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225-047
Originated: Delivered to:4-Dec-25Alaska Oil & Gas Conservation Commiss04Dec25-NR ! "# $$%$ !&$$'($) *%+ ($)*%,- .WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED2P-447 50-103-20468-00-00 203-154 Kuparuk River WL IBC-CBL FINAL FIELD18-Nov-253S-08&50-103-20450-03-00 207-163 Kuparuk River WL Cutter FINAL FIELD 21-Nov-253S-09 50-103-20432-00-00 202-205 Kuparuk River WL Cutter FINAL FIELD 22-Nov-253S-705 50-103-20915-00-00 225-047 Kuparuk River WL TTiX-iPROF-SCMT FINAL FIELD 28-Nov-253S-721 50-103-20911-00-00 225-025 Kuparuk River WL TTiX-iPROF FINAL FIELD 1-Dec-25Transmittal Receipt//////////////////////////////// 0///////////////////////////////// + ! 1 Please return via courier or sign/scan and email a copy to Schlumberger. " 2"3 +45 %TRANSMITTAL DATETRANSMITTAL #1 67 8 " ! - +" 8 # !(3 . 8 ) "3 8 # !9 3 : 8" +8 6 8 8 " 8 # !;" " 3 - 3 " 3 ""+ 3 + < +3!% T41188T11189T41190T41191T411923S-70550-103-20915-00-00225-047Kuparuk RiverWLTTiX-iPROF-SCMTFINAL FIELD28-Nov-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.12.05 11:22:02 -09'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, November 26, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Bob Noble P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL ConocoPhillips Alaska, Inc. 3S-705 KUPARUK RIV UNIT 3S-705 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 11/26/2025 3S-705 50-103-20915-00-00 225-047-0 W SPT 4121 2250470 1500 140 140 140 140 0 0 0 0 INITAL P Bob Noble 10/30/2025 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KUPARUK RIV UNIT 3S-705 Inspection Date: Tubing OA Packer Depth 860 1810 1760 1760IA 45 Min 60 Min Rel Insp Num: Insp Num:mitRCN251103152339 BBL Pumped:0.8 BBL Returned:0.8 Wednesday, November 26, 2025 Page 1 of 1 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ ConocoPhillips Alaska, Inc. Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 14119 feet feet true vertical 4208.00 feet feet Effective Depth measured 14107.56 feet 5,788 feet true vertical 4208.00 feet 4,121 feet Perforation depth Measured depth 6410-13975 feet True Vertical depth 4159-4213 feet Tubing (size, grade, measured and true vertical depth)4.5" 12.6# L80 5929' MD 4,138' TVD Packers and SSSV (type, measured and true vertical depth)HAL TNT 5788' MD 4121' TVD 12. Stimulation or cement squeeze summary: See attached Daily STIM Report Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work:Coyote Oil Pool 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Rodrigo Ruysschaert 7/10/2025 Contact Name:Rodrigo Ruysschaert Contact Email:Rodrigo.Ruysschaert@ConocoPhillips.com Authorized Title:Completions Engineer Contact Phone:907-621-0671 325-375 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) WINJ WAG TBD 9210 6410' MD to 13975' MD 3,151,350 lbs 16/20 WanLi Light weight ceramic proppant, 48,000 lbs of 100 Mesh, and 2500 psi avg treating pressure/3500 psi avg BHG pressure. Representative Daily Average Production or Injection Data Liner 8170.72 4-1/2"14107.56 4208.00 11590 Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure 4790 Intermediate 440.00 7-5/8"5923.00 4140.00 10860 7850 Intermediate 5445.80 7-5/8"5483.00 4061.00 6890 Surface 2690.50 10-3/4"2730.50 2551.00 5210 2470 Conductor 80.00 20"120.00 0.00 Burst Collapse Structural Packer measured true vertical Casing Length Size MD TVD Kuparuk Field / Coyote Oil Pool Plugs measured Junk measured 225-047 3. Address:P.O. Box 100360 Anchorage, AK 99510-0360 50-103-20915-00-00 ADL025528/ADL380106/ADL380107 KRU 3S-705 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 2. Operator Name N 4. Well Class Before Work:5. Permit to Drill Number: p k ft t Fra O g g s O 225 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 12:56 pm, Jul 28, 2025 RBDMS JSB 073125 VTL 7/30/2025 CDW 07/28/2025 DSR-0/10/25 Sales Order# Prepared By: William Martin Derek Osselburn Nanoonk Crew 910163471 Intervals 1-16 Coyote Notice: Although the information contained in this report is based on sound engineering practices, the copyright owner(s) does (do) not accept any responsibility whatsoever, in negligence or otherwise, for any loss or damage arising from the possession or use of the report whether in terms of correctness or otherwise. The application, therefore, by the user of this report or any part thereof, is solely at the user’s own risk. 3S-705 Conoco Phillips Harrison Bay County, AK Post Job Report Stimulation Treatment API: 50-103-20915 Prepared for: Rodrigo Ruysschaert July 4, 2024 Coyote Formation 27# Delta Frac Table of Contents Section Page(s) Executive Summary Actual Design Wellbore Information Interval Summary Fluid System-Proppant Summary Interval 1 Plots Interval 2 Plots Interval 3 Plots Interval 4 Plots Interval 5 Plots Interval 6 Plots Interval 7 Plots Interval 8 Plots Interval 9 Plots Interval 10 Plots Interval 11 Plots Interval 12 Plots Interval 13 Plots Interval 14 Plots Interval 15 Plots Interval 16 Plots Appendix Well Summary Chemical Summary Planned Design Water Straps 7.2.25 Water Straps 7.3.25 Water Straps 7.4.25 Water Analysis 7.1.25 Water Analysis 7.2.25 Water Analysis 7.4.25 Real-Time QC Event Log 7.2 Event Log 7.3 Event Log 7.4 Prejob Break Test Fann 15 Min Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Zone 6 Zone 7 Zone 8 Zone 9 Zone 10 Zone 11 Zone 12 Zone 13 Zone 14 Zone 15 Zone 16 Sand Sieve Analysis 99 - 102 95 - 98 3 4 - 6 7 43 - 46 47 - 50 51 - 54 8 - 23 24 25 - 36 37 - 42 55 - 63 64 - 67 91 - 94 68 - 71 72 - 75 76 - 79 80 - 83 84 - 90 103 - 106 107 108 109 110 - 112 113 114 115 116 117 118 119 120 121 122 123 124 125 126 127 128 129 130 131 132 138 139 140 133 134 135 136 137 Conoco Phillips - 3S-705 TOC 2 718,368 gallons of 27# Delta Frac 90,784 gallons of 27# Linear 3,000 gallons of Seawater 93,580 gallons of 25# Delta Frac 10,607 gallons of 25# Linear 3,153,000 pounds of Wanli 16/20 Ceramic 48,000 pounds of 100M 696,579 gallons of 27# Delta Frac 90,523 gallons of 27# Linear 2,520 gallons of Seawater 95,381 gallons of 25# Delta Frac 11,218 gallons of 25# Linear 3,151,350 pounds of Wanli 16/20 Ceramic 48,000 pounds of 100M Thank you, Halliburton maintains a continuous quality improvement process and appreciates any comments or suggestions that you may have. Halliburton again thanks you for the opportunity to perform service work on this well. We hope to be your solutions provider for future projects. EngineeringExecutiveSummary On July 02, 2024 a stimulation treatment was performed in the Coyote formation on the 3S-705 well in Harrison Bay County, AK. The 3S-705 was a 16 stage Horizontal Sleeve Design. The proposed treatment consisted of: The actual treatment fully completed 16 of 16 stages. 0 stages were skipped, 0 stage screened out and 1 stages were cut short of design. The actual treatment consisted of: A more detailed description of the actual treatment can be found in the attached reports. The following comments were provided to summarize events and changes to the proposed treatment: Fiber cable with pressure transducers at each interval were run on well 3S-705 and 3S-703. This information was monitored in the van while pumping to help with decision making. Interval 06 was cut short due to indications from the fiber data that the fracture was extending out of zone. While seating the dart for interval 12, there was a double pressure spike and the fiber data indicated that the sleeve had initially opened but the dart had slipped. The well was flushed and a second dart was dropped to isolate zone 12. Intervals 1 through 14 were pumped with a 27# base gel and interval 15 and 16 were pumped with a 25# base gel Halliburton is strongly committed to quality control on location. Before and after each job all chemicals, proppants, and fluid volumes are measured to assure the highest level of quality control. Tank fluid analysis, crosslink time, and break tests are performed before each job in order to optimize the performance of the treatment fluids. Pre-job water analysis indicated that the SG of the tank was 1.0 due to snow melt compared to the normal 1.024 that is measured with seawater. Chandler testing in Deadhorse confirmed the fluid system compatibility. MO was diluted at a ratio of 1:2 and pumped on the blender. William Martin Senior Technical Professional Conoco Phillips - 3S-705 Executive Summary 3 CUSTOMERConoco Phillips API BFD (lb/gal)8.54LAT 70.39426745LEASE3S-705SALES ORDEBHST (°F)105LONG-150.1954682FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Actual Clean Actual Clean Calculated Slurry Design Prop Calculated Prop BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinkerSurfactant BufferCatalystInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In-1-2 Seawater Prime Up Pressure Test 5.0 1,000 840 20 200.151-3 Shut-In Shut-In-1-4 27# Linear Arsenal Sleeve Shift 5.0 1,260 355 8 8 1.00 1.00 27.00 2.00 0.151-5 27# Linear DFIT10.0 1,680 839 20 20 1.00 1.00 27.00 2.00 0.151-6 Shut-In Shut-In-1-7 27# Linear Step Rate Test 15.0 8,400 6,393 152 152 1.00 1.00 27.00 2.00 0.151-8 27# Delta Frac Establish Stable Fluid 15.0 8,400 2,335 56 56 0.45 1.00 0.45 1.00 27.00 2.00 0.151-9 27# Delta Frac Pad 20.0 8,915 8,868 211 211 0.45 1.00 0.45 1.00 27.00 2.00 0.151-10 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,487 131 134 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.151-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,604 62 65 5,150 3,008 0.45 1.00 0.45 1.00 27.00 2.00 0.151-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,270 102 119 17,080 16,790 0.45 1.00 0.45 1.00 27.00 2.00 0.151-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,134 98 125 24,780 24,839 0.45 1.00 0.45 1.00 27.00 2.00 0.151-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,457 154 203 45,290 46,787 0.45 1.00 0.45 1.00 27.00 2.00 0.151-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,782 138 189 46,400 48,627 0.45 1.00 0.45 1.00 27.00 2.00 0.151-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,995 95 135 36,000 37,755 0.45 1.00 0.45 1.00 27.00 2.00 0.151-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 4,628 110 136 25,300 24,476 0.45 1.00 0.45 1.00 27.00 2.00 0.151-18 27# Linear Spacer and Dart Drop 20.0 1,470 1,524 36 36 1.00 1.00 27.00 2.00 0.152-1 27# Linear Pre-Pad 20.0 2,100 2,110 50 50 1.00 1.00 27.00 2.00 0.152-2 27# Delta Frac Minifrac - Establish Fluid 20.0 2,100 1,473 35 35 0.45 1.00 0.45 1.00 27.00 2.00 0.152-3 27# Delta Frac Minifrac - Treatment 20.0 7,458 7,475 178 178 0.45 1.00 0.45 1.00 27.00 2.00 0.152-4 27# Linear Displacement 20.0 9,418 9,437 225 225 1.00 1.00 27.00 2.00 0.152-5 Shut-In Shut-In-2-6 27# Delta Frac Establish Stable Fluid 20.0 8,400 2,503 60 60 0.45 1.00 0.45 1.00 27.00 2.00 0.152-7 27# Delta Frac Pad 20.0 8,915 8,914 212 212 0.45 1.00 0.45 1.00 27.00 2.00 0.152-8 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,983 142 146 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.152-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,583 62 66 5,150 4,395 0.45 1.00 0.45 1.00 27.00 2.00 0.152-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,275 102 119 17,080 16,635 0.45 1.00 0.45 1.00 27.00 2.00 0.152-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,120 98 124 24,780 23,970 0.45 1.00 0.45 1.00 27.00 2.00 0.152-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,464 154 202 45,290 45,688 0.45 1.00 0.45 1.00 27.00 2.00 0.152-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,781 138 189 46,400 47,982 0.45 1.00 0.45 1.00 27.00 2.00 0.152-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,994 95 135 36,000 37,765 0.45 1.00 0.45 1.00 27.00 2.00 0.152-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 4,359 104 132 25,300 26,118 0.45 1.00 0.45 1.00 27.00 2.00 0.152-16 27# Linear Spacer and Dart Drop 20.0 1,470 1,321 31 31 1.00 1.00 27.00 2.00 0.153-1 27# Linear Pre-Pad 20.0 2,100 2,165 52 52 1.00 1.00 27.00 2.00 0.153-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,832 44 44 0.45 1.00 0.45 1.00 27.00 2.00 0.153-3 27# Delta Frac Pad 20.0 8,915 8,923 212 212 0.45 1.00 0.45 1.00 27.00 2.00 0.153-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,001 143 146 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.153-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,572 61 66 5,150 4,674 0.45 1.00 0.45 1.00 27.00 2.00 0.153-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,268 102 120 17,080 17,166 0.45 1.00 0.45 1.00 27.00 2.00 0.153-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,142 99 125 24,780 24,638 0.45 1.00 0.45 1.00 27.00 2.00 0.153-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,463 154 203 45,290 46,090 0.45 1.00 0.45 1.00 27.00 2.00 0.153-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,798 138 189 46,400 48,394 0.45 1.00 0.45 1.00 27.00 2.00 0.153-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,999 95 135 36,000 37,809 0.45 1.00 0.45 1.00 27.00 2.00 0.153-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 4,104 98 121 25,300 22,211 0.45 1.00 0.45 1.00 27.00 2.00 0.153-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,427 34 34 1.00 1.00 27.00 2.00 0.154-1 27# Linear Pre-Pad 20.0 2,100 2,135 51 51 1.00 1.00 27.00 2.00 0.154-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 825 20 20 0.45 1.00 0.45 1.00 27.00 2.00 0.154-3 27# Delta Frac Pad 20.0 8,915 8,919 212 212 0.45 1.00 0.45 1.00 27.00 2.00 0.154-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,006 143 146 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.154-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,567 61 66 5,150 4,981 0.45 1.00 0.45 1.00 27.00 2.00 0.154-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,060 97 114 17,080 15,976 0.45 1.00 0.45 1.00 27.00 2.00 0.154-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,354 104 131 24,780 25,358 0.45 1.00 0.45 1.00 27.00 2.00 0.154-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,464 154 203 45,290 45,948 0.45 1.00 0.45 1.00 27.00 2.00 0.154-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,793 138 189 46,400 48,543 0.45 1.00 0.45 1.00 27.00 2.00 0.154-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,991 95 135 36,000 38,115 0.45 1.00 0.45 1.00 27.00 2.00 0.154-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 4,102 98 123 25,300 23,941 0.45 1.00 0.45 1.00 27.00 2.00 0.154-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,361 32 32 1.00 1.00 27.00 2.00 0.155-1 27# Linear Pre-Pad 20.0 2,100 2,102 50 50 1.00 1.00 27.00 2.00 0.155-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,018 24 24 0.45 1.00 0.45 1.00 27.00 2.00 0.155-3 27# Delta Frac Pad 20.0 8,915 8,907 212 212 0.45 1.00 0.45 1.00 27.00 2.00 0.155-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,016 143 146 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.155-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,570 61 66 5,150 4,465 0.45 1.00 0.45 1.00 27.00 2.00 0.155-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,257 101 119 17,080 16,349 0.45 1.00 0.45 1.00 27.00 2.00 0.155-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,125 98 124 24,780 24,377 0.45 1.00 0.45 1.00 27.00 2.00 0.155-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,464 154 203 45,290 46,354 0.45 1.00 0.45 1.00 27.00 2.00 0.155-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,802 138 191 46,400 49,794 0.45 1.00 0.45 1.00 27.00 2.00 0.155-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,967 94 135 36,000 38,276 0.45 1.00 0.45 1.00 27.00 2.00 0.155-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 3,776 90 114 25,300 22,261 0.45 1.00 0.45 1.00 27.00 2.00 0.155-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,633 39 39 1.00 1.00 27.00 2.00 0.156-1 27# Linear Displacement 20.0 7,295 7,815 186 186 1.00 1.00 27.00 2.00 0.156-2 27# Linear DFIT5.0 840 809 19 19 1.00 1.00 27.00 2.00 0.156-3 Shut-In Shut-In-Interval 1Coyote@ 13974.71 - 13978.71 ft 104.2 °FInterval 2Coyote@ 13420.46 - 13424.46 ft 104.2 °FInterval 3Coyote@ 12920.44 - 12924.44 ft 104.2 °FInterval 4Coyote@ 12420.9 - 12424.9 ft 104.2 °FInterval 5Coyote@ 11911.85 - 11915.85 ft 104.2 °FLiquid Additives Dry Additives50-103-20915910163471Conoco Phillips - 3S-705Actual Design4 CUSTOMERConoco Phillips API BFD (lb/gal)8.54LAT 70.39426745LEASE3S-705SALES ORDEBHST (°F)105LONG-150.1954682FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Actual Clean Actual Clean Calculated Slurry Design Prop Calculated Prop BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinkerSurfactant BufferCatalystInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid Additives Dry Additives50-103-209159101634716-4 Shut-In Shut-In-6-5 Seawater Prime Up Pressure Test 5.0 1,000 840 20 200.156-6 Shut-In Shut-In-6-7 27# Linear Pre-Pad 15.0 4,200 5,040 120 120 1.00 1.00 27.00 2.00 0.156-8 27# Delta Frac Establish Stable Fluid 15.0 8,400 3,625 86 86 0.45 1.00 0.45 1.00 27.00 2.00 0.156-9 27# Delta Frac Pad 20.0 8,915 9,000 214 214 0.45 1.00 0.45 1.00 27.00 2.00 0.156-10 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,000 143 146 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.156-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,565 61 67 5,150 5,677 0.45 1.00 0.45 1.00 27.00 2.00 0.156-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,268 102 120 17,080 17,470 0.45 1.00 0.45 1.00 27.00 2.00 0.156-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,099 98 124 24,780 25,032 0.45 1.00 0.45 1.00 27.00 2.00 0.156-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,468 154 204 45,290 47,538 0.45 1.00 0.45 1.00 27.00 2.00 0.156-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 2,900 2,894 69 95 23,200 24,746 0.45 1.00 0.45 1.00 27.00 2.00 0.156-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 2,000 1,929 46 66 18,000 18,821 0.45 1.00 0.45 1.00 27.00 2.00 0.156-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 1,650 3,088 74 87 16,500 12,397 0.45 1.00 0.45 1.00 27.00 2.00 0.156-18 27# Linear Spacer and Dart Drop 20.0 1,470 1,654 39 39 1.00 1.00 27.00 2.00 0.157-1 27# Linear Pre-Pad 20.0 2,100 2,093 50 50 1.00 1.00 27.00 2.00 0.157-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 803 19 19 0.45 1.00 0.45 1.00 27.00 2.00 0.157-3 27# Delta Frac Pad 20.0 8,915 8,932 213 213 0.45 1.00 0.45 1.00 27.00 2.00 0.157-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,053 144 147 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.157-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,567 61 66 5,150 5,014 0.45 1.00 0.45 1.00 27.00 2.00 0.157-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,262 101 120 17,080 17,251 0.45 1.00 0.45 1.00 27.00 2.00 0.157-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,114 98 125 24,780 25,272 0.45 1.00 0.45 1.00 27.00 2.00 0.157-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,465 154 204 45,290 47,441 0.45 1.00 0.45 1.00 27.00 2.00 0.157-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,800 138 190 46,400 48,850 0.45 1.00 0.45 1.00 27.00 2.00 0.157-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 4,001 95 135 36,000 37,451 0.45 1.00 0.45 1.00 27.00 2.00 0.157-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 4,072 97 121 25,300 22,485 0.45 1.00 0.45 1.00 27.00 2.00 0.157-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,454 35 35 1.00 1.00 27.00 2.00 0.158-1 27# Linear Pre-Pad 20.0 2,100 2,094 50 50 1.00 1.00 27.00 2.00 0.158-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,178 28 28 0.45 1.00 0.45 1.00 27.00 2.00 0.158-3 27# Delta Frac Pad 20.0 8,915 6,468 154 154 0.45 1.00 0.45 1.00 27.00 2.00 0.158-4 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,456 35 35 0.45 1.00 0.45 1.00 27.00 2.00 0.158-5 27# Delta Frac Pad 20.0 8,915 8,900 212 212 0.45 1.00 0.45 1.00 27.00 2.00 0.158-6 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,999 143 146 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.158-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,573 61 63 5,150 1,794 0.45 1.00 0.45 1.00 27.00 2.00 0.158-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,270 102 120 17,080 17,568 0.45 1.00 0.45 1.00 27.00 2.00 0.158-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,131 98 126 24,780 25,590 0.45 1.00 0.45 1.00 27.00 2.00 0.158-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,464 154 204 45,290 47,533 0.45 1.00 0.45 1.00 27.00 2.00 0.158-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,870 140 193 46,400 50,073 0.45 1.00 0.45 1.00 27.00 2.00 0.158-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 4,004 95 135 36,000 37,596 0.45 1.00 0.45 1.00 27.00 2.00 0.158-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 3,740 89 109 25,300 18,535 0.45 1.00 0.45 1.00 27.00 2.00 0.158-14 27# Linear Spacer and Dart Drop 20.0 1,470 1,430 34 34 1.00 1.00 27.00 2.00 0.159-1 27# Linear Pre-Pad 20.0 2,100 2,100 50 50 1.00 1.00 27.00 2.00 0.159-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,035 25 25 0.45 1.00 0.45 1.00 27.00 2.00 0.159-3 27# Delta Frac Pad 20.0 8,915 8,973 214 214 0.45 1.00 0.45 1.00 27.00 2.00 0.159-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,004 143 146 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.159-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,628 63 68 5,150 5,308 0.45 1.00 0.45 1.00 27.00 2.00 0.159-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,266 102 120 17,080 16,913 0.45 1.00 0.45 1.00 27.00 2.00 0.159-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,117 98 124 24,780 24,806 0.45 1.00 0.45 1.00 27.00 2.00 0.159-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,458 154 204 45,290 46,870 0.45 1.00 0.45 1.00 27.00 2.00 0.159-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,784 138 189 46,400 48,034 0.45 1.00 0.45 1.00 27.00 2.00 0.159-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,995 95 135 36,000 37,274 0.45 1.00 0.45 1.00 27.00 2.00 0.159-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 3,915 93 114 25,300 19,749 0.45 1.00 0.45 1.00 27.00 2.00 0.159-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,315 31 31 1.00 1.00 27.00 2.00 0.1510-1 27# Linear Pre-Pad 20.0 2,100 2,098 50 50 1.00 1.00 27.00 2.00 0.1510-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 922 22 22 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-3 27# Delta Frac Pad 20.0 8,915 8,931 213 213 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,006 143 146 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,570 61 67 5,150 5,472 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,264 102 119 17,080 16,816 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,132 98 125 24,780 24,610 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,475 154 204 45,290 47,006 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,797 138 189 46,400 47,617 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,995 95 134 36,000 36,571 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 4,086 97 121 25,300 22,371 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,335 32 32 1.00 1.00 27.00 2.00 0.1511-1 27# Linear Pre-Pad 20.0 2,100 2,118 50 50 1.00 1.00 27.00 2.00 0.1511-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 765 18 18 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-3 27# Delta Frac Pad 20.0 8,915 9,303 222 222 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,005 143 146 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,575 61 66 5,150 4,697 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,266 102 120 17,080 16,925 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,126 98 124 24,780 24,617 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,466 154 204 45,290 46,822 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,795 138 189 46,400 48,291 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 4,056 97 137 36,000 37,605 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 3,093 74 96 25,300 20,917 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-12 27# Linear Flush 20.0 6,535 6,606 157 157 1.00 1.00 27.00 2.00 0.15Interval 6Coyote@ 11412.38 - 11416.38 ft 104.2 °FInterval 7Coyote@ 10915.44 - 10919.44 ft 104.2 °FInterval 8Coyote@ 10415.58 - 10419.58 ft 104.1 °FInterval 9Coyote@ 9915.81 - 9919.81 ft 104.1 °FInterval 10Coyote@ 9416.24 - 9420.24 ft 104 °FInterval 11Coyote@ 8909.36 - 8913.36 ft 103.9 °FConoco Phillips - 3S-705Actual Design5 CUSTOMERConoco Phillips API BFD (lb/gal)8.54LAT 70.39426745LEASE3S-705SALES ORDEBHST (°F)105LONG-150.1954682FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Slurry Design Clean Actual Clean Actual Clean Calculated Slurry Design Prop Calculated Prop BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6Treatment Stage Fluid Stage Proppant Conc Rate Volume Volume Volume Volume Total TotalCrosslinkerSurfactant BufferCatalystInterval Number Description Description Description(ppg) (bpm) (gal) (gal) (bbl) (bbl) (lbs) (lbs)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt)Liquid Additives Dry Additives50-103-2091591016347112-1 Shut-In Shut-In-12-2 Seawater Prime Up Pressure Test 5.0 1,000 840 20 200.1512-3 Shut-In Shut-In-12-4 27# Linear Spacer and Dart Drop 15.0 2,100 2,103 50 50 1.00 1.00 27.00 2.00 0.1512-5 27# Delta Frac Establish Stable Fluid 15.0 8,400 1,149 27 27 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-6 27# Delta Frac Pad 20.0 8,915 8,940 213 213 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-7 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 7,316 174 177 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-8 27# Linear Displacement 15.0 5,376 6,325 151 151 1.00 1.00 27.00 2.00 0.1512-9 27# Linear Spacer and Dart Drop 15.0 1,470 2,624 62 62 1.00 1.00 27.00 2.00 0.1512-10 27# Delta Frac Establish Stable Fluid 15.0 8,400 2,350 56 56 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-11 27# Delta Frac Pad 20.0 8,915 8,919 212 212 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-12 27# Delta Frac Conditioning Pad Wanli 16/20 Ceramic 0.50 20.0 6,000 6,013 143 147 3,000 3,214 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,591 62 67 5,150 5,367 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,275 102 121 17,080 17,673 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,132 98 125 24,780 25,405 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,470 154 206 45,290 48,901 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,798 138 191 46,400 49,526 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-18 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,989 95 135 36,000 37,403 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-19 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 3,504 83 100 25,300 15,722 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-20 27# Linear Spacer and Dart Drop 20.0 1,470 1,373 33 33 1.00 1.00 27.00 2.00 0.1513-1 27# Linear Pre-Pad 20.0 2,100 2,101 50 50 1.00 1.00 27.00 2.00 0.1513-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 985 23 23 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-3 27# Delta Frac Pad 20.0 8,915 9,962 237 237 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,006 143 146 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,581 61 67 5,150 5,499 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,275 102 120 17,080 17,138 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,117 98 125 24,780 24,964 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,472 154 204 45,290 47,388 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,795 138 190 46,400 48,669 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 4,000 95 135 36,000 37,739 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 3,870 92 113 25,300 19,914 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,461 35 35 1.00 1.00 27.00 2.00 0.1514-1 27# Linear Pre-Pad 20.0 2,100 2,246 53 53 1.00 1.00 27.00 2.00 0.1514-2 27# Delta Frac Establish Stable Fluid 20.0 2,100 1,454 35 35 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-3 27# Delta Frac Pad 20.0 8,915 8,923 212 212 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-4 27# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,069 145 148 3,000 3,000 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,574 61 66 5,150 4,328 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,259 101 120 17,080 17,257 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,132 98 126 24,780 25,580 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,462 154 204 45,290 47,686 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,796 138 190 46,400 48,694 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,987 95 134 36,000 36,517 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 3,984 95 117 25,300 21,194 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-12 27# Linear Spacer and Dart Drop 20.0 1,470 1,527 36 36 1.00 1.00 27.00 2.00 0.1515-1 25# Linear Pre-Pad 20.0 2,100 2,225 53 53 1.00 1.00 25.00 2.00 0.1515-2 25# Delta Frac Establish Stable Fluid 20.0 2,100 1,506 36 36 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-3 25# Delta Frac Pad 20.0 8,915 8,920 212 212 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-4 25# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 6,034 144 147 3,000 3,000 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-5 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,567 61 66 5,150 4,949 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-6 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,266 102 120 17,080 17,289 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-7 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,134 98 126 24,780 25,504 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-8 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,348 151 201 45,290 47,366 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-9 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,805 138 188 46,400 47,118 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-10 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,981 95 133 36,000 36,002 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-11 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 3,896 93 115 25,300 20,478 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-12 25# Linear Spacer and Dart Drop 20.0 1,470 1,536 37 37 1.00 1.00 25.00 2.00 0.1516-1 25# Linear Pre-Pad 20.0 2,100 2,466 59 59 1.00 1.00 25.00 2.00 0.1516-2 25# Delta Frac Establish Stable Fluid 20.0 2,100 1,012 24 24 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-3 25# Delta Frac Pad 20.0 8,915 9,742 232 232 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-4 25# Delta Frac Conditioning Pad 100M 0.50 20.0 6,000 5,997 143 146 3,000 3,000 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-5 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20.0 2,575 2,581 61 67 5,150 5,220 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-6 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20.0 4,270 4,239 101 119 17,080 16,762 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-7 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20.0 4,130 4,132 98 124 24,780 24,314 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-8 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20.0 6,470 6,472 154 202 45,290 45,290 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-9 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20.0 5,800 5,799 138 189 46,400 48,050 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-10 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20.0 4,000 3,997 95 134 36,000 36,739 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-11 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20.0 2,530 3,953 94 116 25,300 20,822 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-12 25# Linear Flush 20.0 4,937 4,991 119 119 1.00 1.00 25.00 2.00 0.1516-13 Seawater Freeze Protect 5.0 1,470 -0.1516-14 Shut-In Shut-In-917,809 896,221 21,339 24,752 3,201,000 3,213,661Design Total (gal)Actual Total (gal)Design Total (lbs)Calculated Total (lbs)Ticket Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6718,368 696,579 3,153,000 3,165,661 3,151,350(gal) (gal) (gal) (gal) (lbs) (lbs) (lbs)90,784 90,523 48,000 48,000 48,000 Initial Design Material Volume 365.4 913.3 365.4 913.3 24,451.8 1,826.7 137.53,000 2,520 - - - Actual Design Material Volume 356.4 893.7 356.4 893.7 23,916.7 1,787.4 134.4- - - Physical Material Volume Pumped 377 915 400 890 23241 1,780 17493,580 95,381 - - - Physical Material Volume Deviance 6% 2% 12% 0% -3% 0% 29%10,607 11,218** IFS numbers for proppant are taken from software calculations based on multiple variablesMicroMotion Volume Pumped 352 878 351 877 22,329 1,747 ---** Proppant is billed from Weight Ticket volumesMicroMotion Volume Deviance -1% -2% -2% -2% -7% -2% ---Interval 12Coyote@ 8410.32 - 8414.32 ft 103.9 °FInterval 16Coyote@ 6409.86 - 6413.86 ft 103.7 °FInterval 13Coyote@ 7910.63 - 7914.63 ft 103.8 °FInterval 14Coyote@ 7411.38 - 7415.38 ft 103.8 °F25# Linear--Interval 15Coyote@ 6912.05 - 6916.05 ft 103.7 °F-Fluid Type27# Delta Frac27# LinearSeawater25# Delta FracProppant TypeWanli 16/20 Ceramic100M--Conoco Phillips - 3S-705Actual Design6 Conoco Phillips Coyote3S-70550-103-20915*Exceeds 80% of burst pressure*Description OD (in) ID (in) Wt (#) Grade FUF (gal/ft)MD Top (ft)MD Btm (ft) Volume (gal)Tubular Burst Pressure (psi)Tubing4.5 3.958 12.6 L-80 0.6392 0 14,119 9,025 8,430Total14,1199,025ft1.05ft105.0ftft1.05ft104.2ftTop MD (ft)Btm MD (ft)Average TVD (ft)Interval # Formation DescriptorAverage Interval Temperature (F)Ball Drop Time (HH:MM)Ball Hit Time (HH:MM)JSV Drop (bbl)JSV Slow Down (bbl)JSV Hit (bbl)Early (bbl)Surface Seat Pressure (psi)Surface Peak Pressure (psi)Surface Differential (psi)BH Seat Pressure (psi)BH Peak Pressure (psi)BH Differential (psi)Rate at Shift (bpm)Toe13,975 13,979 4,2081Coyote104.2alpha alpha alpha alpha alpha alpha alpha alpha alpha alpha alpha alpha alpha13,420 13,4244,2072Coyote104.211:15:17 AM 11:25:40 AM 1,598 1,782 1,7957.22,247 4,530 2,283 3,416 6,038 2,622 15.112,920 12,9244,2073Coyote104.21:40:48 PM 1:49:48 PM 3,511 3,688 3,69611.62,236 2,893 657 3,453 4,001 548 20.012,421 12,425 4,2094Coyote104.22:52:48 PM 3:01:27 PM 4,967 5,136 5,14511.02,233 5,407 3,174 3,378 6,560 3,182 20.511,912 11,916 4,2115Coyote104.24:03:31 PM 4:11:49 PM 6,397 6,558 6,56810.32,214 4,293 2,079 3,385 5,488 2,103 20.611,412 11,416 4,2136Coyote104.25:14:07 PM 5:22:10 PM 7,829 7,983 7,9957.71,831 4,173 2,342 3,341 5,873 2,532 20.710,915 10,919 4,2127Coyote104.29:42:29 AM 9:50:12 AM 1,375 1,521 1,5329.12,211 4,322 2,111 3,431 5,583 2,152 20.210,416 10,420 4,2058Coyote104.110:54:15 AM 11:01:35 AM 2,811 2,950 2,9609.51,835 2,805 970 3,138 4,262 1,124 20.39,916 9,920 4,1989Coyote104.112:42:08 PM 12:49:04 PM 4,429 4,560 4,5718.91,740 3,409 1,669 3,091 4,815 1,724 20.39,416 9,420 4,19210Coyote104.01:53:32 PM 2:00:08 PM 5,857 5,980 5,9928.31,759 6,885 5,126 3,088 7,663 4,575 20.38,909 8,913 4,18411Coyote103.93:05:15 PM 3:11:27 PM 7,286 7,402 7,4147.61,624 4,645 3,021 3,035 6,171 3,136 20.38,410 8,414 4,17712Coyote103.99:22:51 AM 9:30:48 AM 639 747 7634.01,632 5,640 4,008 3,045 7,117 4,072 15.47,911 7,915 4,17113Coyote103.810:37:15 AM 10:43:04 AM 2,082 2,182 2,1966.41,445 3,668 2,223 2,914 5,178 2,264 15.47,411 7,415 4,16914Coyote103.811:49:59 AM 11:55:22 AM 3,534 3,627 3,6415.81,231 3,515 2,284 2,811 5,050 2,239 15.66,912 6,916 4,16615Coyote103.71:02:22 PM 1:07:21 PM 4,983 5,068 5,0817.21,227 3,556 2,329 2,828 5,225 2,397 15.6Heel6,410 6,414 4,15916Coyote103.72:14:17 PM 2:19:05 PM 6,426 6,504 6,5203.61,223 3,522 2,299 2,810 5,128 2,318 15.6Temp. Gradient (°F/100 ft)BHST (°F)TVD at Bottom PerfMD at Bottom Perf4,21313,979KOPAvg. TVDTotal MD7891011234561213141516Sleeve/Perf DepthSleeves120.4112.8105.2Interval #1Max Pressure (psi)8,500Isolation TypeCemented LinerTreatment TubularsCustomerFormationLeaseAPIDateTemperature DataTemp. Gradient (°F/100 ft)BHST (°F)Directional Data4,1932,23714,119Directional Data2,2377/2/2024KOPTemperature Data8,259 196.67,9397,6147,295Displacement to Top Sleeve/Perf (gal)(BBLS)8,933 212.78,578 204.2189.0181.3173.75,3765,0564,7374,4184,0976,9776,6586,3386,0195,695166.1158.5150.9143.3135.6128.097.6Conoco Phillips - 3S-705 Wellbore Information7 7/2/25 9:01 7/2/25 11:15 133 min alpha bpm alpha psi alpha psi alpha bbl 20.6 bpm 3,403 psi 4,628 psi 19.8 bpm 3,056 psi 2,769 psi 4,178 psi 1,484 hhp 730 psi 0 psi 9 psi 10.58 ppg 5 5 28 % 26 % 21 cP 88.9 F 8.8 DFIT 5.486 bpm 1425 psi 3150 psi 5.521 bpm 1462 psi 3209 psi 2820 psi 0.670 psi/ft 202,282 lbs 3,000 lbs 205,282 lbs 205,282 lbs 48,560 gal 1,156 bbls 9,111 gal 217 bbls 8,868 gal 211 bbls 5,487 gal 131 bbls 31,870 gal 759 bbls 1,524 gal 36 bbls 6,393 gal 152 bbls 2,335 gal 56 bbls 839 gal 20 bbls 355 gal 8 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Pad Percentage Actual Wanli 16/20 Ceramic Pumped: Diagnostic method Average Missile Pressure: Minifrac Max Rate: Open Well Pressure: Initial OA Pressure: Average Missile HHP: Initial BH Pressure (Breakdown): Average BH Pressure: Pumps Ending Stage: Max Proppant Concentration: Pump Time: Conditioning Pad Volume: Proppant Laden Fluid Volume: ISDP: Final Fracture Gradient: Pad Volume: Minifrac Max Surface Pressure: 100M Pumped: Proppant in Formation: 27# Delta Frac Volume: 27# Linear Volume: Minifrac Max DH Pressure: Dart/Ball Early : Average pH: Minifrac Average Rate: The Arsenal Disk burst at 6,919 psi DH and the Alpha Sleeve shifted at 7,982 psi DH. A DFIT was pumped after opening the Alpha Sleeve and pressure decline was monitored for 30 minutes before closure was found to be 2,620 psi. After the Step Rate Test, the frac crew shut down for 4 minutes to trouble shoot the DA's not reading. Interval 01 was pumped to completion. Rate briefly fluctuated once during the stage due to debris going through a pump. DFIT Volume: Arsenal Sleeve Shift Volume: Proppant Summary Minifrac Average Pressure: Minifrac Average DH Pressure: Rodrigo Ruysschaert Average Visc: Average Temp: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max Rate: Max Surface Pressure: Max BH Pressure: Interval Summary 3S-705 - Coyote - Interval 1 Interval Summary Start Date/Time: End Date/Time: Average Surface Pressure: Average Rate: Max OA Pressure: Pumps Starting Stage: Pad Percentage Design Chad Burkett William Martin Total Proppant Pumped* : Fluid Summary (by fluid description) Fluid Summary (by stage description) Establish Stable Fluid Volume: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Step Rate Test Volume: Spacer and Dart Drop Volume: Interval Status: Ryan Knight Derek Osselburn Conoco Phillips - 3S-705 Interval Summary 8 7/2/25 11:15 7/2/25 13:40 146 min 15.1 bpm 4,530 psi 6,038 psi 7 bbl 20.6 bpm 3,103 psi 4,410 psi 20.2 bpm 2,855 psi 2,542 psi 4,003 psi 1,415 hhp 8 psi 9 psi 10.80 ppg 5 5 28 % 27 % 23 cP 89.9 F 8.8 MiniFrac 20.270 bpm 2464 psi 3833 psi 20.37 bpm 3269 psi 4389 psi 2866 psi 0.681 psi/ft 202,553 lbs 3,000 lbs 205,553 lbs 205,553 lbs 57,924 gal 1,379 bbls 12,868 gal 306 bbls 2,110 gal 50 bbls 8,914 gal 212 bbls 5,983 gal 142 bbls 31,576 gal 752 bbls 9,437 gal 225 bbls 1,321 gal 31 bbls 2,503 gal 60 bbls 1,473 gal 35 bbls 7,475 gal 178 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Pad Volume: Minifrac - Treatment Volume: Pre-Pad Volume: Diagnostic method Pad Percentage Design Pad Percentage Actual ISDP: Final Fracture Gradient: Minifrac Max DH Pressure: Proppant in Formation: Fluid Summary (by fluid description) Fluid Summary (by stage description) Minifrac Max Rate: Minifrac Max Surface Pressure: Interval Summary Start Date/Time: End Date/Time: Pump Time: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Initial BH Pressure (Breakdown): Dart/Ball Early : Max Rate: Max Surface Pressure: Max BH Pressure: Average Rate: Average Missile Pressure: Average Surface Pressure: Minifrac Average Rate: 3S-705 - Coyote - Interval 2 Average BH Pressure: Average Missile HHP: Initial OA Pressure: Max OA Pressure: Max Proppant Concentration: Pumps Starting Stage: Pumps Ending Stage: Average Visc: Average Temp: Average pH: Minifrac Average Pressure: Minifrac Average DH Pressure: Proppant Summary Wanli 16/20 Ceramic Pumped: 100M Pumped: Total Proppant Pumped* : 27# Delta Frac Volume: 27# Linear Volume: Conditioning Pad Volume: Proppant Laden Fluid Volume: Displacement Volume: Spacer and Dart Drop Volume: Establish Stable Fluid Volume: Minifrac - Establish Fluid Volume: Interval Status: After shifting the Sleeve for interval 2, a Minifrac was pumped and pressure decline was monitored for 50 minutes. Closure was found to be 2,806 psi using the CoP method. Interval pumped to completion. *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Chad Burkett William Martin Ryan Knight Derek Osselburn Rodrigo Ruysschaert Conoco Phillips - 3S-705 Interval Summary 9 7/2/25 13:40 7/2/25 14:52 72 min 20.0 bpm 2,893 psi 4,001 psi 12 bbl 20.7 bpm 2,993 psi 4,306 psi 20.2 bpm 2,737 psi 2,411 psi 3,913 psi 1,357 hhp 6 psi 7 psi 10.78 ppg 5 5 28 % 27 % 22 cP 89.9 F 8.8 200,982 lbs 3,000 lbs 203,982 lbs 203,982 lbs 48,102 gal 1,145 bbls 3,592 gal 86 bbls 2,165 gal 52 bbls 8,923 gal 212 bbls 6,001 gal 143 bbls 31,346 gal 746 bbls 1,427 gal 34 bbls 1,832 gal 44 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Proppant Summary Spacer and Dart Drop Volume: Wanli 16/20 Ceramic Pumped: Pad Volume: Interval Summary Average Missile HHP: Average Temp: Average Missile Pressure: Average Surface Pressure: Average BH Pressure: Pumps Starting Stage: Pumps Ending Stage: Average pH: 27# Linear Volume: 100M Pumped: Max OA Pressure: Max Proppant Concentration: Pad Percentage Design Pad Percentage Actual Average Visc: Initial OA Pressure: Initial Surface Pressure (Breakdown): Start Date/Time: 3S-705 - Coyote - Interval 3 End Date/Time: Max BH Pressure: Average Rate: Initial BH Pressure (Breakdown): Dart/Ball Early : Max Rate: Max Surface Pressure: Pump Time: Initial Rate (Breakdown): Fluid Summary (by stage description) Pre-Pad Volume: Conditioning Pad Volume: Establish Stable Fluid Volume: 27# Delta Frac Volume: William Martin Ryan Knight Derek Osselburn Interval Status: Interval pumped to completion. *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Total Proppant Pumped* : Proppant in Formation: Fluid Summary (by fluid description) Proppant Laden Fluid Volume: Rodrigo Ruysschaert Chad Burkett Conoco Phillips - 3S-705 Interval Summary 10 7/2/25 14:52 7/2/25 16:03 71 min 20.5 bpm 5,407 psi 6,560 psi 11 bbl 20.9 bpm 3,108 psi 4,272 psi 20.2 bpm 3,016 psi 2,692 psi 4,110 psi 1,495 hhp 6 psi 7 psi 10.90 ppg 5 5 28 % 27 % 22.11 cP 89.89 F 8.79 202,862 lbs 3,000 lbs 205,862 lbs 205,862 lbs 47,081 gal 1,121 bbls 3,496 gal 83 bbls 2,135 gal 51 bbls 8,919 gal 212 bbls 6,006 gal 143 bbls 31,331 gal 746 bbls 1,361 gal 32 bbls 825 gal 20 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Spacer and Dart Drop Volume: Fluid Summary (by fluid description) *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Initial Rate (Breakdown): Proppant in Formation: Max Surface Pressure: 27# Delta Frac Volume: 27# Linear Volume: Average Rate: Average Missile Pressure: Average BH Pressure: Average Missile HHP: Pumps Ending Stage: Pad Percentage Actual Initial BH Pressure (Breakdown): Dart/Ball Early : Max Rate: Interval Summary Start Date/Time: Initial Surface Pressure (Breakdown): End Date/Time: Pump Time: 3S-705 - Coyote - Interval 4 Max BH Pressure: Proppant Summary Wanli 16/20 Ceramic Pumped: Total Proppant Pumped* : Pad Percentage Design Average Surface Pressure: Pumps Starting Stage: 100M Pumped: Max OA Pressure: Max Proppant Concentration: Average Visc: Average Temp: Average pH: Initial OA Pressure: Interval pumped to completion. Derek Osselburn Pre-Pad Volume: Pad Volume: Conditioning Pad Volume: Proppant Laden Fluid Volume: Fluid Summary (by stage description) Establish Stable Fluid Volume: Interval Status: Rodrigo Ruysschaert Chad Burkett William Martin Ryan Knight Conoco Phillips - 3S-705 Interval Summary 11 7/2/25 16:03 7/2/25 17:27 83 min 20.6 bpm 4,293 psi 5,488 psi 10 bbl 20.7 bpm 2,977 psi 4,105 psi 20.3 bpm 2,726 psi 2,437 psi 3,879 psi 1,355 hhp 5 psi 8 psi 10.93 ppg 5 5 28 % 27 % 22 cP 90.11 F 8.8 201,876 lbs 3,000 lbs 204,876 lbs 204,876 lbs 46,902 gal 1,117 bbls 3,735 gal 89 bbls 2,102 gal 50 bbls 8,907 gal 212 bbls 6,016 gal 143 bbls 30,961 gal 737 bbls 1,633 gal 39 bbls 1,018 gal 24 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Average Missile Pressure: Max OA Pressure: Initial BH Pressure (Breakdown): Dart/Ball Early : Average Temp: Initial Surface Pressure (Breakdown): Max Rate: Total Proppant Pumped* : Initial Rate (Breakdown): Pre-Pad Volume: Ryan Knight Interval pumped to completion. Pumps Starting Stage: Pumps Ending Stage: Pump Time: Rodrigo Ruysschaert Chad Burkett Derek Osselburn Establish Stable Fluid Volume: 27# Delta Frac Volume: Spacer and Dart Drop Volume: Proppant Laden Fluid Volume: Interval Status: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Average pH: Pad Percentage Actual 3S-705 - Coyote - Interval 5 Average BH Pressure: Initial OA Pressure: Max Proppant Concentration: Start Date/Time: Pad Percentage Design Average Rate: Proppant in Formation: Pad Volume: William Martin Average Missile HHP: Average Visc: Max Surface Pressure: Interval Summary Proppant Summary Fluid Summary (by fluid description) Fluid Summary (by stage description) Wanli 16/20 Ceramic Pumped: Conditioning Pad Volume: 27# Linear Volume: 100M Pumped: End Date/Time: Max BH Pressure: Average Surface Pressure: Conoco Phillips - 3S-705 Interval Summary 12 7/3/25 8:29 7/3/25 9:42 73 min 20.7 bpm 4,173 psi 5,873 psi 8 bbl 20.6 bpm 2,965 psi 4,176 psi 20.0 bpm 2,888 psi 2,613 psi 3,936 psi 1,414 hhp 685 psi 6 psi 7 psi 10.95 ppg 5 5 33 % 32 % 23.11 cP 89.44 F 8.8 DFIT 5.889 bpm 1221 psi 2972 psi 5.9 bpm 1321 psi 3165 psi 2813 psi 0.668 psi/ft 2790 psi 2771 psi 2752 psi 151,681 lbs 3,000 lbs 154,681 lbs 154,681 lbs 43,936 gal 1,046 bbls 15,318 gal 365 bbls 840 gal 20 bbls 5,040 gal 120 bbls 9,000 gal 214 bbls 6,000 gal 143 bbls 25,311 gal 603 bbls 7,815 gal 186 bbls 1,654 gal 39 bbls 3,625 gal 86 bbls 809 gal 19 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Max Proppant Concentration: Diagnostic method Pad Percentage Actual Max OA Pressure: Spacer and Dart Drop Volume: Proppant Laden Fluid Volume: End Date/Time: Max Surface Pressure: Max BH Pressure: Seawater Volume: Open Well Pressure: Pad Volume: Wanli 16/20 Ceramic Pumped: Pad Percentage Design Average Temp: Total Proppant Pumped* : Final Fracture Gradient: Initial Surface Pressure (Breakdown): Initial BH Pressure (Breakdown): Dart/Ball Early : A DFIT was pumped after opening the sleeve for interval 6 and pressure decline was monitored throughout the night before resuming pumping operations on interval 06 on 7/3/25. Sand stages for 8, 9, and 10ppg were cut in half due to communication with the previous zones as seen in the fiber data. Final 15 min: William Martin Ryan Knight Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Rodrigo Ruysschaert Chad Burkett Initial OA Pressure: Start Date/Time: Minifrac Average DH Pressure: 27# Delta Frac Volume: 27# Linear Volume: Average Surface Pressure: Average BH Pressure: 100M Pumped: Pumps Ending Stage: Pre-Pad Volume: Conditioning Pad Volume: Interval Status: Minifrac Average Rate: Minifrac Max DH Pressure: Average Visc: Proppant in Formation: DFIT Volume: Minifrac Max Surface Pressure: Minifrac Max Rate: 3S-705 - Coyote - Interval 6 Interval Summary Average pH: Minifrac Average Pressure: Final 5 min: Final 10 min: Proppant Summary Fluid Summary (by fluid description) Fluid Summary (by stage description) Establish Stable Fluid Volume: Displacement Volume: Pumps Starting Stage: Max Rate: Average Missile Pressure: ISDP: Average Rate: Pump Time: Initial Rate (Breakdown): Average Missile HHP: Conoco Phillips - 3S-705 Interval Summary 13 7/3/25 9:42 7/3/25 10:54 72 min 20.2 bpm 4,322 psi 5,583 psi 9 bbl 20.7 bpm 2,547 psi 6,807 psi 20.0 bpm 2,416 psi 2,142 psi 3,569 psi 1,185 hhp 8 psi 8 psi 10.78 ppg 5 5 28 % 27 % 22 cP 92.7 F 8.8 203,764 lbs 3,000 lbs 206,764 lbs 206,764 lbs 47,069 gal 1,121 bbls 3,547 gal 84 bbls 2,093 gal 50 bbls 8,932 gal 213 bbls 6,053 gal 144 bbls 31,281 gal 745 bbls 1,454 gal 35 bbls 803 gal 19 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Proppant in Formation: Proppant Laden Fluid Volume: Average Temp: Average Missile HHP: 3S-705 - Coyote - Interval 7 End Date/Time: Conditioning Pad Volume: Total Proppant Pumped* : *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Average BH Pressure: Average Surface Pressure: Wanli 16/20 Ceramic Pumped: Average Visc: Max Surface Pressure: Max BH Pressure: Average Rate: Average Missile Pressure: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max OA Pressure: Dart/Ball Early : Pad Percentage Actual Initial OA Pressure: Pad Percentage Design Pumps Starting Stage: Proppant Summary Pumps Ending Stage: Pre-Pad Volume: Pad Volume: 100M Pumped: Average pH: Max Proppant Concentration: Pump Time: Max Rate: Initial BH Pressure (Breakdown): Start Date/Time: Interval Summary Interval Status: Interval 7 pumped to completion. Fluid Summary (by fluid description) Rodrigo Ruysschaert 27# Delta Frac Volume: Chad Burkett Establish Stable Fluid Volume: William Martin Derek Osselburn Fluid Summary (by stage description) Ryan Knight 27# Linear Volume: Spacer and Dart Drop Volume: Conoco Phillips - 3S-705 Interval Summary 14 7/3/25 10:54 7/3/25 12:42 108 min 20.3 bpm 2,805 psi 4,262 psi 10 bbl 20.7 bpm 2,372 psi 3,676 psi 20.0 bpm 2,303 psi 1,998 psi 3,479 psi 1,131 hhp NA psi NA psi 10.56 ppg 5 5 38 % 35 % 21 cP 95 F 8.73 198,689 lbs 3,000 lbs 201,689 lbs 201,689 lbs 55,053 gal 1,311 bbls 3,524 gal 84 bbls 2,094 gal 50 bbls 15,368 gal 366 bbls 5,999 gal 143 bbls 31,052 gal 739 bbls 1,430 gal 34 bbls 2,634 gal 63 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Max BH Pressure: Dart/Ball Early : End Date/Time: Pump Time: Average Rate: Max Proppant Concentration: Average BH Pressure: Max OA Pressure: Initial OA Pressure: Pumps Ending Stage: After the dart for interval 08 seated, IA pressure increased and the pop-off was activated. It was discovered that the IA pressure transducer was faulty causing erratic pressure readings. The crew shut down for 29 minutes to troubleshoot. The OA pressure cable was used to fix the IA. In order to minimize the time the XL set in the tubing, the decision was made to get back to pumping as soon as possible and the OA gauge was not fixed. The interval was pumped to completion. Proppant Laden Fluid Volume: Average Missile Pressure: Initial Rate (Breakdown): Max Surface Pressure: Average pH: Average Surface Pressure: Pumps Starting Stage: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Spacer and Dart Drop Volume: Proppant in Formation: Average Temp: Max Rate: Initial Surface Pressure (Breakdown): Start Date/Time: Initial BH Pressure (Breakdown): Fluid Summary (by fluid description) Pad Volume: Average Visc: Total Proppant Pumped* : 27# Linear Volume: Conditioning Pad Volume: Average Missile HHP: Fluid Summary (by stage description) Pad Percentage Actual Pad Percentage Design Interval Summary 3S-705 - Coyote - Interval 8 Pre-Pad Volume: Wanli 16/20 Ceramic Pumped: 100M Pumped: Proppant Summary Establish Stable Fluid Volume: 27# Delta Frac Volume: Interval Status: William Martin Chad Burkett Ryan Knight Derek Osselburn Rodrigo Ruysschaert Conoco Phillips - 3S-705 Interval Summary 15 7/3/25 12:42 7/3/25 13:53 71 min 20.3 bpm 3,409 psi 4,815 psi 9 bbl 20.7 bpm 2,491 psi 3,732 psi 20.0 bpm 2,379 psi 2,030 psi 3,479 psi 1,166 hhp NA psi NA psi 10.62 ppg 5 5 28 % 27 % 22 cP 93.2 F 8.78 198,954 lbs 3,000 lbs 201,954 lbs 201,954 lbs 47,175 gal 1,123 bbls 3,415 gal 81 bbls 2,100 gal 50 bbls 8,973 gal 214 bbls 6,004 gal 143 bbls 31,163 gal 742 bbls 1,315 gal 31 bbls 1,035 gal 25 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Interval Status: Pad Volume: Average Missile HHP: Initial OA Pressure: Average Rate: 100M Pumped: Pad Percentage Actual Proppant in Formation: Average BH Pressure: Interval pumped to completion. Max OA Pressure: Derek Osselburn Interval Summary Dart/Ball Early : Average Visc: Pad Percentage Design Total Proppant Pumped* : Max Surface Pressure: Max BH Pressure: Initial Rate (Breakdown): Max Rate: Pumps Ending Stage: Initial Surface Pressure (Breakdown): Proppant Summary Wanli 16/20 Ceramic Pumped: Average Missile Pressure: Pre-Pad Volume: Establish Stable Fluid Volume: Spacer and Dart Drop Volume: 27# Delta Frac Volume: 27# Linear Volume: 3S-705 - Coyote - Interval 9 Conditioning Pad Volume: Proppant Laden Fluid Volume: Initial BH Pressure (Breakdown): Fluid Summary (by stage description) Average pH: Fluid Summary (by fluid description) Start Date/Time: End Date/Time: Pump Time: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. William Martin Ryan Knight Average Temp: Max Proppant Concentration: Pumps Starting Stage: Average Surface Pressure: Rodrigo Ruysschaert Chad Burkett Conoco Phillips - 3S-705 Interval Summary 16 7/3/25 13:53 7/3/25 15:05 72 min 20.3 bpm 6,885 psi 7,663 psi 8 bbl 20.7 bpm 3,104 psi 3,362 psi 20.0 bpm 2,342 psi 1,986 psi 3,444 psi 1,146 hhp NA psi NA psi 10.66 ppg 5 5 28 % 27 % 22 cP 93.4 F 8.76 200,463 lbs 3,000 lbs 203,463 lbs 203,463 lbs 47,178 gal 1,123 bbls 3,433 gal 82 bbls 2,098 gal 50 bbls 8,931 gal 213 bbls 6,006 gal 143 bbls 31,319 gal 746 bbls 1,335 gal 32 bbls 922 gal 22 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Fluid Summary (by stage description) William Martin Initial Rate (Breakdown): Interval Status: Average Surface Pressure: Establish Stable Fluid Volume: Spacer and Dart Drop Volume: Total Proppant Pumped* : Proppant in Formation: Fluid Summary (by fluid description) Max Surface Pressure: Max BH Pressure: Pumps Ending Stage: Max Rate: Initial Surface Pressure (Breakdown): Proppant Summary Average Missile Pressure: Average Rate: 27# Linear Volume: Average Missile HHP: Wanli 16/20 Ceramic Pumped: Initial OA Pressure: Max Proppant Concentration: Proppant Laden Fluid Volume: 100M Pumped: Pre-Pad Volume: Pad Volume: Conditioning Pad Volume: Average Temp: After the dart for interval 10 landed, a pump kicked out due to pressure. The sleeve shifted, rate was regained and the interval pumped to completion. Interval Summary Pump Time: Start Date/Time: 3S-705 - Coyote - Interval 10 End Date/Time: Initial BH Pressure (Breakdown): Pad Percentage Actual Pumps Starting Stage: Dart/Ball Early : 27# Delta Frac Volume: Average Visc: Pad Percentage Design Max OA Pressure: Average pH: Average BH Pressure: Ryan Knight Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Rodrigo Ruysschaert Chad Burkett Conoco Phillips - 3S-705 Interval Summary 17 7/3/25 15:05 7/3/25 16:22 77 min 20.3 bpm 4,645 psi 6,171 psi 8 bbl 20.7 bpm 2,212 psi 3,515 psi 20.0 bpm 2,135 psi 1,801 psi 3,297 psi 1,046 hhp NA psi NA psi 10.59 ppg 5 5 28 % 28 % 22 cP 95.2 F 8.76 2729 psi 0.652 psi/ft 2708 psi 2697 psi 2686 psi 199,874 lbs 3,000 lbs 202,874 lbs 202,874 lbs 46,450 gal 1,106 bbls 8,724 gal 208 bbls 2,118 gal 50 bbls 9,303 gal 222 bbls 6,005 gal 143 bbls 30,377 gal 723 bbls 6,606 gal 157 bbls 765 gal 18 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Initial Surface Pressure (Breakdown): Max Surface Pressure: Average Missile Pressure: Initial Rate (Breakdown): Start Date/Time: Interval Status: Average Missile HHP: 27# Linear Volume: Pumps Starting Stage: ISDP: 100M Pumped: Conditioning Pad Volume: Proppant Laden Fluid Volume: Final Fracture Gradient: Final 10 min: William Martin Interval Summary Proppant Summary Fluid Summary (by fluid description) Total Proppant Pumped* : Proppant in Formation: Pumps Ending Stage: Pump Time: Initial BH Pressure (Breakdown): Dart/Ball Early : 27# Delta Frac Volume: 3S-705 - Coyote - Interval 11 End Date/Time: Max Proppant Concentration: Average Visc: Average Temp: Final 5 min: Final 15 min: Max Rate: Wanli 16/20 Ceramic Pumped: Average pH: Pad Percentage Actual Initial OA Pressure: Flush Volume: Ryan Knight Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Pad Percentage Design Average Surface Pressure: Max OA Pressure: Max BH Pressure: Average Rate: Average BH Pressure: Fluid Summary (by stage description) Establish Stable Fluid Volume: Pre-Pad Volume: Pad Volume: Interval pumped to completion. Rodrigo Ruysschaert Chad Burkett Conoco Phillips - 3S-705 Interval Summary 18 7/4/25 8:20 7/4/25 10:37 137 min 15.4 bpm 5,640 psi 7,117 psi 4 bbl 20.7 bpm 3,357 psi 4,601 psi 19.9 bpm 2,210 psi 1,923 psi 3,306 psi 1,078 hhp 456 psi NA psi NA psi 10.54 ppg 5 5 44 % 44 % 22 cP 92.6 F 8.73 2822 psi 0.676 psi/ft 203,211 lbs 3,000 lbs 206,211 lbs 206,211 lbs 65,446 gal 1,558 bbls 12,425 gal 296 bbls 840 gal 20 bbls 17,859 gal 425 bbls 13,329 gal 317 bbls 30,759 gal 732 bbls 6,325 gal 151 bbls 6,100 gal 145 bbls 3,499 gal 83 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Total Proppant Pumped* : 100M Pumped: Wanli 16/20 Ceramic Pumped: Pumps Ending Stage: Pad Percentage Design Seawater Volume: Proppant in Formation: Proppant Laden Fluid Volume: Displacement Volume: Average Temp: Interval Status: Pad Volume: Conditioning Pad Volume: Spacer and Dart Drop Volume: Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Rodrigo Ruysschaert Max Surface Pressure: ISDP: Establish Stable Fluid Volume: 27# Linear Volume: Proppant Summary Fluid Summary (by fluid description) 27# Delta Frac Volume: Fluid Summary (by stage description) Start Date/Time: Average Rate: Average Missile Pressure: Final Fracture Gradient: Pad Percentage Actual Initial Rate (Breakdown): Average BH Pressure: After the dart seated and sleeve shifted, another pressure spike was observed followed by higher treating pressure. It is presumed that the sleeve shifted but shortly afterwards the dart slipped and seated on the previous zone. This theory was confirmed with fiber data indicating that the fluid was going into interval 11. OSR made the decision to flush the well with linear gel and drop another dart for interval 12. Interval 12 was pumped to completion William Martin Average Surface Pressure: Dart/Ball Early : Max BH Pressure: Average Visc: Ryan Knight Chad Burkett Max OA Pressure: Average pH: Max Rate: Open Well Pressure: Initial OA Pressure: End Date/Time: Pumps Starting Stage: Max Proppant Concentration: Pump Time: 3S-705 - Coyote - Interval 12 Interval Summary Initial BH Pressure (Breakdown): Average Missile HHP: Initial Surface Pressure (Breakdown): Conoco Phillips - 3S-705 Interval Summary 19 7/4/25 10:37 7/4/25 11:49 73 min 15.4 bpm 3,668 psi 5,178 psi 6 bbl 20.8 bpm 2,029 psi 3,372 psi 20.0 bpm 1,940 psi 1,635 psi 3,065 psi 951 hhp NA psi NA psi 10.86 ppg 5 5 28 % 29 % 22 cP 95.8 F 8.7 201,311 lbs 3,000 lbs 204,311 lbs 204,311 lbs 48,063 gal 1,144 bbls 3,562 gal 85 bbls 2,101 gal 50 bbls 9,962 gal 237 bbls 6,006 gal 143 bbls 31,110 gal 741 bbls 1,461 gal 35 bbls 985 gal 23 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Establish Stable Fluid Volume: Interval Status: 100M Pumped: Pre-Pad Volume: Proppant in Formation: 27# Delta Frac Volume: Max Rate: Wanli 16/20 Ceramic Pumped: Average BH Pressure: Average Temp: Pad Volume: Average Surface Pressure: Start Date/Time: Pumps Starting Stage: Average Rate: Proppant Summary Dart/Ball Early : Max OA Pressure: Pumps Ending Stage: Average pH: Initial OA Pressure: Max BH Pressure: Initial BH Pressure (Breakdown): Average Missile Pressure: Pump Time: 3S-705 - Coyote - Interval 13 Rodrigo Ruysschaert Chad Burkett Total Proppant Pumped* : Average Visc: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Spacer and Dart Drop Volume: Pad Percentage Design Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): Max Surface Pressure: Max Proppant Concentration: Average Missile HHP: Interval Summary End Date/Time: Conditioning Pad Volume: Pad Percentage Actual Proppant Laden Fluid Volume: Fluid Summary (by stage description) Interval pumped to completion. William Martin Ryan Knight Derek Osselburn Fluid Summary (by fluid description) 27# Linear Volume: Conoco Phillips - 3S-705 Interval Summary 20 7/4/25 11:49 7/4/25 13:02 72 min 15.6 bpm 3,515 psi 5,050 psi 6 bbl 20.8 bpm 1,928 psi 3,168 psi 20.1 bpm 1,893 psi 1,581 psi 3,023 psi 931 hhp NA psi NA psi 10.81 ppg 5 5 28 % 27 % 22 cP 95.3 F 8.72 201,256 lbs 3,000 lbs 204,256 lbs 204,256 lbs 47,640 gal 1,134 bbls 3,773 gal 90 bbls 2,246 gal 53 bbls 8,923 gal 212 bbls 6,069 gal 145 bbls 31,194 gal 743 bbls 1,527 gal 36 bbls 1,454 gal 35 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Average Rate: Average Missile Pressure: Pumps Ending Stage: Interval Status: Initial BH Pressure (Breakdown): Establish Stable Fluid Volume: Average Surface Pressure: Pad Percentage Design Pad Percentage Actual Average Visc: Initial OA Pressure: Average Missile HHP: Pumps Starting Stage: Average BH Pressure: Fluid Summary (by stage description) Ryan Knight Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Proppant Summary End Date/Time: Average Temp: Dart/Ball Early : Max Surface Pressure: Max OA Pressure: Max Proppant Concentration: Initial Rate (Breakdown): Chad Burkett Interval pumped to completion. 100M Pumped: Pump Time: Average pH: Wanli 16/20 Ceramic Pumped: 3S-705 - Coyote - Interval 14 Max Rate: Max BH Pressure: William Martin Rodrigo Ruysschaert Interval Summary Start Date/Time: Initial Surface Pressure (Breakdown): Total Proppant Pumped* : 27# Linear Volume: Proppant Laden Fluid Volume: Pad Volume: Proppant in Formation: Fluid Summary (by fluid description) 27# Delta Frac Volume: Pre-Pad Volume: Spacer and Dart Drop Volume: Conditioning Pad Volume: Conoco Phillips - 3S-705 Interval Summary 21 7/4/25 13:02 7/4/25 14:14 72 min 15.6 bpm 3,556 psi 5,225 psi 7 bbl 20.8 bpm 1,924 psi 3,420 psi 20.1 bpm 1,815 psi 1,489 psi 2,974 psi 895 hhp NA psi NA psi 10.60 ppg 5 5 28 % 27 % 20 cP 93.7 F 8.72 198,706 lbs 3,000 lbs 201,706 lbs 201,706 lbs 47,457 gal 1,130 bbls 3,761 gal 90 bbls 2,225 gal 53 bbls 8,920 gal 212 bbls 6,034 gal 144 bbls 30,997 gal 738 bbls 1,506 gal 36 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: Average Rate: Start Date/Time: Pre-Pad Volume: Rodrigo Ruysschaert Chad Burkett Pumps Starting Stage: *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number. Establish Stable Fluid Volume: 100M Pumped: Proppant Laden Fluid Volume: Initial OA Pressure: Max OA Pressure: Max Proppant Concentration: Average Visc: Average pH: Initial Rate (Breakdown): Average Surface Pressure: Wanli 16/20 Ceramic Pumped: Proppant Summary Total Proppant Pumped* : Proppant in Formation: Average Temp: Max Surface Pressure: Fluid Summary (by stage description) William Martin Ryan Knight Derek Osselburn Pad Volume: Conditioning Pad Volume: Fluid Summary (by fluid description) Interval Status: Average Missile HHP: Initial BH Pressure (Breakdown): Average BH Pressure: Pump Time: Base gel loading for the delta system was lowered from 27# to 25#. Interval pumped to completion. 25# Delta Frac Volume: 25# Linear Volume: Dart/Ball Early : 3S-705 - Coyote - Interval 15 Interval Summary Average Missile Pressure: Pad Percentage Actual Pumps Ending Stage: Pad Percentage Design End Date/Time: Max BH Pressure: Max Rate: Initial Surface Pressure (Breakdown): Conoco Phillips - 3S-705 Interval Summary 22 7/4/25 14:14 7/4/25 15:31 77 min 15.6 bpm 3,522 psi 5,128 psi 4 bbl 20.7 bpm 1,786 psi 3,060 psi 20.2 bpm 1,586 psi 1,283 psi 2,838 psi 784 hhp NA psi NA psi 10.56 ppg 5 5 28 % 28 % 19 cP 95.3 F 8.73 2684 psi 0.645 psi/ft 2653 psi 2637 psi 2630 psi 197,197 lbs 3,000 lbs 200,197 lbs 200,197 lbs 47,924 gal 1,141 bbls 7,457 gal 178 bbls 2,466 gal 59 bbls 9,742 gal 232 bbls 5,997 gal 143 bbls 31,173 gal 742 bbls 1,012 gal 24 bbls Completed Comments: Engineer: Treater: Supervisor: Customer Engineer: Customer Rep: 25# Delta Frac Volume: Fluid Summary (by stage description) Total Proppant Pumped* : Interval Status: Interval pumped to completion. Max Rate: 3S-705 - Coyote - Interval 16 Final Fracture Gradient: Final 15 min: Average Missile Pressure: Final 5 min: Proppant Summary 100M Pumped: 25# Linear Volume: Pre-Pad Volume: Pad Volume: Average Surface Pressure: Fluid Summary (by fluid description) Wanli 16/20 Ceramic Pumped: Initial Rate (Breakdown): Initial Surface Pressure (Breakdown): ISDP: Pumps Ending Stage: Max Surface Pressure: Conditioning Pad Volume: Proppant Laden Fluid Volume: Interval Summary Pad Percentage Actual Initial OA Pressure: Initial BH Pressure (Breakdown): Dart/Ball Early : Average Missile HHP: Max OA Pressure: Establish Stable Fluid Volume: Max Proppant Concentration: Pad Percentage Design Average Visc: Pump Time: Average Temp: Proppant in Formation: Average pH: Pumps Starting Stage: Start Date/Time: Average BH Pressure: Average Rate: End Date/Time: Max BH Pressure: Final 10 min: William Martin Ryan Knight Derek Osselburn *Values for proppant are taken from software calculations based on multiple variables. Proppant is billed off of weight ticket volumes and may vary slightly from this number.Rodrigo Ruysschaert Chad Burkett Conoco Phillips - 3S-705 Interval Summary 23 CustomerFormationLeaseAPIDateWell SummaryWanli 16/20 Ceramic 100M Total ProppantBH Pressure Rate Visc Temp pHBH PressureRate bbl gal bbl gal bbl gal bbl gal bbl gal bbl lbs lbs lbs14178 19.8 21 88.9 8.8 4628 20.6 1,156 9,111 217 840 20 58,511 1,393 202,282 3,000 205,282 24003 20.2 23 90 8.8 4410 20.6 1,379 12,868 306 70,792 1,686 202,553 3,000 205,553 33913 20.2 22 90 8.8 4306 20.7 1,145 3,592 86 51,694 1,231 200,982 3,000 203,982 44110 20.2 22 90 8.8 4272 20.9 1,121 3,496 83 50,577 1,204 202,862 3,000 205,862 53879 20.3 22 90 8.8 4105 20.7 1,117 3,735 89 50,637 1,206 201,876 3,000 204,876 63936 20.0 23 89 8.8 4176 20.6 1,046 15,318 365 840 20 60,094 1,431 151,681 3,000 154,681 73569 20.0 22 93 8.8 6807 20.7 1,121 3,547 84 50,616 1,205 203,764 3,000 206,764 83479 20.0 21 95 8.7 3676 20.7 1,311 3,524 84 58,577 1,395 198,689 3,000 201,689 93479 20.0 22 93 8.8 3732 20.7 1,123 3,415 81 50,590 1,205 198,954 3,000 201,954 103444 20.0 22 93 8.8 3362 20.7 1,123 3,433 82 50,611 1,205 200,463 3,000 203,463 113297 20.0 22 95 8.8 3515 20.7 1,106 8,724 208 55,174 1,314 199,874 3,000 202,874 123306 19.9 22 93 8.7 4601 20.7 1,558 12,425 296 840 20 78,711 1,874 203,211 3,000 206,211 133065 20.0 22 96 8.7 3372 20.8 1,144 3,562 85 51,625 1,229 201,311 3,000 204,311 143023 20.1 22 95 8.7 3168 20.8 1,134 3,773 90 51,413 1,224 201,256 3,000 204,256 152974 20.1 20 94 8.7 3420 20.847,457 1,130 3,761 90 51,218 1,219 198,706 3,000 201,706 162838 20.2 19 95 8.7 3060 20.747,924 1,141 7,457 178 55,381 1,319 197,197 3,000 200,197 Minimum1046 3415 81 840 20 47457 1130 3761 90 50577 1204 151681 3000 154681 Average1185 6466 154 840 20 47691 1135 5609 134 56014 1334 197854 3000 200854 Maximum1558 15318 365 840 20 47924 1141 7457 178 78711 1874 203764 3000 206764 Wanli 16/20 Ceramic 100M Total ProppantPressure Rate Visc Temp pH Pressure Rate bbl gal bbl gal bbl gal bbl gal bbl gal bbl lbs lbs TotalPlanned17,104 90,784 2,162 3,000 71 93,580 2,228 10,607 253 917,809 21,853 3,153,000 48,000 3,201,000Recorded3716 20.1 22 92 8.78 6807 20.9 16,585 90,523 2,155 2,520 60 95,381 2,271 11,218 267 896,221 21,339 3,165,661 48,000 3,213,661Weight Tickets3,151,350 48,000 3,199,350** Proppant is billed from Weight Ticket volumesJuly 02, 202450-103-209153S-705CoyoteConoco Phillips IntervalAverage MaxSeawaterAverage MaxSeawater 25# Linear27# Delta Frac 27# Linear27# Delta Frac 27# Linear** IFS numbers for proppant are taken from software calculations based on Total FluidFluidsProppantsFluidsProppants25# Delta Frac Total Fluid25# Delta Frac25# LinearConoco Phillips - 3S-705 Fluid System-Proppant Summary24 <-Paste Interval 1 Plots HereePRV Test - 7.2.257/2/202507:5407:5607:5808:007/2/202508:02Time01000200030004000500060007000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)8765Global Event Log5678Intersection IntersectionePRV - Primary Tubing ePRV - Primary IAePRV - Secondary Tubing ePRV - Secondary IA07:54:48 07:57:0207:58:52 08:00:20TP TP275.1 309.61116 789.8TPP TPP261.4 150.71169 275.8IGKP IGKP1500 15001500 1500Conoco Phillips - 3S-705 Interval 1 Plots25 <-Paste Interval 1 Plots HerePressure Test - 7.2.257/2/202508:0608:0808:1008:1208:147/2/202508:16Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)21211109Global Event Log9101112Intersection IntersectionPressure Test - Global Pressure Test - LocalsPressure Test - Max Pressure Test - Pass08:05:01 08:05:0708:07:30 08:12:35TP TP611.7 619.39479 9417TPP TPP640.9 651.39560 9481IGKP IGKP25.00 95009500 9500PKP PKP500.4 576.99500 9500Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 1 Plots26 <-Paste Interval 1 Plots HereBlender Chemical Plot - Bucket Test 7.2.257/2/202507:0007:1007:2007:3007:4007:507/2/202508:00Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABAConoco Phillips - 3S-705 Interval 1 Plots27 <-Paste Interval 1 Plots HereADP Chemical Plots - Bucket Test 7.2.257/2/202507:11:3007:12:0007:12:3007:13:0007:13:3007:14:0007:14:307/2/202507:15:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)ABConoco Phillips - 3S-705 Interval 1 Plots28 Treatment Plot - Arsenal Burst & Alpha Sleeve7/2/202509:0109:0209:037/2/202509:04Time010002000300040005000600070008000900010000A0102030405060708090100B012345678910C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD151413Global Event Log131415Intersection IntersectionOpen Well Arsenal Burst DiskAlpha Sleeve Shift09:01:57 09:02:5709:04:09TP TP730.1 50145981GBP GBP2481 69197928Conoco Phillips - 3S-705 Interval 1 Plots29 Treatment Plot - Interval 01 DFIT7/2/202509:0509:1009:157/2/202509:20Time010002000300040005000600070008000900010000A0102030405060708090100B012345678910C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD651716Global Event Log1617Intersection IntersectionStart DFIT ISIP09:05:01 09:08:41TP TP1416 1090GBP GBP3200 2820Conoco Phillips - 3S-705 Interval 1 Plots30 Halliburton Pumping Diagnostic Analysis ToolkitMinifrac - G Function0.51.01.52.02.53.0G(Time)240025002600270028002900A0100200300400D0100200300400E (0.0023, 0) (m = 139.97) (2.4817, 347) (Y = 0) Gauge BH Pres (psi)Smoothed Pressure (psi)Smoothed Adaptive 1st Derivative (psi)Smoothed Adaptive G*dP/dG (psi)AADE11ClosureTime2.29GBP2569SP2569DP250.7FE54.65Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 1 Plots31 Treatment Plot - Interval 01 Step Rate Test7/2/202509:4009:4509:507/2/202509:55Time0200040006000800010000A020406080100B0246810C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD733323130292827262524232221201918Global Event Log18192021222324252627282930313233Intersection IntersectionOpen Well Step 1Step 2 Step 3Step 4 Step 5Step 6 Step 7Step 8 Step 9Step 10 Step 11Step 12 Step 13Step 14 Step 15\09:38:22 09:39:4609:41:13 09:42:2409:43:38 09:44:5309:46:05 09:47:1909:48:30 09:49:4109:50:51 09:52:0509:53:16 09:54:2709:55:41 09:57:14TP TP544.8 12151298 13181358 14251503 15721621 16721713 17581808 18671924 1963SR SR0.000 1.0742.107 2.9424.019 5.0046.072 7.0777.952 9.03010.00 10.9911.96 12.9613.97 14.80GBP GBP2267 30413041 30593080 31293196 32433290 33453401 34473478 35063550 3564Conoco Phillips - 3S-705 Interval 1 Plots32 Treatment Plot - Interval 017/2/202510:0010:2010:4011:007/2/202511:20Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321181716151413121110982Conoco Phillips - 3S-705 Interval 1 Plots33 Blender Chemical Plot - Interval 017/2/202509:4010:0010:2010:407/2/202511:00Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA211817161514131211109872Conoco Phillips - 3S-705 Interval 1 Plots34 ADP Chemical Plots - Interval 017/2/202509:4010:0010:2010:4011:0011:207/2/202511:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB543211817161514131211109872Conoco Phillips - 3S-705 Interval 1 Plots35 Net Pressure Plot - Interval 017892345678910Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2620 psi 0 Time = 07/02/25 09:55:19 1Time-169.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 1 Plots36 <-Paste Interval 2 Plots HereTreatment Plot - Interval 02 MiniFrac7/2/202511:2011:3011:4011:5012:0012:107/2/202512:20Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD54321182Conoco Phillips - 3S-705 Interval 2 Plots37 <-Paste Interval 2 Plots HereHalliburton Pumping Diagnostic Analysis ToolkitMinifrac - G Function0.51.01.52.02.53.0G(Time)2700280029003000310032003300A0102030405060D0102030405060708090100E (0.0023, 0) (m = 23.113) (2.4541, 56.67) (Y = 0) (Y = 69.77) Gauge BH Pres (psi)Smoothed Pressure (psi)Smoothed Adaptive 1st Derivative (psi)Smoothed Adaptive G*dP/dG (psi)AADE11ClosureTime2.50GBP2763SP2764DP98.69FE56.82Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 2 Plots38 <-Paste Interval 2 Plots HereTreatment Plot - Interval 027/2/202512:4013:0013:207/2/202513:40Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211615141312111098763Conoco Phillips - 3S-705 Interval 2 Plots39 <-Paste Interval 2 Plots HereBlender Chemical Plot - Interval 027/2/202512:3012:4012:5013:0013:1013:2013:307/2/202513:40Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA3211615141312111098763Conoco Phillips - 3S-705 Interval 2 Plots40 ADP Chemical Plots - Interval 027/2/202512:3012:4012:5013:0013:1013:2013:3013:407/2/202513:50Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB3211615141312111098763Conoco Phillips - 3S-705 Interval 2 Plots41 Net Pressure Plot - Interval 0292345678910Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2620 psi 0 Time = 07/02/25 12:20:19 1Time-314.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 2 Plots42 <-Paste Interval 3 Plots HereTreatment Plot - Interval 037/2/202513:4014:0014:2014:407/2/202515:00Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211211109876543211643Conoco Phillips - 3S-705 Interval 3 Plots43 <-Paste Interval 3 Plots HereBlender Chemical Plot - Interval 037/2/202513:4013:5014:0014:1014:2014:3014:407/2/202514:50Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA3211211109876543211643Conoco Phillips - 3S-705 Interval 3 Plots44 <-Paste Interval 3 Plots HereADP Chemical Plots - Interval 037/2/202513:4013:5014:0014:1014:2014:3014:407/2/202514:50Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB3211211109876543211643Conoco Phillips - 3S-705 Interval 3 Plots45 <-Paste Interval 3 Plots HereNet Pressure Plot - Interval 0356789234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2806 psi 0 Time = 07/02/25 13:45:19 1Time-399.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 3 Plots46 <-Paste Interval 4 Plots HereTreatment Plot - Interval 047/2/202515:0015:2015:407/2/202516:00Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211211109876543211254Conoco Phillips - 3S-705 Interval 4 Plots47 <-Paste Interval 4 Plots HereBlender Chemical Plot - Interval 047/2/202515:0015:1015:2015:3015:4015:507/2/202516:00Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA3211211109876543211254Conoco Phillips - 3S-705 Interval 4 Plots48 <-Paste Interval 4 Plots HereADP Chemical Plots - Interval 047/2/202514:5015:0015:1015:2015:3015:4015:507/2/202516:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB211211109876543211254Conoco Phillips - 3S-705 Interval 4 Plots49 <-Paste Interval 4 Plots HereNet Pressure Plot - Interval 04345678923456710Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2806 psi 0 Time = 07/02/25 14:59:19 1Time-473.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 4 Plots50 <-Paste Interval 5 Plots HereTreatment Plot - Interval 057/2/202516:2016:4017:007/2/202517:20Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD2112111098765432165Conoco Phillips - 3S-705 Interval 5 Plots51 <-Paste Interval 5 Plots HereBlender Chemical Plot - Interval 057/2/202516:1016:2016:3016:4016:5017:0017:107/2/202517:20Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA211211109876543211265Conoco Phillips - 3S-705 Interval 5 Plots52 <-Paste Interval 5 Plots HereADP Chemical Plots - Interval 057/2/202516:1016:2016:3016:4016:5017:0017:107/2/202517:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB211211109876543211265Conoco Phillips - 3S-705 Interval 5 Plots53 <-Paste Interval 5 Plots HereNet Pressure Plot - Interval 056789234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2806 psi 0 Time = 07/02/25 16:05:19 1Time-539.05NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 5 Plots54 <-Paste Interval 6 Plots HereePRV Test - 7.3.257/3/202507:2407:2607:2807:3007:327/3/202507:34Time01000200030004000500060007000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)7654Global Event Log4567Intersection IntersectionePRV - Primary Tubing ePRV - Primary IAePRV - Secondary Tubing ePRV - Secondary IA07:25:56 07:27:4507:31:50 07:33:56TP TP1052 12991585 522.4TPP TPP1065 13611632 803.0IGKP IGKP1500 15001800 1800Conoco Phillips - 3S-705 Interval 6 Plots55 <-Paste Interval 6 Plots HerePressure Test - 7.3.257/3/202507:3607:3807:4007:427/3/202507:44Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)111098Global Event Log891011Intersection IntersectionPressure Test - Global Pressure Test - LocalsPressure Test - Max Pressure Test - Pass07:36:17 07:36:2207:38:40 07:43:43TP TP88.78 88.749544 9529TPP TPP86.73 87.829634 9595IGKP IGKP1800 18009500 9500PKP PKP1500 500.49500 9500Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 03-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 6 Plots56 <-Paste Interval 6 Plots HereBlender Chemical Plot - Bucket Test 7.3.257/3/202507:0007:0507:1007:157/3/202507:20Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABAConoco Phillips - 3S-705 Interval 6 Plots57 <-Paste Interval 6 Plots HereTreatment Plot - Interval 06 DFIT7/2/202517:1517:2017:2517:307/2/202517:35Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD216Conoco Phillips - 3S-705 Interval 6 Plots58 Halliburton Pumping Diagnostic Analysis ToolkitMinifrac - G Function0.51.01.52.02.53.03.5G(Time)27402760278028002820284028602880A0102030405060D0102030405060708090100E (0.0023, 0) (m = 17.603) (Y = 0) (Y = 64.37) Gauge BH Pres (psi)Smoothed Pressure (psi)Smoothed Adaptive 1st Derivative (psi)Smoothed Adaptive G*dP/dG (psi)AADE11ClosureTime2.12GBP2782SP2781DP30.37FE52.81Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 02-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 6 Plots59 Treatment Plot - Interval 067/3/202508:4009:0009:207/3/202509:40Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211716151413121110987217Conoco Phillips - 3S-705 Interval 6 Plots60 Blender Chemical Plot - Interval 067/3/202508:3008:4008:5009:0009:1009:2009:3009:407/3/202509:50Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA3211716151413121110987217Conoco Phillips - 3S-705 Interval 6 Plots61 ADP Chemical Plots - Interval 067/3/202508:3008:4008:5009:0009:1009:2009:307/3/202509:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB3211716151413121110987217Conoco Phillips - 3S-705 Interval 6 Plots62 Net Pressure Plot - Interval 06567892345678910Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2806 psi 0 Time = 07/03/25 08:25:01 1Time-47.04NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 03-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 6 Plots63 <-Paste Interval 7 Plots HereTreatment Plot - Interval 077/3/202510:0010:2010:407/3/202511:00Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD32112111098765432187Conoco Phillips - 3S-705 Interval 7 Plots64 <-Paste Interval 7 Plots HereBlender Chemical Plot - Interval 077/3/202509:4009:5010:0010:1010:2010:3010:407/3/202510:50Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA3211211109876543211787Conoco Phillips - 3S-705 Interval 7 Plots65 <-Paste Interval 7 Plots HereADP Chemical Plots - Interval 077/3/202509:5010:0010:1010:2010:3010:4010:5011:007/3/202511:10Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB3211211109876543211787Conoco Phillips - 3S-705 Interval 7 Plots66 <-Paste Interval 7 Plots HereNet Pressure Plot - Interval 075678923456710Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2806 psi 0 Time = 07/03/25 09:45:01 1Time-127.04NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 03-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 7 Plots67 <-Paste Interval 8 Plots HereTreatment Plot - Interval 087/3/202511:0011:2011:4012:0012:207/3/202512:40Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321141312111098765432198Conoco Phillips - 3S-705 Interval 8 Plots68 <-Paste Interval 8 Plots HereBlender Chemical Plot - Interval 087/3/202511:0011:2011:4012:0012:207/3/202512:40Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA32114131211109876543211298Conoco Phillips - 3S-705 Interval 8 Plots69 <-Paste Interval 8 Plots HereADP Chemical Plots - Interval 087/3/202511:0011:2011:4012:0012:207/3/202512:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB321141312111098765432198Conoco Phillips - 3S-705 Interval 8 Plots70 <-Paste Interval 8 Plots HereNet Pressure Plot - Interval 08456789234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2806 psi 0 Time = 07/03/25 11:27:01 1Time-229.04NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 03-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 8 Plots71 <-Paste Interval 9 Plots HereTreatment Plot - Interval 097/3/202513:0013:2013:407/3/202514:00Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321121110987654321109Conoco Phillips - 3S-705 Interval 9 Plots72 <-Paste Interval 9 Plots HereBlender Chemical Plot - Interval 097/3/202512:4012:5013:0013:1013:2013:3013:407/3/202513:50Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA32112111098765432114109Conoco Phillips - 3S-705 Interval 9 Plots73 <-Paste Interval 9 Plots HereADP Chemical Plots - Interval 097/3/202512:4012:5013:0013:1013:2013:3013:4013:507/3/202514:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB32112111098765432114109Conoco Phillips - 3S-705 Interval 9 Plots74 <-Paste Interval 9 Plots HereNet Pressure Plot - Interval 09456789234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2806 psi 0 Time = 07/03/25 12:45:01 1Time-307.04NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 03-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 9 Plots75 <-Paste Interval 10 Plots HereTreatment Plot - Interval 107/3/202514:0014:1014:2014:3014:4014:5015:007/3/202515:10Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211211109876543211110Conoco Phillips - 3S-705 Interval 10 Plots76 <-Paste Interval 10 Plots HereBlender Chemical Plot - Interval 107/3/202514:0014:1014:2014:3014:4014:5015:007/3/202515:10Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA321121110987654321121110Conoco Phillips - 3S-705 Interval 10 Plots77 <-Paste Interval 10 Plots HereADP Chemical Plots - Interval 107/3/202513:5014:0014:1014:2014:3014:4014:5015:007/3/202515:10Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB321121110987654321121110Conoco Phillips - 3S-705 Interval 10 Plots78 <-Paste Interval 10 Plots HereNet Pressure Plot - Interval 1056789234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2806 psi 0 Time = 07/03/25 13:55:01 1Time-377.04NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 03-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 10 Plots79 <-Paste Interval 11 Plots HereTreatment Plot - Interval 117/3/202515:1015:2015:3015:4015:5016:0016:107/3/202516:20Time0100020003000400050006000A01020304050B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD12111098765432111Conoco Phillips - 3S-705 Interval 11 Plots80 <-Paste Interval 11 Plots HereBlender Chemical Plot - Interval 117/3/202515:1015:2015:3015:4015:5016:0016:107/3/202516:20Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA1211109876543211211Conoco Phillips - 3S-705 Interval 11 Plots81 <-Paste Interval 11 Plots HereADP Chemical Plots - Interval 117/3/202515:1015:2015:3015:4015:5016:0016:107/3/202516:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB1211109876543211211Conoco Phillips - 3S-705 Interval 11 Plots82 <-Paste Interval 11 Plots HereNet Pressure Plot - Interval 116789234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2806 psi 0 Time = 07/03/25 15:05:01 1Time-447.04NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 03-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 11 Plots83 <-Paste Interval 12 Plots HereePRV Test - 7.4.257/4/202507:2207:2307:2407:2507:2607:2707:287/4/202507:29Time01000200030004000500060007000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)6543Global Event Log3456Intersection IntersectionePRV - Primary Tubing ePRV - Primary IAePRV - Secondary Tubing ePRV - Secondary IA07:22:50 07:24:3607:26:46 07:27:48TP TP1197 876.8762.3 942.8TPP TPP1221 931.6841.2 995.2IGKP IGKP1500 15001500 1500Conoco Phillips - 3S-705 Interval 12 Plots84 <-Paste Interval 12 Plots HerePressure Test - 7.4.257/4/202507:3207:3407:3607:387/4/202507:40Time010002000300040005000600070008000900010000Treating Pressure (psi)Treating Pressure @Pump (psi)I1 Global Kickout Pressure (psi)P2 Kickout Pressure (psi)Pop-off (psi)5432Global Event Log2345Intersection IntersectionPressure Test - Global Pressure Test - LocalsPressure Test - Max Pressure Test - Pass07:31:26 07:31:3307:33:48 07:40:15TP TP399.4 422.29515 9487TPP TPP447.0 476.69610 9554IGKP IGKP25.00 95009500 9500PKP PKP500.4 94.229500 9500Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 04-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 12 Plots85 <-Paste Interval 12 Plots HereBlender Chemical Plot - Bucket Test 7.4.257/4/202506:5606:5807:0007:0207:0407:0607:0807:107/4/202507:12Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABAConoco Phillips - 3S-705 Interval 12 Plots86 <-Paste Interval 12 Plots HereADP Chemical Plots - Bucket Test 7.4.257/4/202506:54:4006:55:0006:55:2006:55:4006:56:0006:56:207/4/202506:56:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)ABConoco Phillips - 3S-705 Interval 12 Plots87 Treatment Plot - Interval 127/4/202508:2008:4009:0009:2009:4010:0010:207/4/202510:40Time0100020003000400050006000A0102030405060B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321201918171615141312111098765413Conoco Phillips - 3S-705 Interval 12 Plots88 Blender Chemical Plot - Interval 127/4/202508:2008:4009:0009:2009:4010:0010:207/4/202510:40Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA4321201918171615141312111098765413Conoco Phillips - 3S-705 Interval 12 Plots89 ADP Chemical Plots - Interval 127/4/202508:2008:4009:0009:2009:4010:0010:207/4/202510:40Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB321201918171615141312111098765413Conoco Phillips - 3S-705 Interval 12 Plots90 <-Paste Interval 13 Plots HereTreatment Plot - Interval 137/4/202510:4011:0011:207/4/202511:40Time0100020003000400050006000A0102030405060B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211211109876543211413Conoco Phillips - 3S-705 Interval 13 Plots91 <-Paste Interval 13 Plots HereBlender Chemical Plot - Interval 137/4/202510:4010:5011:0011:1011:2011:3011:407/4/202511:50Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA321121110987654321201413Conoco Phillips - 3S-705 Interval 13 Plots92 <-Paste Interval 13 Plots HereADP Chemical Plots - Interval 137/4/202510:4010:5011:0011:1011:2011:3011:407/4/202511:50Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB321121110987654321201413Conoco Phillips - 3S-705 Interval 13 Plots93 <-Paste Interval 13 Plots HereNet Pressure Plot - Interval 136789234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2806 psi 0 Time = 07/04/25 10:37:00 1Time-173.13NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 04-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 13 Plots94 <-Paste Interval 14 Plots HereTreatment Plot - Interval 147/4/202511:5012:0012:1012:2012:3012:4012:5013:007/4/202513:10Time0100020003000400050006000A0102030405060B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD3211211109876543211514Conoco Phillips - 3S-705 Interval 14 Plots95 <-Paste Interval 14 Plots HereBlender Chemical Plot - Interval 147/4/202511:5012:0012:1012:2012:3012:4012:507/4/202513:00Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA321121110987654321121514Conoco Phillips - 3S-705 Interval 14 Plots96 <-Paste Interval 14 Plots HereADP Chemical Plots - Interval 147/4/202511:5012:0012:1012:2012:3012:4012:507/4/202513:00Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB3211211109876543211514Conoco Phillips - 3S-705 Interval 14 Plots97 <-Paste Interval 14 Plots HereNet Pressure Plot - Interval 14456789100Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2650 psi 0 Time = 07/04/25 11:15:00 1Time-211.13NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 04-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 14 Plots98 <-Paste Interval 15 Plots HereTreatment Plot - Interval 157/4/202513:2013:4014:007/4/202514:20Time0100020003000400050006000A0102030405060B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD321121110987654321121615Conoco Phillips - 3S-705 Interval 15 Plots99 <-Paste Interval 15 Plots HereBlender Chemical Plot - Interval 157/4/202513:0013:1013:2013:3013:4013:5014:0014:107/4/202514:20Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA321121110987654321121615Conoco Phillips - 3S-705 Interval 15 Plots100 <-Paste Interval 15 Plots HereADP Chemical Plots - Interval 157/4/202513:0013:1013:2013:3013:4013:5014:0014:107/4/202514:20Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB321121110987654321121615Conoco Phillips - 3S-705 Interval 15 Plots101 <-Paste Interval 15 Plots HereNet Pressure Plot - Interval 15789234567810Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2650 psi 0 Time = 07/04/25 13:00:00 1Time-316.13NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 04-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 15 Plots102 <-Paste Interval 16 Plots HereTreatment Plot - Interval 167/4/202514:2014:4015:007/4/202515:20Time0100020003000400050006000A0102030405060B02468101214161820C0255075100125150DTreating Pressure (psi)Slurry Rate (bpm)Slurry Proppant Conc (lb/gal)BH Proppant Conc (lb/gal)Gauge BH Pres (psi)Actual BH Temp (°F)ABCCAD1312111098765432116Conoco Phillips - 3S-705 Interval 16 Plots103 <-Paste Interval 16 Plots HereBlender Chemical Plot - Interval 167/4/202514:2014:3014:4014:5015:0015:1015:207/4/202515:30Time0.00.51.01.52.02.53.0A012345BMO-67 Conc (gal/Mgal)BC-140 X2 Conc (gal/Mgal)Optiflo-II Conc (lb/Mgal)CAT-3 Conc (gal/Mgal)AABA1312111098765432116Conoco Phillips - 3S-705 Interval 16 Plots104 <-Paste Interval 16 Plots HereADP Chemical Plots - Interval 167/4/202514:2014:3014:4014:5015:0015:1015:207/4/202515:30Time010203040A0.00.20.40.60.81.01.21.41.61.82.0BWG-36 Conc (lb/Mgal)Losurf-300D Conc (gal/Mgal)AB131211109876543211216Conoco Phillips - 3S-705 Interval 16 Plots105 <-Paste Interval 16 Plots HereNet Pressure Plot - Interval 1645678923456710Time (min)2345678923456789100100010000A-5-4-3-2-1012345CNet Gauge BH Pres (psi)A Closure Pressure = 2650 psi 0 Time = 07/04/25 14:15:00 1Time-391.13NetPr0.000Slope0.000Customer: CONOCOPHILLIPS NORTH SLOPE - EBUSJob Date: 04-Jul-2025Sales Order #: 0910163471Well Description: 3S-705 3S-705UWI:Conoco Phillips - 3S-705 Interval 16 Plots106 Sales Order# - - - - - - - - - - Prepared for: Rodrigo Ruysschaert July 4, 2024 Harrison Bay County, AK 910163471 Conoco Phillips 3S-705 Intervals 1-16 Coyote Coyote Formation API: 50-103-20915 Real-Time QC Well Summary Stimulation Treatment Appendix Chemical Summary Planned Design Water Straps Water Analysis Event Log Sand Sieve Analysis Fann 15 Minute Field Break Test Conoco Phillips - 3S-705 Appendix 107 Interval DateDesigned Proppant (lbs)Proppant in Formation (lbs)Designed Fluid (bbl)Vol Clean (bbl)Vol Slurry (bbl)Pad Percentage Design Pad Percentage Actual Proppant Aggressiveness (lb/bbl Clean)Notes1 7/2/2025 203,000 205,282 1,593 1393 1,611 28.0 26.2 2672 7/2/2025 203,000 205,553 1,801 1686 1,904 28.0 27.0 2693 7/2/2025 203,000 203,982 1,199 1231 1,447 28.0 27.2 2694 7/2/2025 203,000 205,862 1,199 1204 1,423 28.0 27.2 2725 7/2/2025 203,000 204,876 1,199 1206 1,423 28.0 27.4 2746 7/3/2025 153,000 154,681 1,479 1431 1,595 32.9 32.1 252 Cut short due to stage communication7 7/3/2025 203,000 206,764 1,199 1205 1,425 28.0 27.3 2748 7/3/2025 203,000 201,689 1,461 1395 1,609 28.0 35.0 269 Pumped 2 pads after shutting down for IA issues9 7/3/2025 203,000 201,954 1,199 1205 1,419 28.0 27.4 26810 7/3/2025 203,000 203,463 1,199 1205 1,421 28.0 27.2 26911 7/3/2025 203,000 202,874 1,320 1314 1,529 28.0 28.2 27612 7/4/2025 206,000 206,211 2,091 1874 2,093 28.0 44.2 273 Two darts dropped - initial dart seated then slipped13 7/4/2025 203,000 204,311 1,199 1229 1,446 28.0 28.7 27214 7/4/2025 203,000 204,256 1,199 1224 1,441 28.0 27.4 27115 7/4/2025 203,000 201,706 1,199 1219 1,434 28.0 27.5 26916 7/4/2025 203,000 200,197 1,317 1319 1,531 28.0 28.4 266 3S-705 Interval HighlightsConoco Phillips - 3S-705Well Summary108 CustomerConoco Phillips FormationCoyoteLease3S-705API50-103-20915DateInterval Summary - Chemicals BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6(gal) (gal) (gal) (gal) (lbs) (lbs) (lbs)Prime Up0000000122 55 22 55 1552 97 72225 69 26 68 1823 138 0321 50 20 51 1319 101 0421 49 21 49 1329 98 0528 67 21 47 1408 116 0620 50 20 50 1430 100 48725 50 28 50 1349 100 0827 57 37 54 1407 114 0919 49 29 36 1373 99 01023 50 20 45 1260 100 01119 74 21 60 1290 107 01238 78 44 85 2121 155 541322 51 25 57 1320 103 01423 52 22 56 1508 103 01522 51 21 56 1352 103 01622 63 23 71 1400 146 0Total 377 915 400 890 23241 1780 174w/o Prime Up377 915 400 890 23241 1780 174Interval7/2/2024Dry AdditivesLiquid AdditivesConoco Phillips - 3S-705 Chemical Summary109 CUSTOMERConoco Phillips FALSEAPI BFD (lb/gal)8.54LAT 70.39426745LEASE3S-705SALES ORDERBHST (°F)105LONG-150.1954682FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6 Cum. PropTreatment Stage Fluid Stage Proppant Conc Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (lbs)1-1 Shut-In Shut-In1:47:24 1-2 Seawater Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:47:24 0.151-3 Shut-In Shut-In1:42:38 1-4 27# Linear Arsenal Sleeve Shift 5 1,260 30 30 0:06:00 1:42:38 1.00 1.00 27.00 2.00 0.151-5 27# Linear DFIT 10 1,680 40 40 0:04:00 1:36:38 1.00 1.00 27.00 2.00 0.151-6 Shut-In Shut-In1:32:38 1-7 27# Linear Step Rate Test 15 8,400 200 200 0:13:20 1:32:38 1.00 1.00 27.00 2.00 0.151-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:18 0.45 1.00 0.45 1.00 27.00 2.00 0.151-9 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.151-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 30001-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 81501-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.15252301-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.15 500101-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.15953001-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.151417001-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1777001-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.15 2030001-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 2030002-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:41:04 1.00 1.00 27.00 2.00 0.152-2 27# Delta Frac Minifrac - Establish Fluid 20 2,100 50 50 0:02:30 1:38:34 0.45 1.00 0.45 1.00 27.00 2.00 0.152-3 27# Delta Frac Minifrac - Treatment 20 7,458 178 178 0:08:53 1:36:04 0.45 1.0000 0.45 1.00 27.00 2.00 0.152-4 27# Linear Displacement 20 9,418 224 224 0:11:13 1:27:11 1.00 1.00 27.00 2.00 0.152-5 Shut-In Shut-In1:15:58 2-6 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:15:58 0.45 1.00 0.45 1.00 27.00 2.00 0.152-7 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.152-8 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 30002-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 81502-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.15252302-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.15 500102-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.15953002-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.151417002-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1777002-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.15 2030002-16 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 2030003-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:58 1.00 1.00 27.00 2.00 0.153-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:28 0.45 1.00 0.45 1.00 27.00 2.00 0.153-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.153-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 30003-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 81503-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.15 252303-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.15 500103-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.15 953003-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1417003-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1777003-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.15 2030003-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 2030004-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:58 1.00 1.00 27.00 2.00 0.154-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:28 0.45 1.00 0.45 1.00 27.00 2.00 0.154-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.154-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 30004-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 81504-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.15 252304-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.15 500104-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.15 953004-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1417004-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1777004-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.15 2030004-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 2030005-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:58 1.00 1.00 27.00 2.00 0.155-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:28 0.45 1.00 0.45 1.00 27.00 2.00 0.155-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.155-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 30005-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 81505-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.15 252305-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.15 500105-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.15 953005-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1417005-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1777005-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.15 2030005-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 2030006-1 27# Linear Displacement 20 7,295 174 174 0:08:41 1:33:49 1.00 1.00 27.00 2.00 0.156-2 27# Linear DFIT 5 840 20 20 0:04:00 1:25:08 1.00 1.00 27.00 2.00 0.156-3 Shut-In Shut-In1:21:08 Interval 1Coyote@ 13974.71 - 13978.71 ft 104.2 °FInterval 2Coyote@ 13420.46 - 13424.46 ft 104.2 °FInterval 3Coyote@ 12920.44 - 12924.44 ft 104.2 °FInterval 4Coyote@ 12420.9 - 12424.9 ft 104.2 °FInterval 5Coyote@ 11911.85 - 11915.85 ft 104.2 °F7/2/24Liquid Additives Dry Additives50-103-20915910163471Conoco Phillips - 3S-705Planned Design110 CUSTOMERConoco Phillips FALSEAPI BFD (lb/gal)8.54LAT 70.39426745LEASE3S-705SALES ORDERBHST (°F)105LONG-150.1954682FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6 Cum. PropTreatment Stage Fluid Stage Proppant Conc Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (lbs)7/2/24Liquid Additives Dry Additives50-103-209159101634716-4 Shut-In Shut-In1:21:08 6-5 Seawater Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:21:08 0.156-6 Shut-In Shut-In1:16:23 6-7 27# Linear Pre-Pad 15 4,200 100 100 0:06:40 1:16:23 1.00 1.00 27.00 2.00 0.156-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:09:43 0.45 1.00 0.45 1.00 27.00 2.00 0.156-9 27# Delta Frac Pad 20 8,915 212 212 0:10:37 0:56:23 0.45 1.00 0.45 1.00 27.00 2.00 0.156-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:45:46 0.45 1.00 0.45 1.00 27.00 2.00 0.15 30006-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:38:27 0.45 1.00 0.45 1.00 27.00 2.00 0.15 81506-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:35:07 0.45 1.00 0.45 1.00 27.00 2.00 0.15252306-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:29:06 0.45 1.00 0.45 1.00 27.00 2.00 0.15 500106-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:22:50 0.45 1.00 0.45 1.00 27.00 2.00 0.15953006-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 2,900 69 94 23,200 0:04:43 0:12:41 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1185006-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 2,000 48 67 18,000 0:03:21 0:07:58 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1365006-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 1,650 39 57 16,500 0:02:52 0:04:37 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1530006-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 1530007-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:58 1.00 1.00 27.00 2.00 0.157-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:28 0.45 1.00 0.45 1.00 27.00 2.00 0.157-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.157-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 30007-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 81507-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.15 252307-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.15 500107-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.15 953007-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1417007-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1777007-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.15 2030007-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 2030008-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:24:05 1.00 1.00 27.00 2.00 0.158-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:21:35 0.45 1.00 0.45 1.00 27.00 2.00 0.158-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:19:05 0.45 1.00 0.45 1.00 27.00 2.00 0.158-4 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:28 0.45 1.00 0.45 1.00 27.00 2.00 0.158-5 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.158-6 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 30008-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 81508-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.15 252308-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.15 500108-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.15953008-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.151417008-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1777008-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.15 2030008-14 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 2030009-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:58 1.00 1.00 27.00 2.00 0.159-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:28 0.45 1.00 0.45 1.00 27.00 2.00 0.159-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.159-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 30009-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 81509-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.15 252309-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.15 500109-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.15 953009-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1417009-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1777009-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.15 2030009-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 20300010-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:58 1.00 1.00 27.00 2.00 0.1510-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:28 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.1510-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 300010-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 815010-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.152523010-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.15 5001010-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.159530010-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.1514170010-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.1517770010-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.1520300010-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 20300011-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:17:00 1.00 1.00 27.00 2.00 0.1511-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:14:30 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:12:00 0.45 1.00 0.45 1.00 27.00 2.00 0.1511-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:01:23 0.45 1.00 0.45 1.00 27.00 2.00 0.15 300011-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:54:05 0.45 1.00 0.45 1.00 27.00 2.00 0.15 815011-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:50:44 0.45 1.00 0.45 1.00 27.00 2.00 0.152523011-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:44:44 0.45 1.00 0.45 1.00 27.00 2.00 0.15 5001011-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:38:28 0.45 1.00 0.45 1.00 27.00 2.00 0.159530011-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:28:18 0.45 1.00 0.45 1.00 27.00 2.00 0.1514170011-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:18:53 0.45 1.00 0.45 1.00 27.00 2.00 0.1517770011-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:12:10 0.45 1.00 0.45 1.00 27.00 2.00 0.1520300011-12 27# Linear Flush 20 6,535 156 156 0:07:47 0:07:47 1.00 1.00 27.00 2.00 0.15 203000Interval 9Coyote@ 9915.81 - 9919.81 ft 104.1 °FInterval 10Coyote@ 9416.24 - 9420.24 ft 104 °FInterval 11Coyote@ 8909.36 - 8913.36 ft 103.9 °FInterval 6Coyote@ 11412.38 - 11416.38 ft 104.2 °FInterval 7Coyote@ 10915.44 - 10919.44 ft 104.2 °FInterval 8Coyote@ 10415.58 - 10419.58 ft 104.1 °FConoco Phillips - 3S-705Planned Design111 CUSTOMERConoco Phillips FALSEAPI BFD (lb/gal)8.54LAT 70.39426745LEASE3S-705SALES ORDERBHST (°F)105LONG-150.1954682FORMATIONCoyoteDATE Max Pressure (psi)8500*Exceeds 80% of burst pressure*Prop Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6 Cum. PropTreatment Stage Fluid Stage Proppant Conc Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer CatalystInterval Number Description Description Description(ppg) (ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (lbs)7/2/24Liquid Additives Dry Additives50-103-2091591016347112-1 Shut-In Shut-In2:09:31 12-2 Seawater Prime Up Pressure Test 5 1,000 24 24 0:04:46 2:09:31 0.1512-3 Shut-In Shut-In2:04:45 12-4 27# Linear Spacer and Dart Drop 15 2,100 50 50 0:03:20 2:04:45 1.00 1.00 27.00 2.00 0.1512-5 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 2:01:25 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-6 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:48:05 0.45 1.00 0.45 1.00 27.00 2.00 0.1512-7 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:37:29 0.45 1.00 0.45 1.00 27.00 2.00 0.15 300012-8 27# Linear Displacement 15 5,376 128 128 0:08:32 1:30:10 1.00 1.00 27.00 2.00 0.15 300012-9 27# Linear Spacer and Dart Drop 15 1,470 35 35 0:02:20 1:21:38 1.00 1.00 27.00 2.00 0.15 300012-10 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:18 0.45 1.00 0.45 1.00 27.00 2.00 0.15 300012-11 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.15 300012-12 27# Delta Frac Conditioning Pad Wanli 16/20 Ceramic 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 600012-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 1115012-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.15 2823012-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.155301012-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.15 9830012-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.15 14470012-18 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.1518070012-19 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.1520600012-20 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 20600013-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:58 1.00 1.00 27.00 2.00 0.1513-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:28 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.1513-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 300013-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 815013-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.152523013-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.15 5001013-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.159530013-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.1514170013-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.1517770013-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.1520300013-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 20300014-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:58 1.00 1.00 27.00 2.00 0.1514-2 27# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:28 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 27.00 2.00 0.1514-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 27.00 2.00 0.15 300014-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 27.00 2.00 0.15 815014-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 27.00 2.00 0.152523014-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 27.00 2.00 0.15 5001014-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 27.00 2.00 0.159530014-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 27.00 2.00 0.1514170014-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 27.00 2.00 0.1517770014-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 27.00 2.00 0.1520300014-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 27.00 2.00 0.15 20300015-1 25# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:10:58 1.00 1.00 25.00 2.00 0.1515-2 25# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:08:28 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-3 25# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.45 1.00 25.00 2.00 0.1515-4 25# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.45 1.00 25.00 2.00 0.15 300015-5 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.45 1.00 25.00 2.00 0.15 815015-6 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.45 1.00 25.00 2.00 0.152523015-7 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.45 1.00 25.00 2.00 0.15 5001015-8 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.45 1.00 25.00 2.00 0.159530015-9 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.45 1.00 25.00 2.00 0.1514170015-10 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.45 1.00 25.00 2.00 0.1517770015-11 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.45 1.00 25.00 2.00 0.1520300015-12 25# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 1.00 25.00 2.00 0.15 20300016-1 25# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:22:06 1.00 1.00 25.00 2.00 0.1516-2 25# Delta Frac Establish Stable Fluid 20 2,100 50 50 0:02:30 1:19:36 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-3 25# Delta Frac Pad 20 8,915 212 212 0:10:37 1:17:06 0.45 1.00 0.45 1.00 25.00 2.00 0.1516-4 25# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:06:29 0.45 1.00 0.45 1.00 25.00 2.00 0.15 300016-5 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:59:11 0.45 1.00 0.45 1.00 25.00 2.00 0.15 815016-6 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:55:50 0.45 1.00 0.45 1.00 25.00 2.00 0.152523016-7 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:49:50 0.45 1.00 0.45 1.00 25.00 2.00 0.15 5001016-8 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:43:34 0.45 1.00 0.45 1.00 25.00 2.00 0.159530016-9 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:33:24 0.45 1.00 0.45 1.00 25.00 2.00 0.1514170016-10 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:23:59 0.45 1.00 0.45 1.00 25.00 2.00 0.1517770016-11 25# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:17:16 0.45 1.00 0.45 1.00 25.00 2.00 0.1520300016-12 25# Linear Flush 20 4,937 118 118 0:05:53 0:12:53 1.00 1.00 25.00 2.00 0.15 20300016-13 Freeze Protect Freeze Protect 5 1,470 35 35 0:07:00 0:07:00 20300016-14 Shut-In Shut-In203000917,809 21,853 25,253 3,201,000Design Total (gal)Design Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-6 Cum. Prop718,3683,153,000(gal) (gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)90,78448,000Initial Design Material Volume 365.4 913.3 365.4 913.3 24,451.8 1,826.7 137.53,000-1,470-Whole Units to be ordered93,580-BC-140X2 Losurf-300D MO-67 CAT-3 WG-36 OPTIFLO-II BE-610607.18251(gpm) (gpm) (gpm) (gpm) ppm ppm ppm-Max Additive Rate 0.4 0.8 0.4 0.8 22.7 1.7 0.1-Min Additive Rate21:53:45 Interval 12Coyote@ 8410.32 - 8414.32 ft 103.9 °FInterval 13Coyote@ 7910.63 - 7914.63 ft 103.8 °FInterval 14Coyote@ 7411.38 - 7415.38 ft 103.8 °FInterval 15Coyote@ 6912.05 - 6916.05 ft 103.7 °FInterval 16Coyote@ 6409.86 - 6413.86 ft 103.7 °FProppant TypeWanli 16/20 Ceramic100M--25# LinearFluid Type27# Delta Frac27# LinearSeawaterFreeze Protect25# Delta Frac---Conoco Phillips - 3S-705Planned Design112 Customer:Well:Date:Formation:SO#:Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels1 Wichita 3J 89 17,850 425 100 10 1,890 452 Wichita 3J 93 18,690 445 100 10 1,890 453 Wichita 3J 94 18,900 450 107 10 1,890 454 Wichita 3J 87 17,430 415 99 10 1,890 455 Wichita 3J 92 18,480 440 92 10 1,890 456 Wichita 3J 90 18,060 430 95 10 1,890 457 Wichita 3J 93 18,690 445 98 10 1,890 458 Atigan 3J 96 18,208 434 100 10 1,627 399 Atigan 3J 99 18,788 447 95 10 1,627 3910 Atigan 3J 99 18,788 447 110 10 1,627 3911 Atigan 3J 100 18,981 452 98 10 1,627 3912 Atigan 3J 101 19,175 457 99 10 1,627 3913 Atigan 3J 97 18,401 438 103 10 1,627 3914 Atigan 3J 100 18,981 452 100 10 1,627 3915 Atigan 3J 100 18,981 452 9 10 1,627 3916 Atigan 3J 100 18,981 452 100 30 5,277 12617 Atigan 3J 97 18,401 438 105 30 5,277 12618 Atigan 3J 102 19,368 461 110 30 5,277 12619 Atigan 3J 92 17,434 415 100 102 19,368 46120 Atigan 3J 91 17,241 410 109 92 17,434 41521 Atigan 3J 101 19,175 457 101 91 17,241 41022 Atigan 3J 101 19,175 457 101 19,175 45723 Atigan 3J 100 18,981 452 101 19,175 45724 Atigan 3J 100 18,981 452 100 18,981 452Gallons Barrels Gallons Barrels Gallons Barrels446,141 10,622 153,452 3,654 292,689 6,969Zones: 1Volume Needed for X Intervals (BBL):Number of Tanks Needed:000 0Tank Bottoms (BBL):443 443 443 443Conoco Phillips 3S-7057/2/2025Coyote910163471Pre-Job Barrel BottomsGeneral Beginning Strap Ending StrapLocation SummaryStarting Volume Ending Volume Total UsedConoco Phillips - 3S-705Water Straps 7.2.25113 Customer:Well:Date:Formation:SO#:Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels1 Wichita 3J 99 19,950 475 100 10 1,890 452 Wichita 3J 96 19,320 460 102 10 1,890 453 Wichita 3J 98 19,740 470 103 10 1,890 454 Wichita 3J 98 19,740 470 99 10 1,890 455 Wichita 3J 100 20,160 480 105 10 1,890 456 Wichita 3J 99 19,950 475 100 10 1,890 457 Wichita 3J 99 19,950 475 103 10 1,890 458 Atigan 3J 104 19,755 470 105 10 1,627 399 Atigan 3J 105 19,949 475 101 10 1,627 3910 Atigan 3J 105 19,949 475 101 10 1,627 3911 Atigan 3J 105 19,949 475 100 10 1,627 3912 Atigan 3J 105 19,949 475 102 10 1,627 3913 Atigan 3J 101 19,175 457 104 10 1,627 3914 Atigan 3J 104 19,755 470 105 10 1,627 3915 Atigan 3J 104 19,755 470 100 10 1,627 3916 Atigan 3J 106 20,142 480 100 10 1,627 3917 Atigan 3J 105 19,949 475 102 50 9,119 21718 Atigan 3J 105 19,949 475 103 50 9,119 21719 Atigan 3J 105 19,949 475 100 50 9,119 21720 Atigan 3J 105 19,949 475 103 91 17,241 41021 Atigan 3J 104 19,755 470 101 91 17,241 41022 Atigan 3J 105 19,949 475 101 101 19,175 45723 Atigan 3J 105 19,949 475 103 101 19,175 45724 Atigan 3J 102 19,368 461 100 100 18,981 452Gallons Barrels Gallons Barrels Gallons Barrels476,003 11,333 147,042 3,501 328,961 7,832Zones: 1Volume Needed for X Intervals (BBL):Number of Tanks Needed:000 0Tank Bottoms (BBL):472 472 472 472Pre-Job Barrel BottomsGeneral Beginning Strap Ending StrapLocation SummaryStarting Volume Ending Volume Total UsedConoco Phillips 3S-7057/3/2025Coyote910163471Conoco Phillips - 3S-705Water Straps 7.3.25114 Customer:Well:Date:Formation:SO#:Tank Type Water Source Inches Gallons Barrels Temperature (°F) Inches Gallons Barrels1 Wichita 3J 96 19,320 460 99 10 1,890 452 Wichita 3J 97 19,530 465 105 10 1,890 453 Wichita 3J 95 19,110 455 105 10 1,890 454 Wichita 3J 98 19,740 470 97 10 1,890 455 Wichita 3J 97 19,530 465 103 10 1,890 456 Wichita 3J 96 19,320 460 99 10 1,890 457 Wichita 3J 99 19,950 475 104 10 1,890 458 Atigan 3J 105 19,949 475 106 10 1,627 399 Atigan 3J 96 18,208 434 103 10 1,627 3910 Atigan 3J 103 19,562 466 100 10 1,627 3911 Atigan 3J 105 19,949 475 103 10 1,627 3912 Atigan 3J 105 19,949 475 103 10 1,627 3913 Atigan 3J 101 19,175 457 106 10 1,627 3914 Atigan 3J 105 19,949 475 103 10 1,627 3915 Atigan 3J 106 20,142 480 100 10 1,627 3916 Atigan 3J 105 19,949 475 103 17 2,905 6917 Atigan 3J 105 19,949 475 102 25 4,365 10418 Atigan 3J 105 19,949 475 102 104 19,755 47019 Atigan 3J 104 19,755 470 100 104 19,755 47020 Atigan 3J 106 20,142 480 100 106 20,142 48021 Atigan 3J 105 19,949 475 102 105 19,949 47522 Atigan 3J 105 19,949 475 100 105 19,949 47523 Atigan 3J 104 19,755 470 101 104 19,755 47024 Atigan 3J 102 19,368 461 99 102 19,368 461Gallons Barrels Gallons Barrels Gallons Barrels472,145 11,242 172,189 4,100 299,956 7,142Zones: 1Volume Needed for X Intervals (BBL):Number of Tanks Needed:000 0Tank Bottoms (BBL):468 468 468 468Conoco Phillips 3S-7057/4/2025Coyote910163471Pre-Job Barrel BottomsGeneral Beginning Strap Ending StrapLocation SummaryStarting Volume Ending Volume Total UsedConoco Phillips - 3S-705Water Straps 7.4.25115 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl-)Sulfate(SO42-)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPost-CrosslinkpHCrosslink Bacteria- °F mg/L mg/L mg/L mg/L mg/L mg/L cP - - - (Y/N) BQ ValueTank #H2S present? Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal Hardness Minus CalciumTitration FANN-35 Probe Probe Probe - Mycometer1 N 1.000 91 0 1,566 200 280 0 280 21.0 6.85 7.14 8.65 Y 52,2532 N 1.000 91 2 1,712 200 240 0 240 21.0 6.95 7.15 8.67 Y 27,8573 N 1.000 90 0 1,566 200 240 0 240 22.0 6.90 7.14 8.63 Y 40,0204 N 1.000 92 2 1,566 200 280 0 280 21.0 6.91 7.18 8.80 Y 63,7705 N 1.000 91 0 2,210 200 280 0 280 21.0 6.96 7.29 8.62 Y 35,8016 N 1.000 90 0 2,400 200 240 40 280 22.0 6.99 7.19 8.79 Y 41,4707 N 1.000 86 2 1,302 200 280 160 440 21.0 7.02 7.28 8.63 Y 48,7138 N 1.000 90 2 3,316 200 400 40 440 21.0 6.95 7.25 8.77 Y 36,7539 N 1.000 94 2 1,566 200 280 40 320 21.0 6.99 7.31 8.67 Y 59,00610 N 1.000 92 0 1,430 200 280 0 280 21.0 6.95 7.25 8.71 Y 45,59011 N 1.000 92 2 1,866 200 280 120 400 22.0 6.90 7.15 8.70 Y 35,38012 N 1.000 93 0 1,866 200 320 0 320 22.0 6.83 7.25 8.71 Y 37,92113 N 1.000 90 2 1,492 200 240 40 280 21.0 7.00 7.29 8.85 Y 47,69714 N 1.000 91 2 1,152 200 280 120 400 22.0 7.03 7.19 8.81 Y 59,84915 N 1.000 91 0 1,152 200 240 40 280 21.0 7.02 7.19 8.80 Y 68,11916 N 1.000 90 2 1,152 200 240 40 280 21.0 7.04 7.28 8.77 Y 53,44717 N 1.000 89 0 1,066 200 280 40 320 23.0 7.07 7.20 8.82 Y 65,47518 N 1.000 92 2 1,180 200 280 40 320 21.0 7.09 7.38 8.89 Y 20,71219 N 1.000 94 2 1,180 200 240 40 280 21.0 7.13 7.23 8.80 Y 63,46820 N 1.000 93 0 1,302 200 240 40 280 21.0 7.09 7.18 8.87 Y 80,18321 N 1.000 95 2 1,180 200 240 0 240 20.0 7.09 7.20 8.88 Y 61,76222 N 1.000 93 0 1,180 200 240 0 240 21.0 6.96 7.17 8.81 Y 90,76823 N 1.000 94 0 1,430 200 240 0 240 20.0 6.95 7.20 8.80 Y 40,60224 N 1.000 95 2 1,430 200 280 40 320 21.0 6.95 7.15 8.79 Y 64,879Average 1.000 1 1,553 200 268 35 303 21.2 6.98 7.22 8.76 - 51,729Maximum 1.000 2 3,316 200 400 160 440 23.0 7.13 7.38 8.89 - 90,768Minimum 1.000 0 1,066 200 240 0 240 20.00 6.83 7.15 8.62 - 20,712Range 0.000 2 2,250 0 160 160 200 3.0 0.30 0.23 0.27 - 70,056Well Name:3S-705Water Source:CPF3Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco Phillips Conoco Phillips - 3S-705Water Analysis 7.1.25116 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl-)Sulfate(SO42-)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPost-CrosslinkpHCrosslink Bacteria- °F mg/L mg/L mg/L mg/L mg/L mg/L cP - - - (Y/N) BQ ValueTank #H2S present? Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal Hardness Minus CalciumTitration FANN-35 Probe Probe Probe - Mycometer1 N 1.000 0 1,566 200 280 80 360 84,1772 N 1.000 0 1,866 200 280 40 320 38,5543 N 1.000 0 1,566 200 360 3,240 3,600 56,4564 N 1.000 0 1,430 200 240 160 400 57,4255 N 1.000 0 1,566 200 320 120 440 50,7326 N 1.000 0 1,866 200 320 80 400 54,7727 N 1.000 0 1,712 200 400 0 400 45,0378 N 1.000 0 2,210 200 360 120 480 44,6479 N 1.000 0 1,866 200 400 0 400 57,15510 N 1.000 0 1,712 200 400 0 400 52,19711 N 1.000 0 1,712 200 280 120 400 41,27212 N 1.000 0 1,566 200 280 80 360 41,22713 N 1.000 0 2,032 200 240 40 280 47,45414 N 1.000 0 1,712 200 320 80 400 46,33215 N 1.000 0 1,566 200 240 240 480 56,355Average 1.000 0 1,730 200 315 293 608 20.7 6.92 7.32 8.83 - 51,586Maximum 1.000 0 2,210 200 400 3,240 3,600 21.0 6.94 7.43 8.85 - 84,177Minimum 1.000 0 1,566 200 240 0 280 20.00 6.90 7.22 8.81 - 38,554Range 0.000 0 644 0 160 3,240 3,320 1.0 0.04 0.21 0.04 - 45,6228.81 Y10520.0 6.92 7.228..9 Y10621.0 6.90 7.31 8.85 Y10421.0 6.94 7.43Well Name:3S-705Water Source:CPF3Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco Phillips Conoco Phillips - 3S-705Water Analysis 7.2.25117 SpecificGravityTestingTemperatureDissolved Iron(Fe2+)Chloride(Cl-)Sulfate(SO42-)Calcium(Ca2+)Magnesium(Mg2+)TotalHardnessLinearViscosityWaterpHGelpHPost-CrosslinkpHCrosslink Bacteria- °F mg/L mg/L mg/L mg/L mg/L mg/L cP - - - (Y/N) BQ ValueTank #H2S present? Y/NHydrometer Digital Thermometer Strip Strip Strip TitrationTotal Hardness Minus CalciumTitration FANN-35 Probe Probe Probe - Mycometer1 N 1.000 0 2,032 200 400 80 480 38,2632 N 1.000 0 2,032 200 400 200 600 35,6173 N 1.000 0 1,866 200 280 200 480 40,7104 N 1.000 0 1,866 200 400 120 520 37,2905 N 1.000 0 2,032 200 400 40 440 43,7076 N 1.000 0 1,542 200 280 240 520 58,0407 N 1.000 0 1,814 200 280 280 560 55,3808 N 1.000 0 1,542 200 280 240 520 37,9009 N 1.000 0 1,674 200 360 80 440 50,22410 N 1.000 0 1,674 200 280 120 400 45,91411 N 1.000 0 1,814 200 280 160 440 50,97512 N 1.000 0 1,542 200 320 200 520 46,22413 N 1.000 0 1,674 200 280 160 440 51,89414 N 1.000 0 1,674 200 360 120 480 48,35515 N 1.000 0 1,542 200 480 -80 400 39,43416 N 1.000 0 1,566 200 400 80 48017 N 1.000 0 1,566 200 440 40 480Average 1.000 0 1732 200 348 134 482 21.3 6.91 7.26 8.83 - 45,329Maximum 1.000 0 2,032 200 480 280 600 22.0 6.92 7.31 8.90 - 58,040Minimum 1.000 0 1,542 200 280 -80 400 21.00 6.90 7.21 8.75 - 35,617Range 0.000 0 490 0 200 360 200 1.0 0.02 0.10 0.15 - 22,423Alaska District Field QCPrejob Water Analysis on LocationCompany:Conoco Phillips Well Name:3S-705Water Source:CPF38.82 Y11022.0 6.92 7.25 8.90 Y10821.0 6.91 7.288.84 Y10921.0 6.90 7.21 8.75 Y10921.0 6.90 7.31Conoco Phillips - 3S-705Water Analysis 7.4.25118 Linear Linear XL XL XL Lip time Linear Linear XL XL XL Lip time Interval Stage Visc pHTemp °FpH min Interval Stage Visc pHTemp °FpHmin 1 Pad 19 7.2 87 8.72 0 11 Pad217.05988.66 0 .50# 19 7.3 90 8.78 0 21 Avg Linear Visc .50# 21 7.06 98 8.73 0 22 Avg Linear Visc 2.00# 21 7.2 85 8.83 0 88.9 Avg XLTemp 2.00# 22 7.05 97 8.77 0 95.2 Avg XLTemp 4.00# 21 7.1 91 8.85 0 8.8 Avg XL pH 4.00# 22 7.06 96 8.76 0 8.76 Avg XL pH 6.00# 22 7.2 90 8.81 0 6.00# 21 7.06 95 8.74 0 7.00# 22 7.18 86 8.87 0 7.00# 22 7.05 97 8.76 0 8.00# 23 7.05 89 8.85 0 8.00# 22 7.06 95 8.76 0 9.00# 23 7.06 92 8.75 0 9.00# 22 7 90 8.82 0 10.00# 22 7 90 8.8 0 10.00# 22 7 91 8.81 0 2 Pad 24 7.1 91 8.77 0 12 Pad227.08928.68 0 .50# 24 7.1 91 8.8 0 .50# 21 7.08 91 8.73 0 2.00# 23 7.02 92 8.78 0 2.00# 22 7.08 90 8.76 0 4.00# 22 7.1 93 8.77 0 23 Avg Linear Visc 4.00# 22 7.08 94 8.74 0 22 Avg Linear Visc 6.00# 22 7.09 91 8.77 0 89.9 Avg XLTemp 6.00# 22 7.07 96 8.72 0 92.6 Avg XLTemp 7.00# 22 7.12 92 8.78 0 8.8 Avg XL pH 7.00# 22 7.05 93 8.72 0 8.73 Avg XL pH 8.00# 22 7.12 88 8.82 0 8.00# 22 7.06 93 8.7 0 9.00# 22 7.15 86 8.85 0 9.00# 22 7.05 91 8.74 0 10.00# 22 7.15 85 8.83 0 10.00# 22 7.06 93 8.76 0 3 Pad 22 7.18 91 8.66 0 13 Pad227.04978.62 0 .50# 22 7.18 91 8.76 0 .50# 22 7.05 95 8.73 0 2.00# 22 7.2 91 8.78 0 2.00# 22 7.05 98 8.67 0 4.00# 22 7.19 93 8.8 0 22 Avg Linear Visc 4.00# 22 7.05 97 8.69 0 22 Avg Linear Visc 6.00# 22 7.21 91 8.74 0 89.9 Avg XLTemp 6.00# 22 7.06 94 8.73 0 95.8 Avg XLTemp 7.00# 22 7.22 91 8.82 0 8.8 Avg XL pH 7.00# 22 7.07 95 8.7 0 8.70 Avg XL pH 8.00# 22 7.21 89 8.89 0 8.00# 22 7.05 98 8.67 0 9.00# 22 7.19 88 8.81 0 9.00# 22 7.06 93 8.75 0 10.00# 22 7.2 84 8.86 0 10.00# 22 7.05 95 8.73 0 4 Pad 22 7.19 93 8.67 0 14 Pad 22 7.06 100 8.53 0 .50# 22 7.21 92 8.79 0 .50# 22 7.06 100 8.68 0 2.00# 22 7.18 89 8.79 0 2.00# 22 7.05 98 8.72 0 4.00# 22 7.17 90 8.77 0 22.11 Avg Linear Visc 4.00# 22 7.06 95 8.76 0 22 Avg Linear Visc 6.00# 22 7.15 91 8.83 0 89.89 Avg XLTemp 6.00# 22 7.05 96 8.74 0 95.3 Avg XLTemp 7.00# 22 7.18 91 8.82 0 8.79 Avg XL pH 7.00# 22 7.07 95 8.72 0 8.71 Avg XL pH 8.00# 23 7.16 88 8.82 0 8.00# 22 7.04 90 8.75 0 9.00# 22 7.2 89 8.84 0 9.00# 22 7.04 94 8.77 0 10.00# 22 7.18 86 8.82 0 10.00# 22 7.04 90 8.75 0 5 Pad 22 7.17 97 8.66 0 15 Pad217.05908.74 0 .50# 22 7.18 98 8.75 0 .50# 22 7.04 90 8.74 0 2.00# 22 7.15 95 8.74 0 2.00# 21 7.04 90 8.7 0 4.00# 22 7.2 93 8.81 0 22.00 Avg Linear Visc 4.00# 21 7.04 96 8.68 0 20 Avg Linear Visc 6.00# 22 7.23 91 8.8 0 90.11 Avg XLTemp 6.00# 21 7.01 97 8.7 0 93.7 Avg XLTemp 7.00# 22 7.19 85 8.86 0 8.80 Avg XL pH 7.00# 20 7.03 94 8.71 0 8.72 Avg XL pH 8.00# 22 7.19 89 8.85 0 8.00# 18 7 95 8.74 0 9.00# 22 7.15 83 8.86 0 9.00# 19 7.05 96 8.7 0 10.00# 22 7.16 80 8.91 0 10.00# 19 0.04 95 8.73 0 6 Pad 22 7.07 91 8.7 0 16 Pad207.05968.67 0 .50# 22 7.07 89 8.81 0 .50# 20 7.05 95 8.75 0 2.00# 23 7.1 88 8.8 0 2.00# 19 7.04 98 8.75 0 4.00# 24 7.15 95 8.78 0 23.11 Avg Linear Visc 4.00# 19 7.02 96 8.72 0 19 Avg Linear Visc 6.00# 24 7.09 90 8.82 0 89.44 Avg XLTemp 6.00# 19 7.02 94 8.72 0 95.3 Avg XLTemp 7.00# 24 7.11 87 8.78 0 8.80 Avg XL pH 7.00# 18 7.05 96 8.7 0 8.73 Avg XL pH 8.00# 23 7.09 88 8.8 0 8.00# 19 7.06 93 8.72 0 9.00# 23 7.08 88 8.89 0 9.00# 18 7.04 95 8.75 0 10.00# 23 7.09 89 8.80 0 10.00# 19 7.02 95 8.75 0 7 Pad 22 7.09 88 8.67 0 17 Pad .50# 22 7.1 96 8.7 0 .50# 2.00# 22 7 95 8.77 0 2.00# 4.00# 22 7.02 97 8.8 0 22 Avg Linear Visc 4.00# #DIV/0! Avg Linear Visc 6.00# 21 7.01 91 8.8 0 92.7 Avg XLTemp 6.00# #DIV/0! Avg XLTemp 7.00# 21 7.05 89 8.83 0 8.8 Avg XL pH 7.00# #DIV/0! Avg XL pH 8.00# 22 7.05 92 8.8 0 8.00# 9.00# 22 7.05 93 8.81 0 9.00# 10.00# 22 7.06 93 8.8 0 10.00# 8 Pad 21 7.05 95 8.63 0 18 Pad .50# 22 7.13 98 8.7 0 .50# 2.00# 21 7.11 96 8.73 0 2.00# 4.00# 20 7.11 94 8.75 0 21.00 Avg Linear Visc 4.00# #DIV/0! Avg Linear Visc 6.00# 21 7.15 92 8.75 0 94.56 Avg XLTemp 6.00# #DIV/0! Avg XLTemp 7.00# 21 7.15 95 8.79 0 8.76 Avg XL pH 7.00# #DIV/0! Avg XL pH 8.00# 21 7.1 95 8.84 0 8.00# 9.00# 21 7.14 95 8.8 0 9.00# 10.00# 21 7.14 91 8.83 0 10.00# 9 Pad 22 7.12 97 8.83 0 19 Pad .50# 22 7.12 95 8.74 0 .50# 2.00# 22 7.11 95 8.76 0 2.00# 4.00# 21 7.11 94 8.8 0 22 Avg Linear Visc 4.00# #DIV/0! Avg Linear Visc 6.00# 21 7.11 95 8.76 0 93.2 Avg XLTemp 6.00# #DIV/0! Avg XLTemp 7.00# 21 7.11 95 8.75 0 8.78 Avg XL pH 7.00# #DIV/0! Avg XL pH 8.00# 21 7.1 92 8.8 0 8.00# 9.00# 22 7.09 89 8.8 0 9.00# 10.00# 22 7.11 87 8.75 0 10.00# 10 Pad 22 7.1 97 8.63 0 20 Pad .50# 22 7.1 97 8.7 0 .50# 2.00# 22 7.1 93 8.76 0 2.00# 4.00# 22 7.09 92 8.77 0 22 Avg Linear Visc 4.00# #DIV/0! Avg Linear Visc 6.00# 22 7.01 91 8.81 0 93.4 Avg XLTemp 6.00# #DIV/0! Avg XLTemp 7.00# 22 7.06 91 8.76 0 8.76 Avg XL pH 7.00# #DIV/0! Avg XL pH 8.00# 22 7.07 94 8.78 0 . 8.00# 9.00# 22 7.05 93 8.8 0 9.00# 10.00# 21 7.06 93 8.79 0 10.00# Customer:CONOCO PHILLIPS Wellname & #:3S-705 Date:July 2, 2025 Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Comments Conoco Phillips - 3S-705 Real-Time QC 119 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 05:45:03 (07/02/25) Other Crew Arrived on Location ---- ---- ---- ---- ---- 2 6:15:19 Start Job Starting Job 0 -2 12 0 1921 1 06:15:19 (07/02/25) Next Treatment Treatment Interval 1 0 -2 12 0 1921 3 6:29:51 Pre-Job Safety Meeting Pre-Job Safety Meeting 0 -3 11 0 1920 4 7:39:52 Prime Pumps Prime Pumps 0 -3 4 0 1918 5 7:54:48 Pressure Test ePRV - Primary Tubing 0 275 261 0 1917 6 7:57:02 Pressure Test ePRV - Primary IA 0 310 151 0 1917 7 7:58:51 Pressure Test ePRV - Secondary Tubing 0 1116 1169 0 1917 8 8:00:20 Pressure Test ePRV - Secondary IA 0 790 276 0 1917 9 8:05:00 Pressure Test Pressure Test - Global 0 612 641 0 1917 10 8:05:07 Pressure Test Pressure Test - Locals 0 619 651 0 1917 11 8:07:29 Pressure Test Pressure Test - Max 0 9479 9560 0 1917 12 8:12:34 Pressure Test Pressure Test - Pass 0 9417 9481 0 1917 13 9:01:14 Start Pumping Start Pumping 0 892 909 0 2465 14 9:01:56 Open Well Open Well 0.44 730 711 0.8 2481 15 9:02:56 Other Arsenal Burst Disk 2.44 5014 5120 2.5 6919 16 9:04:08 Other Alpha Sleeve Shift 5.67 5981 6073 2.8 7928 17 9:05:00 Other Start DFIT 8.53 1416 1498 5.2 3200 18 9:08:41 ISIP ISIP 28.35 1090 1078 1.1 2820 19 9:38:22 Open Well Open Well 28.51 545 535 0 2267 20 9:39:46 Other Step 1 29.86 1215 1287 1.1 3041 21 9:41:12 Other Step 2 32.62 1298 1318 2.1 3041 22 9:42:24 Other Step 3 36.03 1318 1347 2.9 3059 23 9:43:38 Other Step 4 40.82 1358 1398 4 3080 24 9:44:53 Other Step 5 46.89 1425 1460 5 3129 25 9:46:04 Other Step 6 53.95 1503 1550 6.1 3196 26 9:47:18 Other Step 7 62.42 1572 1621 7.1 3243 27 9:48:30 Other Step 8 71.72 1621 1674 7.9 3290 28 9:49:40 Other Step 9 82.09 1672 1724 9 3345 29 9:50:50 Other Step 10 93.79 1713 1773 10 3401 30 9:52:04 Other Step 11 107.21 1758 1833 11 3447 31 9:53:16 Other Step 12 121.26 1808 1879 12 3478 32 9:54:26 Other Step 13 136.44 1867 1908 13 3506 33 9:55:40 Other Step 14 153.35 1924 1988 14 3550 34 9:57:14 Other Step 15\\ 176.47 1963 2036 14.8 3564 35 9:57:37 ISIP ISIP 180.42 747 718 0 2531 36 9:57:57 Other hut Down To Trouble Shoot DA and Sand Screw 180.42 1017 1026 0 2837 37 10:06:42 Alarm Delta Stage At Top Perf = 4 235.31 1839 1957 15.5 3440 38 10:07:15 Alarm Delta Stage At Top Perf = 5 243.85 1830 2015 15.5 3448 39 10:08:20 Alarm Delta Stage At Top Perf = 6 263.72 2114 2313 19.7 3607 40 10:08:21 Alarm Delta Stage At Top Perf = 7 264.05 2114 2315 19.7 3609 41 10:15:55 Alarm Delta Stage At Top Perf = 8 416.11 2492 2737 20.2 3693 42 10:18:41 Alarm Delta Stage At Top Perf = 9 471.79 2739 2992 20.2 3908 43 10:29:10 Alarm Delta Stage At Top Perf = 10 683 2693 3003 20 4013 44 10:35:53 Alarm Delta Stage At Top Perf = 11 815.91 2711 3044 19.9 4109 45 10:39:13 Alarm Delta Stage At Top Perf = 12 882.29 2785 3097 19.9 4237 46 10:41:50 Other 2nd Tracer Drop 933.99 2870 3189 19.9 4334 47 10:45:16 Alarm Delta Stage At Top Perf = 13 1002.6 2870 3203 20 4403 48 10:51:36 Alarm Delta Stage At Top Perf = 14 1128.26 2865 3194 19.8 4403 49 11:01:59 Alarm Delta Stage At Top Perf = 15 1333.57 2901 3245 19.7 4474 50 11:06:51 Other 3rd Tracer Drop 1429.5 2916 3269 19.7 4490 51 11:11:40 Alarm Delta Stage At Top Perf = 16 1524.68 2959 3286 20.3 4560 52 11:15:17 Drop Ball Drop Dart for Interval 02 1597.99 3382 3542 20.4 4618 53 11:15:17 Stop Pumping Stop Pumping 1598.33 3381 3541 20.4 4620 54 11:15:18 Start Pumping Start Pumping 1598.67 3379 3540 20.4 4623 2 11:15:21 (07/02/25) Next Treatment Treatment Interval 2 1599.68 3378 3536 20.4 4604 55 11:17:56 Alarm Delta Stage At Top Perf = 17 1652.29 3048 3190 20.5 4490 56 11:22:46 Other Slow Down For Dart 1750.58 2444 2705 20.3 3676 57 11:25:17 Alarm Delta Stage At Top Perf = 18 1789.68 2249 2481 15.1 3424 58 11:25:40 Ball on Seat Dart on Seat 1795.22 2247 2489 15.1 3416 59 11:25:47 Break Formation Break Formation 1796.99 4521 4808 15.1 6012 60 11:27:32 Alarm Delta Stage At Top Perf = 1 1825.8 3211 3418 20.2 4230 61 11:30:02 Alarm Delta Stage At Top Perf = 2 1876.12 2700 2931 20.2 3853 62 11:31:46 Alarm Delta Stage At Top Perf = 3 1911.25 2693 2855 20.3 3971 63 11:40:35 ISIP ISIP 2087.65 1114 1184 0 2866 64 12:29:12 Open Well Open Well 2087.65 964 965 0 2744 65 12:29:45 Alarm Delta Stage At Top Perf = 4 2089.15 1244 1332 5.7 3027 66 12:35:58 Other 1st Tracer Drop 2203.63 2059 2316 20.6 3377 67 12:41:20 Alarm Delta Stage At Top Perf = 6 2313.83 2413 2682 20.4 3603 68 12:44:15 Alarm Delta Stage At Top Perf = 7 2373.49 2666 2930 20.5 3853 69 12:54:39 Alarm Delta Stage At Top Perf = 8 2585.65 2553 2859 20.3 3885 70 13:01:50 Alarm Delta Stage At Top Perf = 9 2730.88 2502 2844 20.1 3963 71 13:05:10 Alarm Delta Stage At Top Perf = 10 2797.98 2506 2835 20.1 4036 72 13:08:02 Other 2nd Tracer Drop 2855.58 2547 2891 20.1 4090 73 0.549409722 Alarm Delta Stage At Top Perf = 11 2918.11 2556 2916 20.1 4131 74 13:17:22 Alarm Delta Stage At Top Perf = 12 3042.74 2620 2953 20 4193 75 13:27:35 Alarm Delta Stage At Top Perf = 13 3246.78 2605 3000 19.9 4244 76 13:34:16 Other 3rd Tracer Drop 3379.42 2620 3009 19.8 4282 77 13:37:10 Alarm Delta Stage At Top Perf = 14 3437.37 2636 3044 20.1 4335 78 13:40:48 Drop Ball Drop Dart for Interval 03 3511.3 3099 3363 20.5 4389 79 13:40:48 Stop Pumping Stop Pumping 3511.3 3101 3359 20.5 4391 80 13:40:50 Start Pumping Start Pumping 3511.98 3100 3352 20.5 4385 3 13:40:50 (07/02/25) Next Treatment Treatment Interval 3 3511.98 3101 3353 20.5 4388 81 13:43:30 Alarm Delta Stage At Top Perf = 15 3566.61 2870 3051 20.5 4314 82 13:49:49 Ball on Seat Dart on Seat 3695.84 2236 2510 20.6 3453 83 13:49:51 Break Formation Break Formation 3696.87 2522 2732 20.6 3996 84 13:49:59 Alarm Delta Stage At Top Perf = 16 3699.26 2341 2608 20.6 3573 85 13:51:30 Alarm Delta Stage At Top Perf = 1 3730.49 2171 2442 20.5 3415 86 13:54:00 Alarm Delta Stage At Top Perf = 2 3781.93 2322 2606 20.6 3599 87 13:56:08 Alarm Delta Stage At Top Perf = 3 3825.78 2492 2780 20.5 3753 88 14:06:32 Alarm Delta Stage At Top Perf = 4 4038.12 2386 2675 20.3 3733 89 14:13:44 Alarm Delta Stage At Top Perf = 5 4183.85 2267 2644 20.1 3803 90 14:17:04 Alarm Delta Stage At Top Perf = 6 4250.87 2270 2585 20.1 3869 91 14:19:28 Other 2nd Tracer Drop 4298.81 2308 2676 20.1 3906 92 14:23:05 Alarm Delta Stage At Top Perf = 7 4371.65 2318 2669 20.1 3958 93 14:29:21 Alarm Delta Stage At Top Perf = 8 4497.4 2393 2737 20 4018 94 14:39:35 Alarm Delta Stage At Top Perf = 9 4702.04 2411 2789 19.9 4072 95 14:45:33 Other 3rd Tracer Drop 4820.62 2463 2865 19.9 4120 96 14:49:11 Alarm Delta Stage At Top Perf = 10 4893.17 2503 2924 20.3 4213 97 14:52:47 Stop Pumping Stop Pumping 4966.8 2991 3230 20.6 4283 98 14:52:48 Drop Ball Drop Dart for Interval 04 4967.14 2993 3224 20.6 4280 99 14:52:49 Start Pumping Start Pumping 4967.48 2992 3227 20.6 4279 4 14:52:49 (07/02/25) Next Treatment Treatment Interval 4 4967.83 2992 3228 20.6 4279 100 14:55:28 Alarm Delta Stage At Top Perf = 11 5022.44 2764 2981 20.6 4204 101 15:01:25 Alarm Delta Stage At Top Perf = 12 5144.78 2233 2541 20.5 3374 102 15:01:26 Ball on Seat Dart on Seat 5144.78 2233 2540 20.5 3378 103 15:01:32 Break Formation Break Formation 5146.83 5372 5561 20.5 6560 104 15:03:05 Alarm Delta Stage At Top Perf = 1 5178.89 2765 3023 20.5 3834 105 15:05:33 Alarm Delta Stage At Top Perf = 2 5229.46 2852 3157 20.5 3985 106 15:06:31 Alarm Delta Stage At Top Perf = 3 5249.29 2944 3266 20.5 4077 107 15:08:45 Other 1st Tracer Drop 5294.99 3075 3355 20.4 4172 108 15:16:55 Alarm Delta Stage At Top Perf = 4 5461.41 2821 3135 20.3 4046 109 15:24:04 Alarm Delta Stage At Top Perf = 5 5606 2627 2992 20.2 4029 110 15:27:23 Alarm Delta Stage At Top Perf = 6 5672.77 2595 2992 20.1 4075 111 15:33:04 Alarm Delta Stage At Top Perf = 7 5786.85 2637 3018 20.1 4154 112 15:36:26 Other 2nd Tracer Drop 5854.4 2685 3090 20 4195 113 15:39:38 Alarm Delta Stage At Top Perf = 8 5918.56 2708 3064 20 4209 114 15:49:51 Alarm Delta Stage At Top Perf = 9 6122.97 2614 2954 20 4217 115 15:59:28 Alarm Delta Stage At Top Perf = 10 6314.69 2558 2903 19.9 4198 5 16:03:30 (07/02/25) Next Treatment Treatment Interval 5 6397.17 3006 3262 20.6 4239 116 16:03:30 Drop Ball Drop Dart for Interval 5 6397.17 3006 3262 20.6 4239 117 16:05:45 Alarm Delta Stage At Top Perf = 11 6443.79 2830 3038 20.6 4215 118 16:11:47 Alarm Delta Stage At Top Perf = 12 6567.99 2213 2463 20.5 3386 119 16:11:49 Ball on Seat Dart on Seat 6568.33 2214 2466 20.6 3385 120 16:11:57 Break Formation Break Formation 6571.07 4219 4449 20.5 5465 121 16:13:22 Alarm Delta Stage At Top Perf = 1 6600.49 2709 2953 20.6 3812 122 16:15:48 Alarm Delta Stage At Top Perf = 2 6650.57 2668 2916 20.6 3824 123 16:16:58 Alarm Delta Stage At Top Perf = 3 6674.59 2750 2999 20.6 3930 124 16:27:20 Alarm Delta Stage At Top Perf = 4 6886.83 2514 2767 20.4 3765 125 16:34:31 Alarm Delta Stage At Top Perf = 5 7032.6 2300 2602 20.2 3741 126 16:37:50 Alarm Delta Stage At Top Perf = 6 7099.65 2244 2554 20.2 3775 127 16:43:06 Other 2nd Tracer Drop 7206.04 2267 2570 20.2 3839 128 16:43:45 Alarm Delta Stage At Top Perf = 7 7219.14 2273 2594 20.2 3861 129 16:49:58 Alarm Delta Stage At Top Perf = 8 7344.12 2357 2721 20.1 3931 130 17:00:12 Alarm Delta Stage At Top Perf = 9 7549.17 2400 2736 20 3983 131 17:09:51 Alarm Delta Stage At Top Perf = 10 7741.97 2420 2727 20 4039 6 17:14:06 (07/02/25) Next Treatment Treatment Interval 6 7828.8 2886 3087 20.7 4079 132 17:14:06 Drop Ball Drop Dart for Interval 06 7829.14 2886 3089 20.7 4077 133 17:14:08 Stop Pumping Stop Pumping 7829.49 2890 3094 20.6 4097 134 17:14:09 Start Pumping Start Pumping 7830.17 2891 3100 20.7 4102 135 17:16:08 Alarm Delta Stage At Top Perf = 11 7871.05 2760 2982 20.6 4063 136 17:21:41 Alarm Delta Stage At Top Perf = 12 7985.56 1876 2074 20.7 3386 137 17:22:10 Ball on Seat Ball on Seat 7995.21 1831 2024 20.7 3341 138 17:22:17 Break Formation Break Formation 7997.96 4087 4315 20.6 5869 139 17:22:52 Other Start DFIT 8009.61 1195 1270 20.3 3544 140 17:25:17 Alarm Delta Stage At Top Perf = 1 8024.37 1216 1277 5.9 2959 141 17:27:00 ISIP ISIP 8033.92 942 1025 1.1 2813 142 17:32:04 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 8034.14 52 109 0 2790 143 17:36:53 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 8034.14 -2 23 0 2772 144 17:41:55 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 8034.14 -2 23 0 2772 Event Log 7.2.25 Conoco Phillips - 3S-705 Event Log 7.2 120 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 06:30:00 (07/03/25) Pre-Job Safety Meeting Pre-Job Safety Meeting ---- ---- ---- ---- ---- 2 6:47:01 Start Job Starting Job 0 0 0 0 0 1 06:47:01 (07/03/25) Next Treatment Treatment Interval 1 0 0 0 0 1 6 06:47:12 (07/03/25) Next Treatment Treatment Interval 6 0 11 -1 0 2288 3 7:05:15 Other Loop Test 0 -19 -1 0 2286 4 7:13:11 Prime Pumps Prime Pumps 0 80 89 0 2285 5 7:25:56 Pressure Test ePRV - Primary Tubing 0 1052 1065 0 2284 6 7:27:45 Pressure Test ePRV - Primary IA 0 1299 1361 0 2284 7 7:31:50 Pressure Test ePRV - Secondary Tubing 0 1585 1632 0 2283 8 7:33:56 Pressure Test ePRV - Secondary IA 0 522 803 0 2283 9 7:36:16 Pressure Test Pressure Test - Global 0 89 87 0 2283 10 7:36:21 Pressure Test Pressure Test - Locals 0 89 88 0 2283 11 7:38:39 Pressure Test Pressure Test - Max 0 9544 9634 0 2283 12 7:43:42 Pressure Test Pressure Test - Pass 0 9529 9595 0 2282 13 8:29:47 Open Well Open Well 0 685 675 0 2473 14 8:40:35 Start Pad Start Pad 140.74 1854 1983 16.4 3419 15 8:43:19 Alarm Delta Stage At Top Perf = 1 195.55 2178 2443 20.2 3484 16 8:43:20 Alarm Delta Stage At Top Perf = 2 195.89 2179 2440 20.2 3480 17 8:43:21 Alarm Delta Stage At Top Perf = 7 196.22 2179 2438 20.2 3487 18 8:50:19 Alarm Delta Stage At Top Perf = 8 336.49 2788 3052 20.1 3839 19 9:02:22 Other Debris in Pumps 578.49 2763 2940 18.8 3818 20 9:04:21 Alarm Delta Stage At Top Perf = 9 617.09 2824 3097 20.1 3941 21 9:11:40 Alarm Delta Stage At Top Perf = 10 763.33 2613 2902 19.9 3939 22 9:15:04 Alarm Delta Stage At Top Perf = 11 830.87 2583 2923 19.9 4025 23 9:20:52 Other 2nd Tracer Drop 945.61 2575 2873 19.8 4053 24 9:21:09 Alarm Delta Stage At Top Perf = 12 951.55 2562 2854 19.8 4046 25 9:27:28 Alarm Delta Stage At Top Perf = 13 1076.73 2562 2884 19.8 4093 26 9:37:57 Alarm Delta Stage At Top Perf = 14 1283.28 2483 2814 19.7 4105 27 9:42:27 Stop Pumping Stop Pumping 1374.35 2960 3087 20.3 4159 28 9:42:28 Drop Ball Drop Dart for Interval 07 1374.69 2959 3086 20.3 4152 29 9:42:29 Start Pumping Start Pumping 1375.03 2959 3086 20.3 4151 7 09:42:35 (07/03/25) Next Treatment Treatment Interval 7 1377.06 2948 3075 20.3 4158 30 9:42:36 Alarm Delta Stage At Top Perf = 15 1377.4 2948 3074 20.3 4151 31 9:45:36 Alarm Delta Stage At Top Perf = 16 1438.49 2606 2701 20.5 4024 32 9:49:53 Alarm Delta Stage At Top Perf = 17 1525.52 2218 2442 20.3 3465 33 9:50:11 Ball on Seat Dart on Seat 1531.61 2211 2436 20.2 3431 34 9:50:18 Break Formation Break Formation 1533.97 4294 4571 20.2 5580 35 9:51:50 Alarm Delta Stage At Top Perf = 1 1564.96 2163 2379 20.2 3265 36 9:54:17 Alarm Delta Stage At Top Perf = 2 1614.59 2304 2525 20.2 3425 37 9:55:14 Alarm Delta Stage At Top Perf = 3 1633.79 2353 2584 20.2 3484 38 10:05:45 Alarm Delta Stage At Top Perf = 4 1846.46 2295 2535 20.2 3487 39 10:13:06 Alarm Delta Stage At Top Perf = 5 1994.18 2068 2357 20.1 3487 40 10:16:26 Alarm Delta Stage At Top Perf = 6 2060.8 2058 2335 20 3542 41 10:21:08 Other 2nd Tracer Drop 2154.46 2046 2355 19.9 3573 42 10:22:29 Alarm Delta Stage At Top Perf = 7 2181.29 2021 2334 19.9 3586 43 10:28:50 Alarm Delta Stage At Top Perf = 8 2307.37 2083 2389 19.9 3637 44 10:39:16 Alarm Delta Stage At Top Perf = 9 2513.55 2086 2402 19.7 3660 45 10:46:09 Other 3rd Tracer Drop 2649.13 2058 2387 19.7 3678 46 10:49:01 Alarm Delta Stage At Top Perf = 10 2705.38 2073 2413 19.6 3717 8 10:54:15 (07/03/25) Next Treatment Treatment Interval 8 2810.39 2542 2687 20.3 3768 47 10:54:15 Drop Ball Drop Dart for Interval 08 2810.73 2542 2686 20.3 3767 48 10:55:24 Alarm Delta Stage At Top Perf = 11 2834.12 2451 2565 20.4 3775 49 11:01:23 Alarm Delta Stage At Top Perf = 12 2956.21 1837 2062 20.3 3153 50 11:01:34 Ball on Seat Dart on Seat 2959.94 1835 2068 20.3 3138 51 11:01:37 Break Formation Break Formation 2960.62 2800 2255 20.3 4249 52 11:08:05 Alarm Delta Stage At Top Perf = 1 2990.67 2168 2269 10.7 3389 53 11:29:37 Other Resuming Pumping 3027.09 772 58 0 2659 54 11:32:36 Alarm Delta Stage At Top Perf = 2 3040.37 2025 2193 15.9 3594 55 11:34:02 Alarm Delta Stage At Top Perf = 3 3068.5 2114 2310 20.4 3520 56 11:41:37 Alarm Delta Stage At Top Perf = 4 3222.45 2013 2290 20.3 3247 57 11:43:20 Alarm Delta Stage At Top Perf = 5 3257.16 2151 2411 20.2 3354 58 11:53:49 Alarm Delta Stage At Top Perf = 6 3469.03 2205 2486 20.2 3443 59 12:01:04 Alarm Delta Stage At Top Perf = 7 3614.69 1958 2280 20 3432 60 12:04:23 Alarm Delta Stage At Top Perf = 8 3680.87 1937 2269 19.9 3478 61 12:09:36 Other 2nd Tracer Drop 3784.33 1918 2260 19.8 3496 62 12:10:28 Alarm Delta Stage At Top Perf = 9 3801.84 1914 2240 19.8 3497 63 12:16:51 Alarm Delta Stage At Top Perf = 10 3928.49 1946 2279 19.8 3538 64 12:27:17 Alarm Delta Stage At Top Perf = 11 4134.71 1894 2275 19.7 3567 65 12:37:12 Alarm Delta Stage At Top Perf = 12 4329.81 1919 2337 19.6 3615 66 12:42:08 Drop Ball Drop Dart for Interval 9 4429.16 2367 2537 20.4 3656 9 12:42:09 (07/03/25) Next Treatment Treatment Interval 9 4429.85 2367 2536 20.4 3652 67 12:43:34 Alarm Delta Stage At Top Perf = 13 4458.75 2253 2448 20.4 3651 68 12:48:56 Alarm Delta Stage At Top Perf = 14 4568.27 1741 2026 20.2 3107 69 12:49:04 Ball on Seat Dart on Seat 4570.63 1740 2031 20.3 3091 70 0.53412037 Break Formation Break Formation 4571.98 3407 3689 20.2 4771 71 12:50:37 Alarm Delta Stage At Top Perf = 1 4602.32 1928 2265 20.2 3153 72 12:53:05 Alarm Delta Stage At Top Perf = 2 4652.26 2002 2271 20.2 3216 73 12:54:18 Alarm Delta Stage At Top Perf = 3 4676.88 2088 2383 20.2 3314 74 12:54:36 Other 1st Tracer Drop 4682.62 2103 2389 20.2 3324 75 13:04:51 Alarm Delta Stage At Top Perf = 4 4890.65 2063 2345 20.2 3336 76 13:12:07 Alarm Delta Stage At Top Perf = 5 5036.88 1876 2204 20.1 3349 77 13:15:34 Alarm Delta Stage At Top Perf = 6 5105.82 1897 2280 19.9 3397 78 13:21:38 Alarm Delta Stage At Top Perf = 7 5225.84 1990 2391 19.8 3501 79 13:21:57 Other 2nd Tracer Drop 5232.1 1983 2396 19.8 3506 80 13:27:58 Alarm Delta Stage At Top Perf = 8 5351.08 2046 2444 19.8 3578 81 13:38:23 Alarm Delta Stage At Top Perf = 9 5556.69 2033 2467 19.7 3623 82 13:48:05 Alarm Delta Stage At Top Perf = 10 5747.24 2079 2484 19.6 3680 83 13:53:30 Stop Pumping Stop Pumping 5856.26 2487 2685 20.4 3708 84 13:53:32 Drop Ball Drop Dart for Interval 10 5856.93 2485 2683 20.4 3709 85 13:53:32 Stop Pumping Stop Pumping 5856.93 2484 2681 20.4 3715 10 13:53:33 (07/03/25) Next Treatment Treatment Interval 10 5857.27 2482 2687 20.4 3714 86 13:54:28 Alarm Delta Stage At Top Perf = 11 5875.95 2420 2622 20.4 3711 87 14:00:06 Alarm Delta Stage At Top Perf = 12 5990.99 1759 2060 20.3 3094 88 14:00:08 Ball on Seat Dart on Seat 5991.32 1759 2066 20.3 3088 89 14:00:16 Break Formation Break Formation 5994.36 6885 7087 20.1 7663 90 14:01:52 Alarm Delta Stage At Top Perf = 1 6022.37 2739 3026 20.2 3845 91 14:04:20 Alarm Delta Stage At Top Perf = 2 6072.19 2446 2773 20.2 3586 92 14:05:25 Alarm Delta Stage At Top Perf = 3 6094.06 2503 2828 20.2 3618 93 14:06:13 Other 1st Tracer Drop 6110.19 2524 2833 20.2 3631 94 14:15:56 Alarm Delta Stage At Top Perf = 4 6306.66 2277 2613 20.2 3451 95 14:23:13 Alarm Delta Stage At Top Perf = 5 6453.1 1955 2308 20 3372 96 14:26:35 Alarm Delta Stage At Top Perf = 6 6520.36 1953 2360 19.9 3394 97 14:32:37 Alarm Delta Stage At Top Perf = 7 6640.42 1910 2304 19.9 3438 98 14:38:30 Other 2nd Tracer Drop 6757.1 1798 2151 19.8 3427 99 14:38:57 Alarm Delta Stage At Top Perf = 8 6766.02 1790 2186 19.8 3416 100 14:49:22 Alarm Delta Stage At Top Perf = 9 6971.85 1757 2139 19.8 3414 101 14:49:56 Other 3rd Tracer Drop 6982.71 1750 2134 19.7 3398 102 14:59:03 Alarm Delta Stage At Top Perf = 10 7162.35 1732 2150 19.6 3428 11 15:05:15 (07/03/25) Next Treatment Treatment Interval 11 7286.66 2174 2378 20.4 3468 103 15:05:15 Drop Ball Drop Dart for Interval 11 7286.66 2174 2378 20.4 3468 104 15:05:24 Alarm Delta Stage At Top Perf = 11 7290.06 2185 2397 20.4 3487 105 15:11:22 Alarm Delta Stage At Top Perf = 12 7411.99 1621 1953 20.3 3037 106 15:11:27 Ball on Seat Dart on Seat 7413.34 1624 1932 20.3 3035 107 15:11:36 Break Formation Break Formation 7416.39 4639 5021 20.2 6167 108 15:12:57 Alarm Delta Stage At Top Perf = 1 7444 2082 2383 20.2 3383 109 15:15:26 Alarm Delta Stage At Top Perf = 2 7494.21 2100 2397 20.2 3316 110 15:16:20 Alarm Delta Stage At Top Perf = 3 7512.4 2186 2487 20.2 3441 111 15:27:18 Alarm Delta Stage At Top Perf = 4 7734.09 1964 2271 20.2 3249 112 15:34:31 Alarm Delta Stage At Top Perf = 5 7879.81 1759 2109 20.1 3226 113 15:37:52 Alarm Delta Stage At Top Perf = 6 7947.08 1747 2115 20 3252 114 15:43:53 Alarm Delta Stage At Top Perf = 7 8067.25 1703 2085 19.9 3272 115 15:47:16 Other 2nd Tracer Drop 8134.23 1675 2052 19.9 3283 116 15:50:11 Alarm Delta Stage At Top Perf = 8 8192.54 1700 2056 19.9 3297 117 16:00:35 Alarm Delta Stage At Top Perf = 9 8398.23 1686 2051 19.8 3324 118 16:10:18 Alarm Delta Stage At Top Perf = 10 8589.47 1695 2095 19.6 3353 119 16:17:10 Alarm Delta Stage At Top Perf = 11 8727.56 1999 2183 20.4 3394 120 16:22:11 Alarm Delta Stage At Top Perf = 12 8824.01 667 716 4.7 2578 121 16:22:14 ISIP ISIP 8824.1 782 900 2.2 2729 122 16:27:12 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 8824.16 557 718 0 2708 123 16:32:15 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 8824.16 -57 12 0 2697 124 16:37:17 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 8824.16 -10 62 0 2686 Event Log 7.3.25 Conoco Phillips - 3S-705 Event Log 7.3 121 Seq No. Time Activity Code Comment Job Slurry Vol Treating Pressure Treating Pressure @Pump Slurry Rate Tubing Gauge BH Pres 1 06:52:55 (07/04/25) Start Job Starting Job 0 0 0 0 0 1 06:52:55 (07/04/25) Next Treatment Treatment Interval 1 0 0 0 0 0 12 06:53:09 (07/04/25) Next Treatment Treatment Interval 12 0 2 0 0 0 2 7:11:54 Pressure Test Pressure Test 0 103 130 0 1976 3 7:22:49 Pressure Test ePRV - Primary Tubing 0 1197 1221 0 1976 4 7:24:35 Pressure Test ePRV - Primary IA 0 877 932 0 1976 5 7:26:46 Pressure Test ePRV - Secondary Tubing 0 762 841 0 1976 6 7:27:47 Pressure Test ePRV - Secondary IA 0 943 995 0 1976 7 7:31:25 Pressure Test Pressure Test - Global 0 399 447 0 1976 8 7:31:32 Pressure Test Pressure Test - Locals 0 422 477 0 1976 9 7:33:47 Pressure Test Pressure Test - Max 0 9515 9610 0 1976 10 7:40:14 Pressure Test Pressure Test - Pass 0 9487 9554 0 1976 11 8:20:12 Open Well Open Well 0 456 433 0 2017 12 8:23:06 Drop Ball Drop Dart for Interval 12 27.42 1735 1807 15.7 3071 13 8:30:11 Alarm Delta Stage At Top Perf = 4 149.64 1859 2111 20.1 3058 14 8:30:20 Ball on Seat Dart on Seat 152.66 1858 2120 20.1 3032 15 8:30:27 Break Formation Break Formation 154.67 5011 5166 20.1 5846 16 8:32:41 Alarm Delta Stage At Top Perf = 5 199.73 2891 3154 20 3969 17 8:34:03 Alarm Delta Stage At Top Perf = 6 227.09 3073 3336 20 4134 18 8:44:39 Alarm Delta Stage At Top Perf = 7 439.85 3019 3268 20.2 4106 19 8:45:10 Other Cut 100 Mesh 450.25 3005 3243 20.2 4082 20 8:46:00 Other Start Flush 466.81 3042 3223 20.3 4086 21 8:53:21 Alarm Delta Stage At Top Perf = 8 616.56 870 913 19 3247 22 8:53:27 ISIP ISIP 617.11 1142 1215 1.6 2822 23 8:53:45 Other Shut Down to Load Back Up Dart 617.38 989 1030 0.8 2816 24 9:20:34 Open Well Open Well 617.46 916 899 0 2678 25 9:22:50 Drop Ball Drop Dartv2 for Interval 12 639.53 1488 1579 15.6 3073 26 9:30:47 Ball on Seat Dart on Seat 763.03 1632 1879 15.4 3045 27 9:30:57 Break Formation Break Formation 765.59 5640 5995 15.3 7110 28 9:31:03 Alarm Delta Stage At Top Perf = 9 767.11 4531 4823 15.2 5965 29 9:33:38 Alarm Delta Stage At Top Perf = 10 812.95 2928 3142 20.1 3933 30 9:37:14 Alarm Delta Stage At Top Perf = 11 885.38 2394 2629 20.1 3434 31 9:47:47 Alarm Delta Stage At Top Perf = 12 1097.79 2171 2405 20.2 3308 32 9:55:06 Alarm Delta Stage At Top Perf = 13 1244.32 1804 2117 20 3196 33 9:58:29 Alarm Delta Stage At Top Perf = 14 1311.87 1808 2130 19.9 3208 34 10:04:35 Alarm Delta Stage At Top Perf = 15 1433.17 1772 2089 19.9 3226 35 10:05:09 Other 2nd Tracer Drop 1444.1 1753 2073 19.9 3229 36 10:10:57 Alarm Delta Stage At Top Perf = 16 1559.48 1728 2024 19.8 3262 37 10:21:28 Alarm Delta Stage At Top Perf = 17 1767.7 1709 2051 19.8 3271 38 10:31:12 Alarm Delta Stage At Top Perf = 18 1960.33 1713 2076 19.7 3307 39 10:32:02 Other 3rd Tracer Drop 1976.79 1721 2072 19.7 3306 13 10:37:09 (07/04/25) Next Treatment Treatment Interval 13 2080.25 2134 2265 20.4 3315 40 10:37:13 Stop Pumping Stop Pumping 2081.61 2133 2266 20.4 3315 41 10:37:14 Drop Ball Drop Dart for Interval 13 2081.95 2134 2266 20.4 3315 42 10:37:15 Stop Pumping Stop Pumping 2082.29 2133 2267 20.4 3315 43 10:37:34 Alarm Delta Stage At Top Perf = 19 2088.76 2104 2235 20.4 3315 44 10:42:39 Alarm Delta Stage At Top Perf = 20 2189.54 1449 1672 15.5 2936 45 10:43:03 Ball on Seat Dart on Seat 2195.76 1445 1670 15.5 2914 46 10:43:08 Break Formation Break Formation 2197.06 3378 3738 15.5 5131 47 10:44:35 Alarm Delta Stage At Top Perf = 1 2222.25 1971 2179 20.4 3218 48 10:47:02 Alarm Delta Stage At Top Perf = 2 2272.2 1954 2165 20.4 3086 49 10:48:11 Alarm Delta Stage At Top Perf = 3 2295.65 2022 2250 20.4 3147 50 10:49:32 Other 1st Tracer Drop 2323.1 1961 2215 20.3 3090 51 10:59:53 Alarm Delta Stage At Top Perf = 4 2532.85 1804 2058 20.2 3004 52 11:07:09 Alarm Delta Stage At Top Perf = 5 2679.41 1598 1910 20.1 3002 53 11:10:30 Alarm Delta Stage At Top Perf = 6 2746.77 1595 1935 20 3025 54 11:16:32 Alarm Delta Stage At Top Perf = 7 2867.56 1535 1883 20 3056 55 11:19:30 Other 2nd Tracer Drop 2926.41 1511 1846 20 3075 56 11:22:50 Alarm Delta Stage At Top Perf = 8 2993.18 1520 1867 19.9 3082 57 11:33:13 Alarm Delta Stage At Top Perf = 9 3199.54 1482 1846 19.9 3095 58 11:42:52 Alarm Delta Stage At Top Perf = 10 3391.02 1507 1850 19.8 3122 59 11:49:40 Alarm Delta Stage At Top Perf = 11 3528.14 1907 2090 20.4 3154 60 11:49:57 Stop Pumping Stop Pumping 3533.93 1908 2084 20.4 3159 61 11:49:59 Drop Ball Drop Dart for Interval 14 3534.27 1906 2084 20.4 3160 62 11:50:00 Start Pumping Start Pumping 3534.61 1904 2078 20.4 3161 14 11:50:01 (07/04/25) Next Treatment Treatment Interval 14 3534.95 1904 2078 20.4 3163 63 11:54:56 Alarm Delta Stage At Top Perf = 12 3634.25 1230 1475 15.7 2842 64 11:55:21 Ball on Seat dart on Seat 3640.52 1231 1481 15.6 2811 65 11:55:26 Break Formation Break Formation 3642.09 3505 3873 15.6 5014 66 11:57:02 Alarm Delta Stage At Top Perf = 1 3669.24 1682 1896 20.5 3024 67 11:59:39 Alarm Delta Stage At Top Perf = 2 3722.67 1662 1945 20.4 2876 68 12:01:21 Alarm Delta Stage At Top Perf = 3 3757.28 1809 2095 20.3 3008 69 12:01:53 Other 1st Tracer Drop 3768.13 1833 2092 20.3 3004 70 12:11:49 Alarm Delta Stage At Top Perf = 4 3969.86 1775 2048 20.3 2994 71 0.513263889 Alarm Delta Stage At Top Perf = 5 4117.08 1574 1887 20.2 3008 72 12:22:22 Alarm Delta Stage At Top Perf = 6 4182.97 1575 1884 20.1 3018 73 12:28:22 Alarm Delta Stage At Top Perf = 7 4303.46 1497 1820 20 3024 74 12:34:42 Alarm Delta Stage At Top Perf = 8 4429.93 1470 1792 20 3043 75 12:45:03 Alarm Delta Stage At Top Perf = 9 4636.45 1422 1762 19.9 3030 76 12:54:41 Alarm Delta Stage At Top Perf = 10 4828.08 1441 1833 19.9 3054 77 13:01:24 Alarm Delta Stage At Top Perf = 11 4963.48 1872 2104 20.5 3114 78 13:02:20 Stop Pumping Stop Pumping 4982.63 1925 2160 20.5 3121 79 13:02:22 Drop Ball Drop Dart for Interval 15 4983.31 1924 2162 20.5 3125 80 13:02:23 Start Pumping Start Pumping 4983.66 1926 2167 20.5 3120 15 13:02:23 (07/04/25) Next Treatment Treatment Interval 15 4983.66 1926 2167 20.5 3120 81 13:06:52 Alarm Delta Stage At Top Perf = 12 5073.8 1220 1478 15.7 2864 82 13:07:21 Ball on Seat Dart on Seat 5081.37 1227 1515 15.6 2828 83 13:07:28 Break Formation Break Formation 5083.19 3487 3765 15.6 5202 84 13:09:03 Alarm Delta Stage At Top Perf = 1 5110.26 1831 2104 20.5 3207 85 13:11:38 Alarm Delta Stage At Top Perf = 2 5163.08 1760 2037 20.4 2979 86 13:13:24 Alarm Delta Stage At Top Perf = 3 5199.19 1865 2141 20.4 3062 87 13:16:05 Other 1st Tracer Drop 5253.93 1796 2078 20.4 3012 88 13:23:48 Alarm Delta Stage At Top Perf = 4 5411.54 1727 2009 20.5 2987 89 13:31:02 Alarm Delta Stage At Top Perf = 5 5558.61 1517 1824 20.2 2958 90 13:34:20 Alarm Delta Stage At Top Perf = 6 5625.27 1481 1824 20.2 2962 91 13:40:20 Alarm Delta Stage At Top Perf = 7 5745.75 1389 1742 20.1 2955 92 13:46:39 Alarm Delta Stage At Top Perf = 8 5872.31 1349 1709 20.1 2967 93 13:56:49 Alarm Delta Stage At Top Perf = 9 6075.72 1291 1645 20 2944 94 14:06:21 Alarm Delta Stage At Top Perf = 10 6265.78 1305 1684 19.9 2970 95 14:13:02 Alarm Delta Stage At Top Perf = 11 6400.42 1603 1863 20.5 2981 96 14:14:15 Stop Pumping Stop Pumping 6425.33 1696 1972 20.5 2987 97 14:14:16 Drop Ball Drop Dart for Interval 16 6425.67 1696 1972 20.5 2987 16 14:14:17 (07/04/25) Next Treatment Treatment Interval 16 6425.67 1697 1977 20.5 2987 98 14:14:18 Start Pumping Start Pumping 6426.01 1700 1979 20.5 2995 99 14:18:18 Alarm Delta Stage At Top Perf = 12 6507.94 1222 1402 15.8 2829 100 14:19:04 Ball on Seat Dart on Seat 6519.93 1223 1476 15.6 2810 101 14:19:09 Break Formation Break Formation 6520.97 3508 3583 15.5 5091 102 14:20:37 Alarm Delta Stage At Top Perf = 1 6544.68 1594 1907 19.5 3011 103 14:23:30 Alarm Delta Stage At Top Perf = 2 6603.35 1716 1972 20.4 2906 104 14:24:41 Alarm Delta Stage At Top Perf = 3 6627.48 1674 1930 20.4 2912 105 14:26:09 Other 1st Tracer Drop 6657.03 1624 1871 20.4 2878 106 14:36:04 Alarm Delta Stage At Top Perf = 4 6859.63 1505 1750 20.4 2832 107 14:43:15 Alarm Delta Stage At Top Perf = 5 7005.76 1334 1629 20.3 2815 108 14:46:36 Alarm Delta Stage At Top Perf = 6 7073.51 1256 1553 20.2 2815 109 14:52:31 Alarm Delta Stage At Top Perf = 7 7192.65 1160 1489 20.1 2817 110 14:58:46 Alarm Delta Stage At Top Perf = 8 7318.05 1096 1438 20.1 2808 111 15:01:04 Other 2nd Tracer Drop 7364.29 1113 1434 20.1 2812 112 15:09:03 Alarm Delta Stage At Top Perf = 9 7524.49 1083 1402 20 2805 113 15:18:36 Alarm Delta Stage At Top Perf = 10 7715.57 1067 1423 20 2825 114 15:25:19 Alarm Delta Stage At Top Perf = 11 7851.03 1283 1568 20.6 2839 115 15:31:09 ISIP ISIP 7968.14 849 922 0 2671 116 15:36:04 Shut-In Pressure @ 5 Minutes Shut-In Pressure @ 5 Minutes 7968.14 235 308 0 2653 117 15:41:04 Shut-In Pressure @ 10 Minutes Shut-In Pressure @ 10 Minutes 7968.14 117 169 0 2637 118 15:46:06 Shut-In Pressure @ 15 Minutes Shut-In Pressure @ 15 Minutes 7968.14 -29 23 0 2623 Event Log 7.4.25 Conoco Phillips - 3S-705 Event Log 7.4 122 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Test #1Test #2Test #3Test #4time (hr:min) -->00:00 01:00 02:00 03:00 04:00 05:00 10:00 15:00 20:00 25:00 30:00 45:00 1:00 1:15 1:30 1:45 2:00 2:15 2:30 2:45 3:00 3:30 4:00 4:30 5:00 5:30 6:00 6:30Test #1 (cp) -->4937 2716 2024 1728 2197 1901 2148 1975 2000 1605 1457 1605 1555 1481 1308 1284 1037 765 494 222 99 49 0 0 0 0 0 0Dial Reading200 110 82 70 89 77 87 80 81 65 59 65 63 60 53 52 42 31 20 9 4 2Test #2 (cp) -->4814 1391 1444 1284 1337 1070 1070 1284 1123 1284 1070 856 535 294 134 53 0 0 0000000000Dial Reading180 52 54 48 50 40 40 48 42 48 40 32 20 11 5 2Test #3 (cp) -->4948 1872 2006 1899 1631 1658 1872 1738 1471 2140 1444 1257 829 455 187 107 53 0 0 000000000Dial Reading185 70 75 71 61 62 70 65 55 80 54 47 31 17 7 4 2Test #4 (cp) -->0000000000000000000000000000Dial Reading3S-705 Stage(s): Break Test105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/4/2025ConocoPhillips Project No:D. MartinezHydration Visc: 21 88Temperature was held at 115 degres for the duration of the testAll chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0F PH LOSURF-300D WG-36 LoSurf MO-67 CAT-3 BC-140X2 OptiFlo-II0.45 2.001.00 0.12 1.00 0.45 2.0027.00 1.00 0.12 1.0091 8.79 1.0098 8.88 1.00 25.00 1.00 0.45 2.0093 8.84 1.00 22.000.12 1.00010002000300040005000600000:00 02:00 04:00 10:00 20:00 30:00 1:00 1:30 2:00 2:30 3:00 4:00 5:00 6:00Viscosity (cp)Time (min:sec)Prejob Crosslink Break Tests27# - Opti II @ 2.0 and CAT-3 @ 1.022# Opti II @ 2.0 and CAT-3 @ 1.025# Opti II @ 2.0 and CAT-3 @ 1.0Fluid is broken at 200cpConoco Phillips - 3S-705Prejob Break Test123 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 1105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/2/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH: 7.30CoyoteTemp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2790 8.78 1.000200400600800100012001400160000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 1 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Fann 15 Min Zone 1124 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 2105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/2/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH: 7.30CoyoteTemp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2791 8.80 1.0005001000150020002500300000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 2 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 2125 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 3105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/2/2025ConocoPhillips Project No:D. MartinezHydration Visc: 24 110All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH: 7.45Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2791 8.76 1.00050010001500200025003000350000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 3 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 3126 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad.50 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 4140 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/2/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2792 8.79 1.0005001000150020002500300000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 4 Crosslink Tests.50 ppg0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 4 127 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad.50 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 5105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/2/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2798 8.75 1.0005001000150020002500300000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 5 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 5128 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad.50 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 6105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/3/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0F PH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2787 8.82 1.000500100015002000250030003500400000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 6 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 6129 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 7105 Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/3/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2797 8.74 1.00050010001500200025003000350000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 7 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 7 130 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 8Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/3/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2799 8.82 1.000500100015002000250030003500400000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 8 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 8131 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 9Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/3/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2796 8.65 1.0005001000150020002500300035004000450000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 9 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 9132 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 10Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/3/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2791 8.80 1.000500100015002000250030003500400000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 10 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 10133 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 11Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/3/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2798 8.75 1.0005001000150020002500300035004000450000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 11 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 11134 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 12Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/4/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2791 8.74 1.00050010001500200025003000350000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 12 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 12135 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 13Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/4/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2799 8.73 1.0005001000150020002500300035004000450000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 13 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 13136 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 14Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/4/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2790 8.80 1.00050010001500200025003000350000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 14 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 14137 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 15Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/4/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 25102 8.84 1.000500100015002000250030003500400000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 15 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 15138 Company:Well Name:BHST (ºF):Depth:Formation:Analyst:cp @Lot Number--->Pad0.5 ppg 1 ppg 2 ppg3 ppg4 ppg3S-705 Stage(s): 16Water Source: CPF3ALASKA DISTRICT LABORATORY15 Minute Fann Model 35 Crosslinked Fluid ReportFluid System: Date: 7/4/2025ConocoPhillips Project No:D. MartinezHydration Visc:All chemical concentrations below are in gallons per thousand / pounds per thousandWater pH:Coyote Hydration pH:Temp 0FPH LOSURF-300D BC-140X2 CAT-3 MO-67 Optiflo-II WG-360.45 1.00 0.45 2.00 2595 8.74 1.000500100015002000250030003500400000:00 02:00 04:00 06:00 08:00 10:00 12:00 14:00Viscosity (cp)Time (min:sec)Zone 16 Crosslink TestsPad0.5 ppg2 ppg3 ppg4 ppg5 ppgFluid is broken at 200cpConoco Phillips - 3S-705Zone 16139 Company: Well: Sand Type Date Tested Total Sample Size Seive Weight Seive Weight 100.0 g Sieve Size Before Sand With sand WT. rtn'd % rtn'd % API Spec 12 355.0 355 0 0.0% 0.00% <0.1% 16 340.1 342 1.9 1.9% 18 303.3 391.7 88.4 88.4% 20 296.5 301.9 5.4 5.4% 25 419.4 421.3 1.9 1.9% 30 281.5 282.1 0.6 0.6% 40 407.6 409 1.4 1.4% Pan 306.6 306.7 0.1 0.1% 0.10% <1.0% Total: 99.7 100% Conoco Phillips 3S-705 16/20 Proppant 7/1/2025 Ceramic Proppant Sieves Sample: 16 / 20 - 7/1/2025 96.30% >/= 90% Conoco Phillips - 3S-705 Sand Sieve Analysis 140 Hydraulic Fracturing Fluid Product Component Information Disclosure 2025-07-02 Alaska HARRISON BAY 50-103-20915-00-00 CONOCOPHILLIPS 3S-705 3S-705 -150.19546820 70.39426745 NAD83 none Oil 4193 851409.95 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 (SG 8.52) Operator Base Fluid Density = 8.52 BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CAT-3 ACTIVATOR Halliburton Activator LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Ceramic Proppant - Wanli Wanli Proppant Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant Flow Insurance Brass Patina Energy Tracer OPT 2002-2054 ResMetrics Tracer WPT 1001-1052 ResMetrics Tracer Ingredients Water 7732-18-5 95.00%66.67141%7254013 Corundum 1302-74-5 60.00%17.37838%1890810 Mullite 1302-93-8 40.00%11.58559%1260540 Sodium chloride 7647-14-5 5.00%3.50915%381805 Crystalline silica, quartz 14808-60-7 100.00%0.44280%48178 Guar gum 9000-30-0 100.00%0.21361%23241 Water 7732-18-5 100.00%0.09271%10087 Ethanol 64-17-5 60.00%0.03835%4173 Monoethanolamine borate 26038-87-9 100.00%0.03520%3831 EDTA/Copper chelate Proprietary 30.00%0.02047%2227 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 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01917%2087 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.01917%2087 Ammonium persulfate 7727-54-0 100.00%0.01636%1780 Ethylene glycol 107-21-1 30.00%0.01056%1150 Oxyalkylated phenolic resin Proprietary 10.00%0.00639%696 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Oxylated phenolic resin Proprietary 30.00%0.00491%534 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Sodium hydroxide 1310-73-2 30.00%0.00388%423 Ammonium chloride 12125-02-9 5.00%0.00341%372 Naphthalene 91-20-3 5.00%0.00320%348 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00320%348 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00138%150 Glycol Ether Proprietary 85.00%0.00100%109 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Ammonia 7664-41-7 1.00%0.00068%75 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00064%70 Flow Insurance Brass Proprietary 100.00%0.00041%45 Patina Energy Julie Harrish julie@patinae nergy.com 8327140836 Confidential Proprietary 20.00%0.00036%39 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Ethylene Glycol 107-21-1 20.00%0.00024%27 C.I. pigment Orange 5 3468-63-1 1.00%0.00016%18 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1- naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00004%4 * 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 Fracture Date State: County: API Number: Operator Name: Well Name and Number: Longitude: Latitude: Long/Lat Projection: Indian/Federal: All component information listed was obtained from the supplier’s 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 Administration’s (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 Hydraulic Fracturing Fluid Product Component Information Disclosure Job Start Date: 07/02/2025 Job End Date: 07/04/2025 State: Alaska County: Harrison Bay API Number: 50-103-20915-00-00 Operator Name:ConocoPhillips Company/Burlington Resources Well Name and Number: 3S-705 Latitude: 70.394564 Longitude: -150.192333 Datum: NAD83 Federal Well: NO Indian Well: NO True Vertical Depth: 4213 Total Base Water Volume (gal)*: 851409.95 Total Base Non Water Volume: 0 Water Source Percent Other, > 1000TDS 100.00% 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)** Comments BC-140 X2 Halliburton Initiator BE-6(TM) Bactericide Halliburton Microbiocide CAT-3 ACTIVATOR Halliburton Activator Ceramic Proppant - Wanli Wanli Proppant Flow Insurance Brass Patina Energy Tracer LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPT 2002-2054 ResMetrics Tracer OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant SEAWATER (SG 8.52)Operator Base Fluid WG-36 GELLING AGENT Halliburton Gelling Agent WPT 1001- 1052 ResMetrics Tracer Items above are Trade Names. Items below are the individual ingredients. Water 7732-18-5 95.00000 66.66898 None Corundum 1302-74-5 60.00000 17.37774 None Mullite 1302-93-8 40.00000 11.58516 None Sodium chloride 7647-14-5 5.00000 3.50902 None Crystalline silica, quartz 14808-60-7 100.00000 0.44279 None Guar gum 9000-30-0 100.00000 0.21360 None Water 7732-18-5 100.00000 0.09270 None Ethanol 64-17-5 60.00000 0.03835 None Monoethanolamine borate 26038-87-9 100.00000 0.03520 None EDTA/Copper chelate Proprietary 30.00000 0.02047 None Heavy aromatic petroleum naphtha 64742-94-5 30.00000 0.01917 None Oxyalkylated nonyl phenolic resin Proprietary 30.00000 0.01917 None Ammonium persulfate 7727-54-0 100.00000 0.01636 None Ethylene glycol 107-21-1 30.00000 0.01056 None Oxyalkylated phenolic resin Proprietary 10.00000 0.00639 None Oxylated phenolic resin Proprietary 30.00000 0.00491 None Sodium hydroxide 1310-73-2 30.00000 0.00388 None Ammonium chloride 12125-02-9 5.00000 0.00341 None Poly(oxy-1,2-ethanediyl), alpha-(4-nonylphenyl)- omega-hydroxy-, branched 127087-87-0 5.00000 0.00320 None Naphthalene 91-20-3 5.00000 0.00320 None 2-Bromo-2-nitropropane- 1,3-diol 52-51-7 100.00000 0.00138 None Glycol Ether Proprietary 85.00000 0.00100 None Ammonia 7664-41-7 1.00000 0.00068 None 1,2,4 Trimethylbenzene 95-63-6 1.00000 0.00064 None Flow Insurance Brass Proprietary 100.00000 0.00041 None Confidential Proprietary 20.00000 0.00036 None Ethylene Glycol 107-21-1 20.00000 0.00024 None C.I. pigment Orange 5 3468-63-1 1.00000 0.00016 None 2,7-Naphthalenedisulfonic acid, 3-hydroxy-4-(4- sulfor-1-naphthalenyl) azo -, trisodium salt 915-67-3 0.10000 0.00004 None * Total Water Volume sources may include various types of water including fresh water, produced water, and 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. Ingredient information for chemicals subject to 29 CFR 1910.1200(i) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) Page 1/1 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 23.23 ] REPORT # [ 1] REPORT DATE: [ 6/26/2025] API / UWI 5010320915 Original KB/RT Elevation (ft) 48.00 Ground Elevation (ft) 22.90 Original Spud Date 6/3/2025 Job Category COMPLETIONS Primary Job Type INITIAL COMPLETION Total AFE (Cost) 6,610,068.00 AFE / RFE / Maint.# GKA.00183.E.W002.CO.I S;GKA.00183.E.W002.C O.IF;GKA.00183.E.W002. CO.IW Network/Order Number 10454643;50060721;500 60722 AFE+Supp Amt (Cost) 6,610,068.00 Daily Cost Total (Cost) 94,300.00 Cumulative Cost (Cost) 94,300.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary STAGE EQUIPMENT ON 3S 24hr Forecast BEGIN RIG UP General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile CAMPBELL, JAMES Frac Supervisor 661-203-1472 LAWSON, JACOB Supervisor 971-606-0075 Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 14:00 9.99 COMPZN, STIM RURD P MOBILIZE AND STAGE EQUIPMENT ON 3S 0.0 Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/26/2025 14:00 6/26/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/27/2025 00:00 6/27/2025 23:59 FRAC HES 046 ROGERS, BRENT,Wells Supervisor 6/28/2025 13:00 6/28/2025 20:00 SLICK LINE HES 046 ROGERS, BRENT,Wells Supervisor 6/29/2025 05:30 6/29/2025 09:00 SLICK LINE HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/30/2025 00:00 6/30/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/1/2025 00:00 7/1/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/2/2025 00:00 7/2/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/3/2025 00:00 7/3/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/4/2025 00:00 7/4/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/5/2025 00:00 7/5/2025 12:00 FRAC Offline Activities Type Subtype Des Start Date End Date FRAC Frac Equipment 6/28/2025 00:00 6/28/2025 23:59 FRAC Frac Equipment 6/29/2025 00:00 6/29/2025 23:59 PUMPING 44 6/28/2025 13:00 6/28/2025 19:00 PUMPING 44 6/29/2025 07:00 6/29/2025 09:00 Page 1/1 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 24.23 ] REPORT # [ 2] REPORT DATE: [ 6/27/2025] API / UWI 5010320915 Original KB/RT Elevation (ft) 48.00 Ground Elevation (ft) 22.90 Original Spud Date 6/3/2025 Job Category COMPLETIONS Primary Job Type INITIAL COMPLETION Total AFE (Cost) 6,610,068.00 AFE / RFE / Maint.# GKA.00183.E.W002.CO.I S;GKA.00183.E.W002.C O.IF;GKA.00183.E.W002. CO.IW Network/Order Number 10454643;50060721;500 60722 AFE+Supp Amt (Cost) 6,610,068.00 Daily Cost Total (Cost) 94,300.00 Cumulative Cost (Cost) 188,600.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary CONTIUE RIG IN, CREW SWAP 24hr Forecast General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile CAMPBELL, JAMES Frac Supervisor 661-203-1472 LAWSON, JACOB Supervisor 971-606-0075 Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 00:00 7.50 COMPZN, STIM RURD P RIG IN PUMPSAND SUCK SIDE 07:30 16.4 9 COMPZN, STIM RURD P CREW SWAP Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/26/2025 14:00 6/26/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/27/2025 00:00 6/27/2025 23:59 FRAC HES 046 ROGERS, BRENT,Wells Supervisor 6/28/2025 13:00 6/28/2025 20:00 SLICK LINE HES 046 ROGERS, BRENT,Wells Supervisor 6/29/2025 05:30 6/29/2025 09:00 SLICK LINE HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/30/2025 00:00 6/30/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/1/2025 00:00 7/1/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/2/2025 00:00 7/2/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/3/2025 00:00 7/3/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/4/2025 00:00 7/4/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/5/2025 00:00 7/5/2025 12:00 FRAC Offline Activities Type Subtype Des Start Date End Date FRAC Frac Equipment 6/28/2025 00:00 6/28/2025 23:59 FRAC Frac Equipment 6/29/2025 00:00 6/29/2025 23:59 PUMPING 44 6/28/2025 13:00 6/28/2025 19:00 PUMPING 44 6/29/2025 07:00 6/29/2025 09:00 Page 1/2 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 25.06 ] REPORT # [ 3] REPORT DATE: [ 6/28/2025] API / UWI 5010320915 Original KB/RT Elevation (ft) 48.00 Ground Elevation (ft) 22.90 Original Spud Date 6/3/2025 Job Category COMPLETIONS Primary Job Type INITIAL COMPLETION Total AFE (Cost) 6,610,068.00 AFE / RFE / Maint.# GKA.00183.E.W002.CO.I S;GKA.00183.E.W002.C O.IF;GKA.00183.E.W002. CO.IW Network/Order Number 10454643;50060721;500 60722 AFE+Supp Amt (Cost) 6,610,068.00 Daily Cost Total (Cost) 94,300.00 Cumulative Cost (Cost) 282,900.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary DRIFT 3.69'' GAUGE DEVIATED OUT @ 5785' RKB, SET 4-1/2 SS CATCHER @ 2390' RKB, PULL 1'' SOV IN ST#1 @ 2245' RKB, SET1'' INCONEL TOP SUB DMY IN ST#1 @ 2245' RKB, LRS PERFORM MIT-T TO 4200 PSI (GOOD TEST), LRS PERFORM MIT-IA TO 3850 (GOOD TEST), JOB IN PROGRESS 24hr Forecast General Remarks INITIAL T/I/O 0/0/0 FINAL T/I/O 250/250/0 ZX Code ZX50 Slickline / DSL Misc. (or Multiple Operations Contact Name Title Mobile BUQUET, JONATHAN Slickline Operator 985-232-2439 Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 13:00 0.25 COMPZN, STIM TRAV P NOTIFY DSO, MOVE OVER FROM 3S-08C, INSPECT LOC., SPOT IN EQUIPMENT, JSSM 13:15 0.50 COMPZN, STIM RURD P R/U .125 CARBON, 2-1/8'' RLR TS= RS, QC, 5', QC, KJ, 5', QC, OJ, QC, KJ, LSS, PT w/ LRS= 250L / 2500H, INSTALL FUSIBLE, NOTIFY DSO, ***TIME START @ 13:00*** 13:45 0.75 COMPZN, STIM SLKL P RIH w/ QC, 1-7/8 X 2' STEM, 3.69'' GAUGE, DEVIATED OUT @ 5750' SLM / 5785' RKB, POOH 14:30 0.75 COMPZN, STIM SLKL P RIG w/ QC, 4-1/2 GS (brass), 4-1/2 SS CATCHER, SET @ 2355' SLM / 2390' RKB, POOH 15:15 0.50 COMPZN, STIM SLKL P RIH w/ QC, KJ, 4-1/2 OK-1, 1-1/4 JDC (steel), LATCH & PULL 1'' SOV IN ST#1 @ 2215' SLM / 2245' RKB, POOH 15:45 0.50 COMPZN, STIM SLKL P RIH w/ QC, KJ, 4-1/2 OMK-1, GA-2 R/T, 1'' INCONEL TOP SUB DMY, SET IN ST#1 @ 2215' SLM / 2245' RKB, PRESSURE TUBING TO 1000 PSI, SHEAR OFF, POOH 16:15 1.75 COMPZN, STIM SLKL P LRS PERFORM MIT-T (FAILED TEST) PRE MIT T/I/O 275/150/0 INITIAL T/I/O 4225/450/0 15 MIN T/I/O 4100/450/0 30 MIN T/I/O 4025/450/0 RETEST MIT-T (GOOD TEST) PRE MIT T/I/O 4025/450/0 INITIAL T/I/O 4250/450/0 15 MIN T/I/O 4200/450/0 30 MIN T/I/O 4175/450/0 18:00 0.75 COMPZN, STIM SLKL P LRS PERFORM MIT-IA (GOOD TEST), ***END TIME @ 19:00*** PRE MIT T/I/O 325/75/0 INITIAL T/I/O 950/3900/0 15 MIN T/I/O 950/3750/0 30 MIN T/I/O 950/3725/0 18:45 0.50 COMPZN, STIM RURD P LDFN, SECURE WELL, TREE CAP PT'd, NOTIFY DSO 19:15 0.75 COMPZN, STIM TRAV P TRAVEL TO F-WING, RETURN WELL FILE, SYNC CPU Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 10.0 10.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/26/2025 14:00 6/26/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/27/2025 00:00 6/27/2025 23:59 FRAC HES 046 ROGERS, BRENT,Wells Supervisor 6/28/2025 13:00 6/28/2025 20:00 SLICK LINE Page 2/2 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 25.06 ] REPORT # [ 3] REPORT DATE: [ 6/28/2025] Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES 046 ROGERS, BRENT,Wells Supervisor 6/29/2025 05:30 6/29/2025 09:00 SLICK LINE HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/30/2025 00:00 6/30/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/1/2025 00:00 7/1/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/2/2025 00:00 7/2/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/3/2025 00:00 7/3/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/4/2025 00:00 7/4/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/5/2025 00:00 7/5/2025 12:00 FRAC Offline Activities Type Subtype Des Start Date End Date FRAC Frac Equipment 6/28/2025 00:00 6/28/2025 23:59 FRAC Frac Equipment 6/29/2025 00:00 6/29/2025 23:59 PUMPING 44 6/28/2025 13:00 6/28/2025 19:00 PUMPING 44 6/29/2025 07:00 6/29/2025 09:00 Page 1/1 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 25.60 ] REPORT # [ 4] REPORT DATE: [ 6/29/2025] API / UWI 5010320915 Original KB/RT Elevation (ft) 48.00 Ground Elevation (ft) 22.90 Original Spud Date 6/3/2025 Job Category COMPLETIONS Primary Job Type INITIAL COMPLETION Total AFE (Cost) 6,610,068.00 AFE / RFE / Maint.# GKA.00183.E.W002.CO.I S;GKA.00183.E.W002.C O.IF;GKA.00183.E.W002. CO.IW Network/Order Number 10454643;50060721;500 60722 AFE+Supp Amt (Cost) 6,610,068.00 Daily Cost Total (Cost) 94,300.00 Cumulative Cost (Cost) 377,200.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary PULL 4-1/2 SS CATCHER @ 2390' RKB, JOB COMPLETE 24hr Forecast General Remarks INITIAL T/I/O 250/250/0 FINAL T/I/O 250/250/0 ZX Code ZX50 Slickline / DSL Misc. (or Multiple Operations Contact Name Title Mobile BUQUET, JONATHAN Slickline Operator 985-232-2439 Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 05:30 1.00 COMPZN, STIM TRAV P CONFER w/ CWG, OBTAIN WELL FILE, SYNC CPU, NOTIFY DSO, TRAVEL TO 3S -705, INSPECT LOC. 06:30 0.75 COMPZN, STIM RURD P R/U .125 CARBON, 2-1/8'' RLR TS= RS, QC, 5', QC, KJ, 5', QC, OJ, QC, KJ, LSS, PT w/ LRS= 250L / 3500H, ***TIME START @ 07:00*** 07:15 1.00 COMPZN, STIM SLKL P RIH w/ QC, 4-1/2 GS (brass), LATCH & PULL 4-1/2 SS CATCHER @ 2355' SLM / 2390' RKB, POOH 08:15 0.75 COMPZN, STIM TRAV P R/D LRS & HES, SECURE WELL, TREE CAP PT'd, NOTIFY DSO, MOVE OVER TO 3S-703 Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 1.0 11.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/26/2025 14:00 6/26/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/27/2025 00:00 6/27/2025 23:59 FRAC HES 046 ROGERS, BRENT,Wells Supervisor 6/28/2025 13:00 6/28/2025 20:00 SLICK LINE HES 046 ROGERS, BRENT,Wells Supervisor 6/29/2025 05:30 6/29/2025 09:00 SLICK LINE HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/30/2025 00:00 6/30/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/1/2025 00:00 7/1/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/2/2025 00:00 7/2/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/3/2025 00:00 7/3/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/4/2025 00:00 7/4/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/5/2025 00:00 7/5/2025 12:00 FRAC Offline Activities Type Subtype Des Start Date End Date FRAC Frac Equipment 6/28/2025 00:00 6/28/2025 23:59 FRAC Frac Equipment 6/29/2025 00:00 6/29/2025 23:59 PUMPING 44 6/28/2025 13:00 6/28/2025 19:00 PUMPING 44 6/29/2025 07:00 6/29/2025 09:00 Page 1/1 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 27.23 ] REPORT # [ 5] REPORT DATE: [ 6/30/2025] API / UWI 5010320915 Original KB/RT Elevation (ft) 48.00 Ground Elevation (ft) 22.90 Original Spud Date 6/3/2025 Job Category COMPLETIONS Primary Job Type INITIAL COMPLETION Total AFE (Cost) 6,610,068.00 AFE / RFE / Maint.# GKA.00183.E.W002.CO.I S;GKA.00183.E.W002.C O.IF;GKA.00183.E.W002. CO.IW Network/Order Number 10454643;50060721;500 60722 AFE+Supp Amt (Cost) 6,610,068.00 Daily Cost Total (Cost) 94,300.00 Cumulative Cost (Cost) 471,500.00 Weather Temperature (°F) Road Condition Wind Last 24hr Summary CONTINUE RIGGING IN, BEGIN ROLLING TANKS, STAGE PROPPANT 24hr Forecast COMPLETE RIG IN General Remarks ZX Code ZX02 Fracturing Contact Name Title Mobile OSSELBURN,DEREK Frac Supervisor 724-494-3261 LAWSON, JACOB Supervisor 971-606-0075 Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 00:00 6.50 COMPZN, STIM RURD P START RUNNING RESTRAINTS, SPOT IN FRAC SHACK, SPOT GREAT NORTH LAUNCHER EQUIPMENT 06:30 6.00 COMPZN, STIM RURD P STAB ON LAUNCHER, RUNIRON TO WELL, SET CVA, 12:30 5.00 COMPZN, STIM RURD P CONTINUE RIG UP, TIE IN ALL HYDRAULIC LINES TO THE LAUNCHER STACK 17:30 3.00 COMPZN, STIM RURD P RIG UP WATER HEATER FOR TANK ROLLING TO TEMP 20:30 3.49 COMPZN, STIM RURD P ROLL TANKS TO TEMP Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 11.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/26/2025 14:00 6/26/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/27/2025 00:00 6/27/2025 23:59 FRAC HES 046 ROGERS, BRENT,Wells Supervisor 6/28/2025 13:00 6/28/2025 20:00 SLICK LINE HES 046 ROGERS, BRENT,Wells Supervisor 6/29/2025 05:30 6/29/2025 09:00 SLICK LINE HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/30/2025 00:00 6/30/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/1/2025 00:00 7/1/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/2/2025 00:00 7/2/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/3/2025 00:00 7/3/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/4/2025 00:00 7/4/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/5/2025 00:00 7/5/2025 12:00 FRAC Offline Activities Type Subtype Des Start Date End Date FRAC Frac Equipment 6/28/2025 00:00 6/28/2025 23:59 FRAC Frac Equipment 6/29/2025 00:00 6/29/2025 23:59 PUMPING 44 6/28/2025 13:00 6/28/2025 19:00 PUMPING 44 6/29/2025 07:00 6/29/2025 09:00 Page 1/1 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 28.23 ] REPORT # [ 6] REPORT DATE: [ 7/1/2025] API / UWI 5010320915 Original KB/RT Elevation (ft) 48.00 Ground Elevation (ft) 22.90 Original Spud Date 6/3/2025 Job Category COMPLETIONS Primary Job Type INITIAL COMPLETION Total AFE (Cost) 6,610,068.00 AFE / RFE / Maint.# GKA.00183.E.W002.CO.I S;GKA.00183.E.W002.C O.IF;GKA.00183.E.W002. CO.IW Network/Order Number 10454643;50060721;500 60722 AFE+Supp Amt (Cost) 6,610,068.00 Daily Cost Total (Cost) 143,005.48 Cumulative Cost (Cost) 614,505.48 Weather Temperature (°F) Road Condition Wind Last 24hr Summary COMPLETED RIG IN, COMPLETED SCAFFOLDING, LOADED THE SAHARA, COMPLETED ROLLING TANKS, RIGGED IN AND LOADED FUEL, SPOTTED SAFETY SHACK 24hr Forecast STIM INTERVALS 1-5 General Remarks HAL 18 ZX Code ZX02 Fracturing Contact Name Title Mobile OSSELBURN,DEREK Frac Supervisor 724-494-3261 LAWSON, JACOB Supervisor 971-606-0075 Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 00:00 6.50 COMPZN, STIM RURD P HARD LINE CREW RIGGED IN THE IA, OA, TUBING LINE, CONTINUED ROLLING FRAC TANKS UP TO TEMP, SPOTTED FRAC SHACK FUEL SYSTEM, 06:30 8.00 COMPZN, STIM RURD P SCAFFOLD CREW COMPLETED MODIFICATIONS TO NIPPLE UP THE DART ROTARY, COMPLETED THE LAUNCHER STACK RIG IN, SPOTTED IN FINAL PUMPS, CONTINUED ROLLING TANKS UP TO TEMP, RIGGED IN FRAC SHACK 14:30 3.50 COMPZN, STIM RURD P RIGGED IN THE LAUNCH LINE AND THE LAUNCH PUMP, STARTED SAHARA TOP OFF, STILL ROLLING TANKS, FIRE UP EQUIPMENT 18:00 5.99 COMPZN, STIM RURD P STARTED RUNNING RESTRAINTS, EQUIPMENT PREPARATIONS, LOADING PROPPANT Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 11.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/26/2025 14:00 6/26/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/27/2025 00:00 6/27/2025 23:59 FRAC HES 046 ROGERS, BRENT,Wells Supervisor 6/28/2025 13:00 6/28/2025 20:00 SLICK LINE HES 046 ROGERS, BRENT,Wells Supervisor 6/29/2025 05:30 6/29/2025 09:00 SLICK LINE HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/30/2025 00:00 6/30/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/1/2025 00:00 7/1/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/2/2025 00:00 7/2/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/3/2025 00:00 7/3/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/4/2025 00:00 7/4/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/5/2025 00:00 7/5/2025 12:00 FRAC Offline Activities Type Subtype Des Start Date End Date FRAC Frac Equipment 6/28/2025 00:00 6/28/2025 23:59 FRAC Frac Equipment 6/29/2025 00:00 6/29/2025 23:59 PUMPING 44 6/28/2025 13:00 6/28/2025 19:00 PUMPING 44 6/29/2025 07:00 6/29/2025 09:00 Page 1/2 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 29.23 ] REPORT # [ 7] REPORT DATE: [ 7/2/2025] API / UWI 5010320915 Original KB/RT Elevation (ft) 48.00 Ground Elevation (ft) 22.90 Original Spud Date 6/3/2025 Job Category COMPLETIONS Primary Job Type INITIAL COMPLETION Total AFE (Cost) 6,610,068.00 AFE / RFE / Maint.# GKA.00183.E.W002.CO.I S;GKA.00183.E.W002.C O.IF;GKA.00183.E.W002. CO.IW Network/Order Number 10454643;50060721;500 60722 AFE+Supp Amt (Cost) 6,610,068.00 Daily Cost Total (Cost) 1,252,864.94 Cumulative Cost (Cost) 1,867,370.42 Weather Temperature (°F) Road Condition Wind Last 24hr Summary BROKE THE ARSENAL DISC @ 6919 PSI DH, SHIFTED THE ALPHA SLEEVE @ 7982 PSI DH, COMPLETED DFIT, INTERVAL 1, A MINI-FRAC, AND INTERVALS 2-5, DROPPED DART FOR INTERVAL 6 PUMPED DFIT, BLOCKED IN IA AND TUBING FOR OVERNIGHT MONITORING, TOTAL PROPPANT PLACED 1,025,555, TOTAL CLEAN VOLUME, 6,719 BBL, TOTAL SLURRY VOLUME, 7809 BBL 24hr Forecast STIM INTERVALS 6-11 General Remarks INITIAL T/I/O 780/150/0 FINAL T/I/O 942/3303/7 HAL 18 ZX Code ZX02 Fracturing Contact Name Title Mobile OSSELBURN,DEREK Frac Supervisor 724-494-3261 LAWSON, JACOB Supervisor 971-606-0075 Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 00:00 6.50 COMPZN, STIM RURD P COMPLETE WATER HEATING, LOADING PROPPANT AND RESTRAINTS 06:30 0.75 COMPZN, STIM RURD P SAFETY MEETING 07:15 1.00 COMPZN, STIM RURD P PRIME EQUIPMENT, PSI TEST STARTING PSI 9480, 5 MINUTE PSI 9412, GOOD TEST, 08:15 0.75 COMPZN, STIM RURD P MIX GEL, LOAD DARTS 09:00 0.15 COMPZN, STIM PUMP P EQUALIZE TO 1000 PSI, OPENING PSI 787, ROLLED PUMP, THE ARSENAL DISC, BROKE @ 5514 PSI SURFACE 6,919 DH, ALPHA SLEEVE SHIFT@ 5982 PSI SURFACE, 7,982 DH, ROLLED INTO THE 30 BBL DFIT, SHUT DOWN FOR CLOSURE PSI. 09:09 0.50 COMPZN, STIM PUMP P BLOCKED IN THE WELL AND THE IA, MONITORED PSI 09:39 1.80 COMPZN, STIM PUMP P EQUALIZED TO 1000 PSI, OPENING PSI 568,ESTABLISHED INJECTION, PERFORM STEP RATE TEST TO 15 BPM, SHUT DOWN FOR A BLENDER REBOOT, THE SAND SCREWS AND D.A.S. WERE NOT READING, RESUMED PUMPING BROUGHT RATE TO 15 BPM ESTABLISHED XL,ROLLED INTO INTERVAL TOTAL CLEAN VOLUME PUMPED 1,393 BBL , TOTAL SLURRY VOLUME 1,611 BBL TOTAL PROPPANT PLACED 205,282 LB , 100 MESH 3000 LB, 16/20 LB 202,282 , AVG PSI 2,769, AVG BHP 4,178 PSI, AVG RATE 19.8 BPM, DART FOR INTERVAL 2 LAUNCHED @ 1578 JSV 11:27 0.25 COMPZN, STIM PUMP P INTERVAL 2 DART LANDED @1795 BBL, 7 BBL EARLY,SURF SEAT: 2247 PSI, SURF PEAK: 4,530, SURF DIFF: 2283, BH SEAT: 3416 PSI, BH PEAK: 6038, BH DIFF: 2622 COMPLETED THE MINI-FRAC SHUT DOWN FOR PSI MONITORING. 11:42 0.75 COMPZN, STIM PUMP P PSI MONITOURING 12:27 1.39 COMPZN, STIM PUMP P RESUMED INTERVAL 2, TOTAL CLEAN VOLUME PUMPED 1,686 BBL , TOTAL SLURRY VOLUME BBL 1,904 , TOTAL PROPPANT PLACED 205,553LB , 100 MESH 3000 LB, 16/20 202,553 LB , AVG PSI 2,542 , AVG BHP 4,003 PSI , AVG RATE 20.2 BPM INTERVAL 3 DART LAUNCHED AT 3511 JSV 13:50 1.20 COMPZN, STIM PUMP P INTERVAL 3 DART LANDED @ 3697 BBL, 11 BBL EARLY,SURF SEAT: 2236, SURF PEAK: 2893, SURF DIFF: 657, BH SEAT: 3453, BH PEAK: 4001, BH DIFF: 548, TOTAL CLEAN VOLUME PUMPED 1,231 BBL, TOTAL SLURRY VOLUME BBL 1,447 TOTAL PROPPANT PLACED LB 203,982, 100 MESH 3000 LB, 16/20 LB 200,982 , AVG PSI 2,411 , AVG BHP 3,913 PSI , AVG RATE BPM 20.2 DART FOR STAGE 4 LAUNCHED @ 4967 JSV 15:02 1.20 COMPZN, STIM PUMP P INTERVAL 4 DART LANDED @ 5145 BBL, 11 BBL EARLY,SURF SEAT: 2233, SURF PEAK: 5407, SURF DIFF: 3174BH SEAT: 3378, BH PEAK: 6560, BH DIFF: 3182, TOTAL CLEAN VOLUME PUMPED BBL 1,204, TOTAL SLURRY VOLUME BBL 1,423 TOTAL PROPPANT PLACED LB 205,862, 100 MESH 3000 LB, 16/20 LB 202,862, AVG PSI 2,692, AVG BHP 4,110 PSI , AVG RATE BPM 20.2, DART FOR INTERVAL 5 LAUNCHED @ 6396 JSV Page 2/2 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 29.23 ] REPORT # [ 7] REPORT DATE: [ 7/2/2025] Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 16:14 1.15 COMPZN, STIM PUMP P INTERVAL 5 DART LANDED @ 6569 BBL, 8 BBL EARLY,SURF SEAT: 2214, SURF PEAK 4293, SURF DIFFf: 2079, BH SEAT: 3385, BH PEAK: 5488, BH SEAT: 2103, TOTAL CLEAN VOLUME PUMPED BBL 1,206, TOTAL SLURRY VOLUME BBL 1,423 TOTAL PROPPANT PLACED LB 204,876, 100 MESH 3000 LB, 16/20 LB 201,876 , AVG PSI 2,437 , AVG BHP 3,879 PSI, AVG RATE BPM 20.3, DART FOR STAGE 6 LAUNCHED @ 7829 JSV 17:23 0.15 COMPZN, STIM PUMP P INTERVAL 6 DART LANDED @ 7995 PSI PUMPED DFIT,HARD SHUTDOWN, BLOCKED IN ALL PSI BLED DOWN SURFACE LINES 17:32 0.75 COMPZN, STIM WAIT P FAN OUT, BLOW DOWN 18:17 5.70 COMPZN, STIM WAIT P RELOAD PROPPANT, RELOAD WATER, WORK ON EQUIPMENT Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 11.0 FRAC FLUID 6,991.0 6,991.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/26/2025 14:00 6/26/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/27/2025 00:00 6/27/2025 23:59 FRAC HES 046 ROGERS, BRENT,Wells Supervisor 6/28/2025 13:00 6/28/2025 20:00 SLICK LINE HES 046 ROGERS, BRENT,Wells Supervisor 6/29/2025 05:30 6/29/2025 09:00 SLICK LINE HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/30/2025 00:00 6/30/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/1/2025 00:00 7/1/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/2/2025 00:00 7/2/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/3/2025 00:00 7/3/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/4/2025 00:00 7/4/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/5/2025 00:00 7/5/2025 12:00 FRAC Offline Activities Type Subtype Des Start Date End Date FRAC Frac Equipment 6/28/2025 00:00 6/28/2025 23:59 FRAC Frac Equipment 6/29/2025 00:00 6/29/2025 23:59 PUMPING 44 6/28/2025 13:00 6/28/2025 19:00 PUMPING 44 6/29/2025 07:00 6/29/2025 09:00 Stimulation Intervals Interval Number Start Date End Date Top (ftKB) Btm (ftKB) Proppant Designed (lb) Proppant Total (lb) Volume Clean Total (bbl) Volume Slurry Total (bbl) 1 7/2/2025 09:01 7/2/2025 11:15 13,974.7 13,978.7 203,000.0 205,282.0 1,393.12 1,611.18 2 7/2/2025 11:15 7/2/2025 13:40 13,420.5 13,424.5 203,000.0 205,553.0 1,685.52 1,903.87 3 7/2/2025 13:40 7/2/2025 14:52 12,920.4 12,924.4 203,000.0 203,982.0 1,230.81 1,447.49 4 7/2/2025 14:52 7/2/2025 16:03 12,420.9 12,424.9 203,000.0 205,862.0 1,204.21 1,422.89 5 7/2/2025 16:03 7/2/2025 17:27 11,911.9 11,915.9 203,000.0 204,876.0 1,205.64 1,423.27 Page 1/2 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 30.23 ] REPORT # [ 8] REPORT DATE: [ 7/3/2025] API / UWI 5010320915 Original KB/RT Elevation (ft) 48.00 Ground Elevation (ft) 22.90 Original Spud Date 6/3/2025 Job Category COMPLETIONS Primary Job Type INITIAL COMPLETION Total AFE (Cost) 6,610,068.00 AFE / RFE / Maint.# GKA.00183.E.W002.CO.I S;GKA.00183.E.W002.C O.IF;GKA.00183.E.W002. CO.IW Network/Order Number 10454643;50060721;500 60722 AFE+Supp Amt (Cost) 6,610,068.00 Daily Cost Total (Cost) 1,155,201.50 Cumulative Cost (Cost) 3,022,571.92 Weather Temperature (°F) Road Condition Wind Last 24hr Summary COMPLETE STAGES 6-11 INTERVAL 6 WAS CUT 50,000 LB SHORT, THERE WAS PASS THROUGH THE DART TO INTERVAL 5, TOTAL PLACED 1,171,425 LB PROPPANT, TOTAL FLUIDS, CLEAN VOLUME 7,754 BBL, TOTAL SLURRY VOLUME 8,998 BBL, 24hr Forecast General Remarks INITIAL T/I/O 680/1598/5 FINAL T/I/O 853/700/7 HAL 18 ZX Code ZX02 Fracturing Contact Name Title Mobile OSSELBURN,DEREK Frac Supervisor 724-494-3261 LAWSON, JACOB Supervisor 971-606-0075 Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 00:00 6.50 COMPZN, STIM WAIT P COMPLETED MAINTENANCE 458 201 570 579, COMPLETED LOADING/HEATING WATER 06:30 0.50 COMPZN, STIM WAIT P SAFETY MEETING 07:00 0.75 COMPZN, STIM WAIT P SETTING UP EQUIPMENT, PRIMING EQUIPMENT, PRESSURE TESTING START 9558, 5 MINUTE ENDING PSI 9526 GOOD TEST, 07:45 0.75 COMPZN, STIM WAIT P MIXING GEL LOADING DARTS 08:30 1.34 COMPZN, STIM PUMP P EQUALIZE TO 100PSI, OPENING PSI, 680, STAGED INTO GEL SPACER, DETERMINED INTERVAL 5 WAS LEAKING BY, DECISION WAS MADE TO CONTINUE INTERVAL, THEN CUT SHORT, CLEAN VOLUME PUMPED BBL 1,431 BBL, TOTAL SLURRY VOLUME 1595 BBL , TOTAL PROPPANT PLACED LB 154,681, 100 MESH 3000 LB, 16/20 515,681 LB , AVG PSI 2,888 , AVG BHP 3,936 PSI , AVG RATE 20 BPM INTERVAL 7 DART LAUNCHED AT 1375 JSV. 09:50 1.11 COMPZN, STIM PUMP P INTERVAL 7 DART LANDED @ 1532 BBL JSV, 9 BBL EARLY, SURF SEAT: 2211, SURF PEAK: 4322, SURF DIFF: 2111, BH SEAT: 3431, BH PEAK: 5583, BH DIFF: 2152, TOTAL CLEAN VOLUME PUMPED BBL 1,205, TOTAL SLURRY VOLUME BBL 1425 TOTAL PROPPANT PLACED LB 206,764, 100 MESH 3000 LB, 16/20 LB 203,764 , AVG PSI 2,142 , AVG BHP PSI 3569, AVG RATE BPM 20, DART FOR INTERVAL 8 LAUNCHED @ 2810 JSV 10:57 0.20 COMPZN, STIM PUMP P INTERVAL 8 DART LANDED @ 2960 BBL JSV, 8 BBL EARLY,SURF SEAT: 1835, SURF PEAK: 2805, SURF DIFF: 970, BH SEAT: 3138, BH DIFF: 4262, BH DIFF: 1124 , DURING THE SLEEVE SHIFT THE IA TRANSDUCER SPIKED KICKING THE PUMPS AND POPPING THE TREATING LINE EPRV FROM THE IA TRANSDUCER, CLOSED WELL FOR REPAIR, SWAPPING CABLE AND TRANSDUCER 11:09 0.50 COMPZN, STIM WAIT T WAITING ON IA PSI TRANSDUCER AND CABLE SWAP 11:39 1.24 COMPZN, STIM PUMP P TOTAL CLEAN VOLUME PUMPED BBL 1395 , TOTAL SLURRY VOLUME BBL 1609 TOTAL PROPPANT PLACED LB 201,689, 100 MESH 3000 LB, 16/20 LB 198,689 , AVG PSI 1998 , AVG BHP PSI 3479 , AVG RATE BPM 20. DART FOR INTERVAL 9 LAUNCHED @ 4429 JSV 12:53 1.25 COMPZN, STIM PUMP P INTERVAL 9 DART LANDED @ 4571 BBL, 9 BBL EARLY, SS: 1740, SP: 3409, SD: 1669 BS: 3091, BP: 4815, BD: 1724, TOTAL CLEAN VOLUME PUMPED BBL 1205, TOTAL SLURRY VOLUME BBL 1419 TOTAL PROPPANT PLACED LB 201954, 100 MESH 3000 LB, 16/20 198954LB , AVG PSI 2,030 , AVG BHP 3,479 PSI, AVG RATE BPM 20 , DART FOR STAGE 10 LAUNCHED @ 5856 JSV Page 2/2 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 30.23 ] REPORT # [ 8] REPORT DATE: [ 7/3/2025] Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 14:08 1.15 COMPZN, STIM PUMP P INTERVAL 10 DART LANDED @ 4571 BBL, 9 BBL EARLY,SS: 1759 PSI SP: 6885, SD: 5126 BS: 3088 PSI, BP: 7663, BD: 4575, TOTAL CLEAN VOLUME PUMPED 1421 BBL , TOTAL SLURRY VOLUME BBL 1421 TOTAL PROPPANT PLACED LB 203463 , 100 MESH 3000 LB, 16/20 LB 200463 , AVG PSI 2030 , AVG BHP PSI 3479, AVG RATE BPM 20., DART FOR STAGE 11 LAUNCHED @ 7286 JSV 15:17 1.20 COMPZN, STIM PUMP P INTERVAL 11 DART LANDED @ 7414 BBL, 8 BBL EARLY,SS: 1759 PSI SP: 6885, SD: 5126 BS: 3088 PSI, BP: 7663, BD: 4575, TOTAL CLEAN VOLUME PUMPED BBL 1314 , TOTAL SLURRY VOLUME BBL 1529 TOTAL PROPPANT PLACED LB 202874 , 100 MESH 3000 LB, 16/20 LB 199874 , AVG PSI 1801, AVG BHP 3,5297 PSI, AVG RATE BPM 20. 16:29 0.50 COMPZN, STIM WAIT P 15 MIN PSI MONITORING, FAN OUT BLOW DOWN PUMPS 16:59 0.50 COMPZN, STIM PUMP P PUMP 30 BBL FREEZE PROTECT 17:29 6.50 COMPZN, STIM WAIT P LOAD/HEAT WATER Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 11.0 FRAC FLUID 7,754.0 14,745.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/26/2025 14:00 6/26/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/27/2025 00:00 6/27/2025 23:59 FRAC HES 046 ROGERS, BRENT,Wells Supervisor 6/28/2025 13:00 6/28/2025 20:00 SLICK LINE HES 046 ROGERS, BRENT,Wells Supervisor 6/29/2025 05:30 6/29/2025 09:00 SLICK LINE HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/30/2025 00:00 6/30/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/1/2025 00:00 7/1/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/2/2025 00:00 7/2/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/3/2025 00:00 7/3/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/4/2025 00:00 7/4/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/5/2025 00:00 7/5/2025 12:00 FRAC Offline Activities Type Subtype Des Start Date End Date FRAC Frac Equipment 6/28/2025 00:00 6/28/2025 23:59 FRAC Frac Equipment 6/29/2025 00:00 6/29/2025 23:59 PUMPING 44 6/28/2025 13:00 6/28/2025 19:00 PUMPING 44 6/29/2025 07:00 6/29/2025 09:00 Stimulation Intervals Interval Number Start Date End Date Top (ftKB) Btm (ftKB) Proppant Designed (lb) Proppant Total (lb) Volume Clean Total (bbl) Volume Slurry Total (bbl) 6 7/3/2025 08:29 7/3/2025 09:42 11,412.4 11,416.4 153,000.0 154,681.0 1,430.81 1,595.14 7 7/3/2025 09:42 7/3/2025 10:54 10,915.4 10,919.4 203,000.0 206,764.0 1,205.14 1,424.78 8 7/3/2025 10:54 7/3/2025 12:42 10,415.6 10,419.6 203,000.0 201,689.0 1,394.69 1,608.94 9 7/3/2025 12:42 7/3/2025 13:53 9,915.8 9,919.8 203,000.0 201,954.0 1,204.52 1,419.05 10 7/3/2025 13:53 7/3/2025 15:05 9,416.2 9,420.2 203,000.0 203,463.0 1,205.02 1,421.15 11 7/3/2025 15:05 7/3/2025 16:22 8,909.4 8,913.4 203,000.0 202,874.0 1,313.67 1,529.17 Page 1/2 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 31.23 ] REPORT # [ 9] REPORT DATE: [ 7/4/2025] API / UWI 5010320915 Original KB/RT Elevation (ft) 48.00 Ground Elevation (ft) 22.90 Original Spud Date 6/3/2025 Job Category COMPLETIONS Primary Job Type INITIAL COMPLETION Total AFE (Cost) 6,610,068.00 AFE / RFE / Maint.# GKA.00183.E.W002.CO.I S;GKA.00183.E.W002.C O.IF;GKA.00183.E.W002. CO.IW Network/Order Number 10454643;50060721;500 60722 AFE+Supp Amt (Cost) 6,610,068.00 Daily Cost Total (Cost) 1,020,884.16 Cumulative Cost (Cost) 4,043,456.08 Weather Temperature (°F) Road Condition Wind Last 24hr Summary COMPLETE INTERVALS 12-16 , THE INTERVAL 12 DART SEAT HAD AN ABNORMAL DOUBLE HUMP AND TREATING PRESSURE WAS ABOVE THE PREVIOUS AVERAGE TREATING PRESSURES. FIBER DATA INDICATED THAT THE FLUID WAS GOING INTO INTERVAL 11. THE DECISION WAS MADE TO FLUSH THE WELL WITH LINEAR GEL AND DROP ANOTHER DART FOR INTERVAL 12, SECOND DART HAD A GOOD SEAT AND BREAK AND NO PRESSURE TRANSFER, DAILY TOTALS, TOTAL PROPPANT PLACED 1,016,681 LB , TOTAL CLEAN VOLUME 6,685 BBL, TOTAL SLURRY VOLUME 7,945 BBL, 24hr Forecast General Remarks INITIAL T/I/O 680/492 /5 FINAL T/I/O 853/700/7 HAL 19 ZX Code ZX02 Fracturing Contact Name Title Mobile OSSELBURN,DEREK Frac Supervisor 724-494-3261 LAWSON, JACOB Supervisor 971-606-0075 Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 00:00 6.50 COMPZN, STIM WAIT P WATER AND PROPPANT FILLING 06:30 0.50 COMPZN, STIM WAIT P SAFETY MEETING 07:00 0.75 COMPZN, STIM WAIT P PRIME UP PSI TEST 07:45 0.60 COMPZN, STIM WAIT P LOAD DARTS MIX GEL 08:21 0.60 COMPZN, STIM PUMP P WELL OPEN, OPENING PSI 489, LAUNCHED DART FOR INTERVAL 12 @ 28 BBL JSV, DART LANDED @ 154 BBL JSV, A PRESSURE RESPONSE WAS NOTED IN INTERVAL 11, WENT TO FLUSH AFTER PUMPING 1965 LB 100 MESH TO DROP A BACK UP DART, 08:57 0.35 COMPZN, STIM WAIT T LOAD DART 09:18 1.40 COMPZN, STIM PUMP P OPENED WELL, LAUNCHED DART 2 FOR INTERVAL 12,DART LANDED AT 763 BBL JSV 4 BL EARLY,SS: 1632, SP: 5640, SD: 4008, BS: 3045, BP: 7117, BD: 4072, GOOD ZONAL EXCLUSION SHOWN ON ALL INSTRUMENTATION, RESUMED STAGE TOTAL CLEAN VOLUME PUMPED BBL 1,874 , TOTAL SLURRY VOLUME BBL 2,094 TOTAL PROPPANT PLACED LB 206,211 , 100 MESH 3000 LB, 16/20 LB 203,211 AFTER THE SECOND DART THE FULL DESIGNED PROPPANT WAS PUMPED WITH 16/20 INCLUDING THE 100 MESH STAGE, AVG PSI 1,923, AVG BHP PSI 3,306, AVG RATE BPM 19.9, DART FOR INTERVAL 13 LAUNCHED @ 2082 JSV 10:42 1.24 COMPZN, STIM PUMP P INTERVAL 13 DART LANDED @ 2196 BBL JSV, 6 BBL EARLY,SS: 1445, SP: 3668, SD: 2223, BS: 2914, BP: 5178, BD: 2264, TOTAL CLEAN VOLUME PUMPED BBL 1,229, TOTAL SLURRY VOLUME BBL 1,446 TOTAL PROPPANT PLACED LB 204,311 , 100 MESH 3000 LB, 16/20 LB 201,311 , AVG PSI 1,635 , AVG BHP PSI 3,065 , AVG RATE BPM 20., DART FOR INTERVAL 14 LAUNCHED @ 3534 JSV 11:56 1.18 COMPZN, STIM PUMP P INTERVAL 14 DART LANDED @ 3641 BBL JSV, 6, BBL EARLY,SS: 1231, SP: 3515, SD: 2284, BS: 2811, BP: 5050, BD: 2239, TOTAL CLEAN VOLUME PUMPED BBL 1,224, TOTAL SLURRY VOLUME BBL 1,441 TOTAL PROPPANT PLACED LB 204,256 , 100 MESH 3000 LB, 16/20 201,256 LB , AVG PSI 1,893 , AVG BHP PSI 3,023, AVG RATE BPM 20.1 DART FOR INTERVAL 15 LAUNCHED @ 4983 JSV 13:07 1.20 COMPZN, STIM PUMP P INTERVAL 15 DART LANDED @ 5081 BBL JSV, 7, BBL EARLY, SS: 1227, SP: 3556, SD: 2329, BS: 2828, BP: 5225, BD: 2397, TOTAL CLEAN VOLUME PUMPED BBL 1,219, TOTAL SLURRY VOLUME BBL 1,434 TOTAL PROPPANT PLACED LB 201,706 , 100 MESH 3000 LB, 16/20 LB 198,706 , AVG PSI 1,489 , AVG BHP PSI 2,974, AVG RATE BPM 20.1, DART FOR INTERVAL 16 LAUNCHED @ 6425 BBL JSV, 25# GEL SYSTEM PUMPED ON THIS STAGE Page 2/2 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 31.23 ] REPORT # [ 9] REPORT DATE: [ 7/4/2025] Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 14:19 1.20 COMPZN, STIM PUMP P INTERVAL 16 DART LANDED @ 5081 BBL JSV, 3 BBL EARLY, SS: 1223, SP: 3522, SD: 2299, BS: 2810, BP: 5128, BD: 2318, TOTAL CLEAN VOLUME PUMPED BBL 1,319, TOTAL SLURRY VOLUME BBL 1,531 TOTAL PROPPANT PLACED LB 200,197, 100 MESH 3000 LB, 16/20 LB 197,197 , AVG PSI 1,283, AVG BHP PSI 2,838, AVG RATE BPM 20.2., 25# GEL SYSTEM PUMPED ON THIS STAGE 15:31 0.50 COMPZN, STIM WAIT P 15 MINUTE SIP 16:01 0.70 COMPZN, STIM WAIT P LRS PUMPING 30 BBL FREEZE PROTECT 16:43 7.27 COMPZN, STIM WAIT P RELOADING WATER Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 30.0 41.0 FRAC FLUID 6,865.0 21,610.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/26/2025 14:00 6/26/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/27/2025 00:00 6/27/2025 23:59 FRAC HES 046 ROGERS, BRENT,Wells Supervisor 6/28/2025 13:00 6/28/2025 20:00 SLICK LINE HES 046 ROGERS, BRENT,Wells Supervisor 6/29/2025 05:30 6/29/2025 09:00 SLICK LINE HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/30/2025 00:00 6/30/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/1/2025 00:00 7/1/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/2/2025 00:00 7/2/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/3/2025 00:00 7/3/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/4/2025 00:00 7/4/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/5/2025 00:00 7/5/2025 12:00 FRAC Offline Activities Type Subtype Des Start Date End Date FRAC Frac Equipment 6/28/2025 00:00 6/28/2025 23:59 FRAC Frac Equipment 6/29/2025 00:00 6/29/2025 23:59 PUMPING 44 6/28/2025 13:00 6/28/2025 19:00 PUMPING 44 6/29/2025 07:00 6/29/2025 09:00 Stimulation Intervals Interval Number Start Date End Date Top (ftKB) Btm (ftKB) Proppant Designed (lb) Proppant Total (lb) Volume Clean Total (bbl) Volume Slurry Total (bbl) 12 7/4/2025 08:20 7/4/2025 10:37 8,410.3 8,414.3 206,000.0 206,211.0 1,874.07 2,093.12 13 7/4/2025 10:37 7/4/2025 11:49 7,910.6 7,914.6 203,000.0 204,311.0 1,229.17 1,446.20 14 7/4/2025 11:49 7/4/2025 13:02 7,411.4 7,415.4 203,000.0 204,256.0 1,224.12 1,441.09 15 7/4/2025 13:02 7/4/2025 14:14 6,912.1 6,916.1 203,000.0 201,706.0 1,219.48 1,433.74 16 7/4/2025 14:14 7/4/2025 15:31 6,409.9 6,413.9 203,000.0 200,197.0 1,318.60 1,531.26 Page 1/1 3S-705 Report Printed: 7/7/2025 Daily STIM Report ORIG SPUD DATE: [ 6/3/2025 ] DRLG RIG RELEASE: [ 6/22/2025 ] CMPLT JOB START [ 6/26/2025 ] ON PRODUCTION: [ ] DAYS FROM SPUD: [ 31.73 ] REPORT # [ 10] REPORT DATE: [ 7/5/2025] API / UWI 5010320915 Original KB/RT Elevation (ft) 48.00 Ground Elevation (ft) 22.90 Original Spud Date 6/3/2025 Job Category COMPLETIONS Primary Job Type INITIAL COMPLETION Total AFE (Cost) 6,610,068.00 AFE / RFE / Maint.# GKA.00183.E.W002.CO.I S;GKA.00183.E.W002.C O.IF;GKA.00183.E.W002. CO.IW Network/Order Number 10454643;50060721;500 60722 AFE+Supp Amt (Cost) 6,610,068.00 Daily Cost Total (Cost) 483,761.69 Cumulative Cost (Cost) 4,527,217.77 Weather Temperature (°F) Road Condition Wind Last 24hr Summary RIGGED OFF 3S-705, BEGAN SWAP TO 3S-703 24hr Forecast General Remarks HAL- 19 ZX Code ZX02 Fracturing Contact Name Title Mobile OSSELBURN,DEREK Frac Supervisor 724-494-3261 LAWSON, JACOB Supervisor 971-606-0075 Time Log Start Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 00:00 7.00 COMPZN, STIM DMOB P BROKE DOWN PUMPS THAT ARE GOING IN FOR PM'S, 07:00 5.00 COMPZN, STIM DMOB P BROKE DOWN IRON AND RESRAINTS FROM 3S-705, RIGGED DOWN THE LAUNCHER STACK AND LAUNCH LINE Report Fluids Summary Fluid To well (bbl) Cum to Well (bbl) DIESEL 41.0 FRAC FLUID 21,610.0 Contractor Rig Name/# Rig Supervisor Rig Accept Date RR Date Rig Type HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/26/2025 14:00 6/26/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/27/2025 00:00 6/27/2025 23:59 FRAC HES 046 ROGERS, BRENT,Wells Supervisor 6/28/2025 13:00 6/28/2025 20:00 SLICK LINE HES 046 ROGERS, BRENT,Wells Supervisor 6/29/2025 05:30 6/29/2025 09:00 SLICK LINE HES Frac Equipment BURKETT, CHAD,Wells Supervisor 6/30/2025 00:00 6/30/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/1/2025 00:00 7/1/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/2/2025 00:00 7/2/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/3/2025 00:00 7/3/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/4/2025 00:00 7/4/2025 23:59 FRAC HES Frac Equipment BURKETT, CHAD,Wells Supervisor 7/5/2025 00:00 7/5/2025 12:00 FRAC Offline Activities Type Subtype Des Start Date End Date FRAC Frac Equipment 6/28/2025 00:00 6/28/2025 23:59 FRAC Frac Equipment 6/29/2025 00:00 6/29/2025 23:59 PUMPING 44 6/28/2025 13:00 6/28/2025 19:00 PUMPING 44 6/29/2025 07:00 6/29/2025 09:00 T + 1 337.856-7201 1058 Baker Hughes Drive Broussard, LA 70518, USA Jul 14, 2025 AOGCC Attention: Meredith Guhl 333 W. 7th Ave., Suite 100 Anchorage, Alaska 99501-3539 Subject:Final Log Distribution for ConocoPhillips Alaska, Inc. KRU 3S-705 Kuparuk River API #: 50-103-20915-00-00 Permit No: 225-047 Rig: Doyon 25 The final Coil deliverables were uploaded via https://copsftp.sharefile.com/ for the above well. Items delivered: Digital Las Data, Graphic Images CGM/PDF and Survey Files. Thank you. Signature of receiver & date received: Please return transmittal letter to: Hampton, Jerissa AKGGREDTSupport@ConocoPhillips.onmicrosoft.com Luis G Arismendi Luis.arismendi@bakerhughes.com 225-047 T40657 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.14 14:07:58 -08'00' Originated: Delivered to:3-Jul-25Alaska Oil & Gas Conservation Commiss03Jul25-NR ! "# $$%$ !&$$'($)*%+ ($)*%,- .WELL NAME API #SERVICE ORDER #FIELD NAMESERVICE DESCRIPTIONDELIVERABLE DESCRIPTION DATA TYPE DATE LOGGED3S-705 50-103-20915-00-00 225-047 Kuparuk River WL TTiX IBC FINAL FIELD 20-Jun-252K-23 50-103-20125-00-00 190-014 Kuparuk River WL Hex Plug FINAL FIELD 25-Jun-252L-304 50-103-20613-00-00 210-011 Kuparuk River WL Pressure-Temp Log FINAL FIELD 26-Jun-251B-04 50-029-20595-00-00 181-065 Kuparuk River WL IPROF FINAL FIELD 28-Jun-25Transmittal Receipt//////////////////////////////// 0///////////////////////////////// + ! 1 Please return via courier or sign/scan and email a copy to Schlumberger. " 2"3 +45 %TRANSMITTAL DATETRANSMITTAL #1 67 8 " ! - +" 8 # !(3 . 8 ) "3 8 # !9 3 : 8" +8 6 8 8 " 8 # !;" " 3 - 3 " 3 ""+ 3 + < +3!% T40638T40639T40640T406413S-70550-103-20915-00-00225-047Kuparuk RiverWLTTiX IBCFINAL FIELD20-Jun-25Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.07.09 09:20:13 -08'00' 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? Yes No 9. Property Designation (Lease Number): 10. Field: Coyote Coyote 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 14120 Casing Collapse Structural Conductor Surface 2474 Production 4789 Production 7870 Production 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: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7/1/2025 141078174 4-1/2" 4208 HES TNT Production Packer 5933 Perforation Depth MD (ft): 5483 450 4-1/2" 41397-5/8" 20" 10-3/4" 80 7-5/8"5483 2730 MD 6885 5209 120 2573 4061 120 2730 Length Size Proposed Pools: L-80 TVD Burst planned: 5,927' 10860 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025528/ADL380106/ADL380107 KRU 225-047 P.O. Box 100360 Anchorage, Alaska, 99510-0360 50-103-20915-00-00 ConocoPhillips Alaska Inc. AOGCC USE ONLY 11590 Tubing Grade:Tubing MD (ft): planned: 5,786' MD / 4,121' TVD Perforation Depth TVD (ft): Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY 4208 14120 4208 1484 3S-705 Completions Engineer Madeline Woodard madeline.e.woodard@cop.com 907-265-6086 CO 819 m n P s 2 6 5 6 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 12:49 pm, Jun 20, 2025 Digitally signed by Madeline Woodard DN: CN=Madeline Woodard, E= madeline.e.woodard@conocophillips.com Reason: I am the author of this document Location: Date: 2025.06.20 12:06:23-08'00' Foxit PDF Editor Version: 13.1.6 Madeline Woodard 325-375 10-404 CDW 06/24/2025 DSR-6/25/25 Include a PRV on OA or hold an open bleed on OA during fracture treatment. Test tubing PRV, IA PRV, and pump trips to the set pressures detailed in the section 7 table. If a 10-407 has nt been submitted when this work is complete include this on the 10-407 A.Dewhurst 24JUN25 7/1/2025 JJL 6/24/25 3S-714 to be monitored during 3S-705 frac stages 14-16. SJC for GCW 6/26/25 6/26/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.26 09:36:35 -08'00' RBDMS JSB 062625 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). June 18, 2025 VIA E-MAIL To: Operator and Owners (shown on Exhibit 2) Re: Notice of Operations for 3S-705 Well ADL 380107, ADL 380106 & ADL 025528 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 3S- 705 Well (the “Well”). The Application will be filed with the Alaska Oil and Gas Conservation Commission on or about June 19, 2025. The Well is currently planned to be drilled as a directional horizontal well on lease ADL 380107 ADL 380106, and ADL 025528 as depicted on Exhibit 1, and has locations as follows: Location FNL FEL Township Range Section Meridian Surface 2,474’ 893’ T12N R8E 18 Umiat Top Open Interval 2,502’ 3,639’ T12N R8E 18 Umiat Bottomhole 4,772’ 473’ T12N R7E 1 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 BCC: Madeline Woodard Brian Buck Jason C. 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 2 – Plat 20 AAC 25.283 (2)(A) Plat 1: Wells within 1/2 mile Table 1: Wells within 1/2 miles (2)(C) Business Unit ID Business Area ID Field Name API * Well Name Status Symbology Well in Frac Port 1/2 mi Buffer Open Interval in Frac Port 1/2 mi Buffer KUP KRU KUPARUK RIVER UNIT 501032045800 3S-03 SUSP Suspended KUP KRU KUPARUK RIVER UNIT 501032045400 3S-06 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045401 3S-06A PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032043000 3S-07 ACTIVE Oil KUP KRU KUPARUK RIVER UNIT 501032045000 3S-08 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045001 3S-08A PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045002 3S-08B PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045003 3S-08C ACTIVE Oil KUP KRU KUPARUK RIVER UNIT 501032045060 3S-08CL1 ACTIVE Oil KUP KRU KUPARUK RIVER UNIT 501032045070 3S-08CL1PB1 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032043200 3S-09 ACTIVE Injector Miscible Water Alternating Gas KUP KRU KUPARUK RIVER UNIT 501032044000 3S-10 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032043900 3S-14 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032044400 3S-15 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032044500 3S-16 ACTIVE Injector Miscible Water Alternating Gas KUP KRU KUPARUK RIVER UNIT 501032044800 3S-17 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032044801 3S-17A PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032043300 3S-18 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032046000 3S-19 SUSP Suspended Yes - Suspended Yes - Suspended KUP KRU KUPARUK RIVER UNIT 501032045200 3S-21 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032044600 3S-22 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045300 3S-23 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP KRU KUPARUK RIVER UNIT 501032045301 3S-23A SUSP Suspended Yes - Suspended Yes - Suspended KUP KRU KUPARUK RIVER UNIT 501032045600 3S-24 PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032045601 3S-24A PA Plugged and Abandoned KUP COYOTE COYOTE 501032045602 3S-24B PA Plugged and Abandoned KUP KRU KUPARUK RIVER UNIT 501032036101 3S-26 PA Plugged and Abandoned KUP TOROK TOROK 501032090600 3S-602 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032087000 3S-606 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032087000 3S-606 ACTIVE Injector Produced Water KUP TOROK TOROK 501032087500 3S-610 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032087500 3S-610 ACTIVE Oil KUP TOROK TOROK 501032077400 3S-611 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032077400 3S-611 ACTIVE Oil KUP TOROK TOROK 501032077470 3S-611PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP TOROK TOROK 501032077470 3S-611PB1 PA Plugged and Abandoned KUP TOROK TOROK 501032077700 3S-612 ACTIVE Injector Miscible Water Alternating Gas Yes Yes KUP TOROK TOROK 501032077700 3S-612 ACTIVE Injector Miscible Water Alternating Gas KUP TOROK TOROK 501032073500 3S-613 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032084400 3S-615 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032086400 3S-617 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032086400 3S-617 ACTIVE Injector Produced Water KUP TOROK TOROK 501032069500 3S-620 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032086800 3S-624 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032086800 3S-624 ACTIVE Oil KUP TOROK TOROK 501032084200 3S-625 ACTIVE Injector Produced Water Yes Yes KUP TOROK TOROK 501032087800 3S-626 ACTIVE Oil Yes Yes KUP TOROK TOROK 501032087800 3S-626 ACTIVE Oil KUP TOROK TOROK 501032087870 3S-626PB1 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP COYOTE COYOTE 501032084700 3S-701 PA Plugged and Abandoned Yes - P&A Yes - P&A KUP COYOTE COYOTE 501032084701 3S-701A ACTIVE Injector Produced Water Yes Yes KUP COYOTE COYOTE 501032091300 3S-703 ACTIVE Oil Yes Yes KUP COYOTE COYOTE 501032084800 3S-704 ACTIVE Oil Yes Yes KUP COYOTE COYOTE 501032090300 3S-714 ACTIVE Oil Yes Yes KUP COYOTE COYOTE 501032088400 3S-718 ACTIVE Oil KUP COYOTE COYOTE 501032091100 3S-721 ACTIVE Oil Yes Yes KUP COYOTE COYOTE 501032088600 3S-722 ACTIVE Injector Produced Water KUP COYOTE COYOTE 501032091000 3S-723 ACTIVE Oil Yes Yes KUP KRU KUPARUK RIVER UNIT 501032036100 PALM 1 PA Plugged and Abandoned Yes - P&A Yes - P&A SECTION 3 – FRESHWATER AQUIFERS 20 AAC 25.283(a)(3) There are no freshwater aquifers or underground sources of drinking water within a one-half mile radius of the current or proposed wellbore trajectory. None as per Aquifer Exemption Title 40 CFR 147.102(b)(3), “That portions of the aquifers on the North Slope described by a ¼ mile area beyond and lying directly below the Kuparuk River Unit oil and gas producing field”. 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) See Wellbore schematic for casing and cement details. SLB CBL Sonic VDL dated 6/20/2025 indicates TOC 2730 ft MD. CDW 06/24/2025 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 6/6/2025-6/7/2025 shows that the original job pumped as designed. The cement job was pumped with 458 barrels of 11.0 ppg lead cement and 58 barrels 15.8 ppg tail cement, displaced with 9.5 ppg mud. The plug bumped at 1150 psi and float held. No losses were observed during the job and 257bbls of cement returned to surface. The 7-5/8” x 4-1/2” casing cement report on 6/18/2025 shows that the job was pumped with 115 barrels of 11.0ppg lead cement and 516 bbls of 15.3ppg tail cement. The cement was displaced with 9.5ppg CI brine. The plug bumped and pressure was held at 1500 psi for 5 minutes. Pressure was then bled off and floats checked with floats holding. 20bbls of fluid was lost during the job. A cement bond log indicated the cement top at 2,730’ MD / 2,573’ TVD / 2,508’ TVDSS (2862’ MD / 1514’ TVD above the Coyote). Summary All casing is cemented in accordance with 20 AAC 25.030. cement top at 2,730 SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE-TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 6/7/2025 the 10-3/4” casing was pressure tested to 3,500 psi for 30 minutes On 6/19/2025 the 7-5/8” x 4-1/2” tapered casing was pressure tested to 4,000 psi for 30 minutes. The 4-1/2” tubing will be pressure tested to 4,550 psi for 30 minutes. The 7-5/8” casing by 4-1/2” tubing annulus will be pressure tested to 3,850 psi for 30 minutes. The 4-1/2” tubing will be pressure tested to 4,100 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 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 of approximately 375 ft TVD over the course of the lateral section of well 3S-705, from where it intersects the top formation at 5,592’ MD to TD of the well. At the heel of the well it has a gross thickness of ~570’ thinning to ~180’ 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 ~210’ TVT in the vicinity of the 3S-705 wellbore. The top of the confining intervals starts at ~3,822’ TVDSS (4,972’ 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 2,740’ MD. This interval acts as a continuation of the upper confining interval. Currently, there is limited data of the fracture gradient of the overlying Seabee formation, however, further data collection is planned. CPAI has completed a LOT in the overlying confining interval at 3,944’ TVDSS to 14.0ppg (0.728 psi/ft). CPAI also estimates the fracture closure pressure gradient to be 0.67 psi/ft based on diagnostic fracture injection testing (DFIT). The fracture gradient of the overlying Seabee formation will be greater than the fracture closure pressure gradient of 0.67 psi/ft and the leak off point of 0.73 psi/ft, per the figure below. 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 ~210’ 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). We have also lowered the lateral landing depth for the horizontal wells based on thickness of the gross package to be deeper than the perforation in the 3S-24B vertical well. The lower confining interval of the Coyote comprises slope to basin floor mudstones of the Torok formation, which are present in thicknesses of ~700’ TVT in the vicinity of the 3S-705 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 ~4,590 ft TVDSS at the heel, and ~4,246’ ft TVDSS at the toe of the well. The estimated formation pressure within the Coyote interval is 1,673 – 1,777 psi at a depth of 4,022’ 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 the following assessments for each well’s mechanical condition, seismic, 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 are listed in the AOR submitted with this sundry application. A summary of the condition of each well is listed below: 3S-15: This wellbore was P&A’d in 2020. A cement retainer was set at 7,790’ MD via coil tubing and 25.6 bbls of cement was pumped below the retainer and 1 bbl on top of the retainer to isolate the original zone of interest (Kuparuk C sand). Cement was tagged at 7,749’ MD’ MD and a passing MIT-T was performed and witnessed by AOGCC on 6/18/2020. The tubing was then punched from 7,692’-7,696’ MD and 294 bbls of 15.8ppg Class G cement was circulated down the tubing and up the IA. A cement top off was completed for the tubing, IA, and OA, 8 bbls of Portland Type I/II Class G 15.6ppg cement was pumped down the OA, 0.2bbls Portland Type I/II Class G 15.6ppg cement was pumped down the IA, and 0.2 bbls of Portland Type I/II Class G 15.6ppg cement was pumped down the tubing. The 9-5/8” x 7” OA was abandoned with 120bbls of 15.8ppg Permafrost cement from the surface to the surface shoe depth of 3,561’ MD. The excavation and final abandonment was completed on 9/10/2020, witnessed by AOGCC. 3S-17/17A: 3S-17 was originally drilled in 2003 and the main wellbore was abandoned on 4/28/2003 with two plugs. One plug was set from 8,906’-8,561’ MD with 33bbls of 15.8ppg class G cement and the other was set from 6,771’-6200’ MD and was tagged at 6,120’ MD/4,250’ TVDSS with the kick off BHA for the 3S-17A wellbore. Plug and Abandonment operations on 3S-17 and 3S-17A (sidetrack from 3S-17 on 4/29/2003), began on 7/30/2022 and were completed 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. 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. 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 7” x 9-5/8” OA was cemented via down squeeze with 115bbls of 15.8ppg Permafrost cement (surface to 9-5/8” shoe) on 5/18/2023.The final abandonment was completed on 9/25/23, witnessed by AOGCC. The 3S-17/17A Coyote penetration is 250-300’ away from the nearest 3S-705 frac sleeves (stages 13 and 14). The modeled half-length for these stages surpasses this distance, however, the well path is oriented along the measured maximum horizontal stress to create longitudinal fractures along the wellbore. Although there is potential the fracture deviates from longitudinal due to uncertainty in the orientation of the maximum horizontal stress, ConocoPhillips thinks the risk of loss of containment of frac fluids to the 3S-17/-17A wellbores is low. The Coyote interval is isolated via cement in and above the top of the Coyote and from below with cement above the Moraine formation in 3S-17/-17A. If treating pressure drops abruptly indicating connection to 3S-17/-17A, 3S-705 will be flushed immediately. See figure below for a visual of stages 13 and 14 distances to 3S-17/-17A Coyote top (dark red circle) and Coyote base (blue circle). 3S-18: 3S-18 was originally drilled in 2002 targeting the Kuparuk. This well was recently plugged and abandoned with final abandonment completed in 2024. A cement retainer was set at 6,566’ MD via coil tubing and 19 bbls of cement was pumped below the retainer and 2 bbls on top of the retainer. Cement was tagged at 6,316’ MD and a passing MIT-T and MIT-IA was performed and witnessed by AOGCC on 5/12/2023. The tubing was then cut at 6,283’ MD and the tubing pulled out of hole. A bridge plug was set at 4,737’ MD in the 7” casing and the 7” casing was perforated from 4,711-4,561’ MD. Coil was utilized to perf wash and cement with 68bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 4,377’ SLMD in the 7” casing. TOC was determined in the annulus at 4,561’ MD / 4,000’ TVD / 3,944’ TVDSS via log. Coil was used to pump 40 bbls of 15.8ppg cement in the 7” casing from 4,736’ to 3,686’ CTMD. The TOC was tagged at 3,655’ SLMD and a MIT-T performed to 1,700 psi, witnessed by AOGCC on 2/4/2024. The top cement job was performed on 2/9/2024 with 158 bbls of 15.8ppg Class G cement and the 7” casing was cemented to surface from 3,678’ CTMD. The 7” x 9- 5/8” OA was cemented via down squeeze with 104bbls of 15.8ppg Permafrost cement (surface to 9-5/8” shoe) on 9/20/2023.The final abandonment was completed on 3/31/2024, witnessed by AOGCC. 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. 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. 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. 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. 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. 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 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. 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. 3S-23/23A: 3S-23 was originally drilled in 2003 and the main wellbore was abandoned in 2006 by cementing the perforations, cutting and pulling the 3-1/2” tubing, and the 7” casing at 4,149’ MD. A kick off plug was then set from 4,423’ MD with 43bbls of 17.0ppg Class G cement. The 3S-23A wellbore was then kicked off at 4,090’ MD after tagging cement at 3,696’ MD. 3S-23A was drilled to TD and completed for in the Kuparuk sand. Estimated TOC for the intermediate casing was 9,471’ MD/5,638’ TVD/5,581’ TVDSS. Plug and Abandonment operations on 3S-23A began on 4/30/2023 and were completed 1/6/2025. A cement retainer was set at 10,315’ MD via coil tubing and 80 bbls of 15.8ppg class G cement was pumped below the retainer and 2 bbls on top of the retainer. Cement was tagged at 10,048’ SLMD and a passing MIT-T and MIT-IA was performed and witnessed by AOGCC on 5/9/2023. The tubing was then cut at 9,805’ MD and the tubing pulled out of hole. A bridge plug was set at 6,718’ MD in the 7” casing and the 7” casing was perforated from 6,692’-6,542’ MD. Coil was utilized to perf wash and cement with 70bbls of 15.8ppg cement pumped into the perforations. TOC was tagged at 6,370’ SLMD in the 7” casing and a MIT-T performed to 1500 psi. TOC was determined in the annulus at 6,542’ MD / 4,030 TVD / 3,972’ TVDSS via log. Coil was used to pump 40 bbls of 15.8ppg cement in the 7” casing. The TOC was tagged at 5,616’ MD and a MIT performed, witnessed by AOGCC on 2/14/2024. The top cement job was performed on 2/27/2024 with 239 bbls of 15.8ppg Class G cement and the 7” casing was cemented to surface. Integrity issues were then seen and the cement in the 7” casing was milled/underreamed to 4,255’ MD. A CIBP was set at 4,240’ MD and tested to 1,670 psi, witnessed by AOGCC on 12/18/2024. Cement was then pumped above the CIBP to surface using 52bbls of 15.8ppg premium lead cement and 130bbls of 15.8ppg tail cement. The 7” x 9-5/8” OA was cemented via down squeeze with 103bbls of 15.8ppg Permafrost cement (surface to 9-5/8” shoe) on 9/26/2023.The final abandonment was completed on 1/6/2025, witnessed by AOGCC. 3S-602: The 7-5/8” casing cement report on 03/08/2025 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 104 barrels of 14.0 ppg lead cement, followed with 31 barrels of 15.3 ppg tail cement. This was displaced with 322 barrels of 9.5 ppg BaraECD NAF. The plugs bumped, pressure was bled off, and floats were confirmed to be holding. A cement bond log indicates competent cement with a cement top @ 4,500 MD (3,610’ TVD/3,542’ TVDSS), which is 497’ TVD above the Coyote. 3S-606: The 7-5/8” casing cement report on 2/11/2024 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 111 barrels of 15.3 ppg with BM-II (Bridge Maker II), followed with 29 barrels of 15.3 ppg without BMII. The plugs bumped, pressure increased to 1500 psi and held for 5 minutes. A cement bond log indicates competent cement with a cement top @ 3,950 MD (3,164’ TVD/3,098’ TVDSS), which is 938’ TVD above the Coyote. 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), which is 932’ TVD above the Coyote. 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 8,228’MD (3,967’ TVD/3,904’ TVDSS), which is 141’ TVD above the Coyote. 3S-613: The 7-5/8” casing cement report on 5/2/2016 shows that the 2-stage 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). 3S-617: The 7-5/8” casing cement report on 11/5/2023 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 142 barrels of 15.3 ppg. The plug was not bumped. Pressure was being monitored and no pressure built up indicating that the floats held. A cement bond log indicates competent cement with a cement top @ 3,841’ MD (3,157’ TVD/3,092’ TVDSS), which is 934’ TVD above the Coyote. 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. 3S-624: The 7-5/8” casing cement report on 12/24/2023 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 125 barrels of 15.3ppg primary cement with LCM and 22 barrels of 15.3ppg primary cement without LCM. The plug was bumped and the floats held. A cement bond log indicates competent cement with a cement top @ 3,435’ MD (2,778’ TVD/2,715’ TVDSS), which is 1,315’ TVD above the Coyote. 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. 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. 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. The TOC was tagged at 2,580’ MD/2,306’ TVD/2,243’ TVDSS with 10klbs, tag witness waived by AOGCC. 3S-701: This wellbore was abandoned on 1/11/2023 with 1 abandonment plug. The plug was set from 5,597’- 3,406’ MD with 208bbls of 15.3ppg cement utilizing a 3.5” sacrificial string and cement stinger disconnect tool. No losses were observed during the job. A kick off plug was then pumped at 3,385’ MD with 62bbls of 16.5ppg cement. The KOP was tagged at 2,806’ MD with 5klbs. 3S-701A: The 7-5/8" Casing cement report on 1/20/2023 shows that the job was pumped as designed with 69bbls of 15.3ppg cement. Plugs bumped and pressured up and floats held. No losses were observed during the job. This plug isolated the Coyote (4,794’ MD/4,094’ TVD to 5,370’ MD/4,671’ TVD). A cement bond log indicates competent cement with a cement top @ 6800’ MD (3723’ TVD/3,659’ TVDSS), which is 423’ TVD above the Coyote. 3S-703: The 7-5/8” x 4-1/2” casing cement report on 5/29/2025 shows that the job was pumped with 137 barrels of 11.0ppg lead cement and 502 bbls of 15.3ppg tail cement. The cement was displaced with 9.5ppg CI brine. The plug bumped and pressure was held at 1500 psi for 5 minutes. Pressure was then bled off and floats checked with floats holding. 26bbls of fluid were lost during the job. A cement bond log indicated the cement top at 2,720’ MD (2,537’ TVD / 2,472’ TVDSS), which is 1556’ TVD above the Coyote. 3S-714: The 7-5/8" Casing cement report on 2/7/2025 shows that the job was pumped as designed with 57bbls of 15.3ppg cement. Plugs bumped and pressured up to 1902psi and held. Floats checked and were holding. A cement bond log indicates competent cement with a cement top @ 5530’ MD (3765’ TVD/3,702’ TVDSS), which is 327’ TVD above the Coyote. This well is currently awaiting a coil tubing clean out prior to flowback for clean up. Due to the orientation of this wellbore and its proximity to 3S-705, the DHG on this well will be monitored during the stimulation of the last 3 stages of 3S-705. 3S-723: The 7-5/8” x 4-1/2” casing cement report on 4/12/2025 shows that the job was pumped as designed. The cement job was pumped with 669 BBLs of 15.3 ppg cement with 1 ppb Cemnet after 1st 50 BBLs of cement. During the cement displacement, flow out was observed to be decreasing. Plugs bumped and floats held, but a total of 70bbls of fluid was lost during the job. A cement bond log indicates competent cement with a cement top @ 5056' MD / 4061' TVD with partially bonded cement up to 4,800’ MD. The 5056’ MD / 4061’ TVD top of cement is 116’ MD / 39’ TVD above the Coyote. Palm 1: Three abandonment plugs were placed on 2/21/2001. The three plugs were set as balanced plugs at the following depths: 5,900’-6,620' MD MD with 2755sx of 15.8ppg Class G cement, 5,880'-5,200’ MD with 275sx of 15.8ppg Class G cement, and 4,700'-4,100' MD (3900’ TVDSS) of 250sx of 15.8ppg Class G Cement. The middle abandonment plug was tagged with 20klbs at 5,247' MD/4827 TVDSS, witnessed by AOGCC. A kick off plug was then set at 3,100'-2,660' MD with 300sx (50bbls) of 17.2ppg Class G cement. The kick off plug was tagged at 2,553’ MD/2492’ TVDSS (1546’ TVD above the Coyote). yg gp proximity to 3S-705, the DHG on this well will be monitoredpp during the stimulation of the last 3 stages of 3S-705. 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 one fault transects the Coyote reservoir within one half mile radius of the 3S-705 wellbore trajectory. This fault is north of the toe of the 3S-705 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. As this fault is interpreted to lose throw into the confining interval above the Coyote reservoir it should not affect overburden integrity and therefore its 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) 3S-705 was completed in 2025 as a horizontal injector in the Coyote formation. The well was completed with a 4.5” tubing upper completion and a 7-5/8” x 4-1/2” tapered casing string 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). CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.39426745LEASE3S-705SALES ORDERBHST (°F)LONG-150.1954682FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTEBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)1-1 Shut-In Shut-In1:47:24 1-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:47:24 1-3 Shut-In Shut-In1:42:38 1-4 27# Linear Arsenal Sleeve Shift 5 1,260 30 30 0:06:00 1:42:38 1.00 2.00 27.00 2.000.151-5 27# Linear DFIT 10 1,680 40 40 0:04:00 1:36:38 1.00 2.00 27.00 2.000.151-6 27# Linear Step Rate Test 15 8,400 200 200 0:13:20 1:32:38 1.00 2.00 27.00 2.000.151-7 Shut-In Shut-In1:19:18 1-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:18 0.45 1.00 0.50 2.00 27.00 2.000.151-9 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.000.151-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.000.151-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.000.151-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.000.151-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.000.151-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.000.151-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.000.151-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.000.151-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.000.151-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.152-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:58:59 1.00 2.00 27.00 2.000.152-2 27# Delta Frac Minifrac - Establish Fluid 20 8,400 200 200 0:10:00 1:56:29 0.45 1.00 0.50 2.00 27.00 2.000.152-3 27# Delta Frac Minifrac - Treatment 20 8,658 206 206 0:10:18 1:46:29 0.45 1.0000 0.50 2.00 27.00 2.000.152-4 27# Linear Flush 20 8,578 204 204 0:10:13 1:36:11 1.00 2.00 27.00 2.000.152-5 Shut-In Shut-In 20 8,400 200 200 0:10:00 1:25:58 2-6 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:15:58 0.45 1.00 0.50 2.00 27.00 2.000.152-7 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.000.152-8 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.000.152-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.000.152-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.000.152-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.000.152-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.000.152-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.000.152-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.000.152-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.000.152-16 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.153-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:28 1.00 2.00 27.00 2.000.153-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:15:58 0.45 1.00 0.50 2.00 27.00 2.000.153-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.000.153-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.000.153-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.000.153-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.000.153-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.000.153-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.000.153-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.000.153-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.000.153-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.000.153-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.154-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:28 1.00 2.00 27.00 2.000.154-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:15:58 0.45 1.00 0.50 2.00 27.00 2.000.154-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.000.154-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.000.154-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.000.154-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.000.154-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.000.154-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.000.154-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.000.154-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.000.154-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.000.154-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.155-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:31:47 1.00 2.00 27.00 2.000.155-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:29:17 0.45 1.00 0.50 2.00 27.00 2.000.155-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:19:17 0.45 1.00 0.50 2.00 27.00 2.000.155-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:08:40 0.45 1.00 0.50 2.00 27.00 2.000.155-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 1:01:22 0.45 1.00 0.50 2.00 27.00 2.000.155-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:58:01 0.45 1.00 0.50 2.00 27.00 2.000.155-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:52:01 0.45 1.00 0.50 2.00 27.00 2.000.155-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:45:45 0.45 1.00 0.50 2.00 27.00 2.000.155-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:35:35 0.45 1.00 0.50 2.00 27.00 2.000.155-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:26:10 0.45 1.00 0.50 2.00 27.00 2.000.155-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:19:27 0.45 1.00 0.50 2.00 27.00 2.000.155-12 27# Linear Flush 20 7,614 181 181 0:09:04 0:15:04 1.00 2.00 27.00 2.000.155-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 5-14 Shut-In Shut-InInterval 1Coyote@ 13974.71 - 13978.71 ft - °FInterval 2Coyote@ 13420.46 - 13424.46 ft - °FInterval 3Coyote@ 12920.44 - 12924.44 ft - °FInterval 4Coyote@ 12420.9 - 12424.9 ft - °FInterval 5Coyote@ 11911.85 - 11915.85 ft - °FLiquid AdditivesDry Additives50-103-20915Conoco Phillips - 3S-705Planned Design1 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.39426745LEASE3S-705SALES ORDERBHST (°F)LONG-150.1954682FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTEBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-209156-1 Shut-In Shut-In1:42:39 6-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:42:39 6-3 Shut-In Shut-In1:37:53 6-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:37:53 1.00 2.00 27.00 2.00 0.156-5 27# Linear Displace Dart to Seat 15 7,295 174 174 0:11:35 1:35:53 1.00 2.00 27.00 2.00 0.156-6 27# Linear DFIT 10 2,100 50 50 0:05:00 1:24:18 1.00 2.00 27.00 2.00 0.156-7 Shut-In Shut-In1:19:18 6-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:18 0.45 1.00 0.50 2.00 27.00 2.00 0.156-9 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.00 0.156-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.00 0.156-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.00 0.156-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.00 0.156-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.00 0.156-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.00 0.156-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.00 0.156-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.00 0.156-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.00 0.156-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.157-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:28 1.00 2.00 27.00 2.00 0.157-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:15:58 0.45 1.00 0.50 2.00 27.00 2.00 0.157-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.00 0.157-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.00 0.157-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.0000 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.00 0.157-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.00 0.157-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.00 0.157-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.00 0.157-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.00 0.157-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.00 0.157-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.00 0.157-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.158-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:28 1.00 2.00 27.00 2.00 0.158-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:15:58 0.45 1.00 0.50 2.00 27.00 2.00 0.158-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.00 0.158-4 27# Delta Frac Conditioning Pad 100M 0.5000 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.00 0.158-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.00 0.158-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.00 0.158-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.00 0.158-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.00 0.158-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.00 0.158-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.00 0.158-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.00 0.158-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.159-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:28 1.00 2.00 27.00 2.00 0.159-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:15:58 0.45 1.00 0.50 2.00 27.00 2.00 0.159-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.00 0.159-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.00 0.159-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.00 0.159-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.00 0.159-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.00 0.159-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.00 0.159-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.00 0.159-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.00 0.159-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.00 0.159-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.00 0.15Interval 9Coyote@ 9915.80999999999 - 9919.80999999999 ft - °FInterval 6Coyote@ 11412.38 - 11416.38 ft - °FInterval 7Coyote@ 10915.44 - 10919.44 ft - °FInterval 8Coyote@ 10415.58 - 10419.58 ft - °FConoco Phillips - 3S-705Planned Design2 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.39426745LEASE3S-705SALES ORDERBHST (°F)LONG-150.1954682FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTEBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-2091510-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:28 1.00 2.00 27.00 2.00 0.1510-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:15:58 0.45 1.00 0.50 2.00 27.00 2.000.1510-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.000.1510-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.000.1510-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.000.1510-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.000.1510-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.000.1510-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.000.1510-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.000.1510-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.000.1510-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.000.1510-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.1511-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:29:30 1.00 2.00 27.00 2.000.1511-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:27:00 0.45 1.00 0.50 2.00 27.00 2.000.1511-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:17:00 0.45 1.00 0.50 2.00 27.00 2.000.1511-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:06:23 0.45 1.00 0.50 2.00 27.00 2.000.1511-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:59:05 0.45 1.00 0.50 2.00 27.00 2.000.1511-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:55:44 0.45 1.00 0.50 2.00 27.00 2.000.1511-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:49:44 0.45 1.00 0.50 2.00 27.00 2.000.1511-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:43:28 0.45 1.00 0.50 2.00 27.00 2.000.1511-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:33:18 0.45 1.00 0.50 2.00 27.00 2.000.1511-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:23:53 0.45 1.00 0.50 2.00 27.00 2.000.1511-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:17:10 0.45 1.00 0.50 2.00 27.00 2.000.1511-12 27# Linear Flush 20 5,695 136 136 0:06:47 0:12:47 1.00 2.00 27.00 2.000.1511-13 Freeze Protect Freeze Protect 5 1,260 30 30 0:06:00 0:06:00 11-14 Shut-In Shut-InInterval 10Coyote@ 9416.23999999999 - 9420.23999999999 ft - °FInterval 11Coyote@ 8909.35999999999 - 8913.35999999999 ft - °FConoco Phillips - 3S-705Planned Design3 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.39426745LEASE3S-705SALES ORDERBHST (°F)LONG-150.1954682FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTEBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-2091512-1 Shut-In Shut-In1:39:36 12-2 Freeze Protect Prime Up Pressure Test 5 1,000 24 24 0:04:46 1:39:36 12-3 Shut-In Shut-In1:34:50 12-4 27# Linear Spacer and Dart Drop 15 1,260 30 30 0:02:00 1:34:50 1.00 2.00 27.00 2.000.1512-5 27# Linear Displace Dart to Seat 15 5,376 128 128 0:08:32 1:32:50 1.00 2.00 27.00 2.000.1512-6 27# Linear DFIT 10 2,100 50 50 0:05:00 1:24:18 1.00 2.00 27.00 2.000.1512-7 Shut-In Shut-In1:19:18 12-8 27# Delta Frac Establish Stable Fluid 15 8,400 200 200 0:13:20 1:19:18 0.45 1.00 0.50 2.00 27.00 2.000.1512-9 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.000.1512-10 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.000.1512-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.000.1512-12 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.000.1512-13 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.000.1512-14 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.000.1512-15 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.000.1512-16 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.000.1512-17 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.000.1512-18 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.1513-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:28 1.00 2.00 27.00 2.000.1513-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:15:58 0.45 1.00 0.50 2.00 27.00 2.000.1513-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.000.1513-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.000.1513-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.000.1513-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.000.1513-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.000.1513-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.000.1513-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.000.1513-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.000.1513-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.000.1513-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.1514-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:28 1.00 2.00 27.00 2.000.1514-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:15:58 0.45 1.00 0.50 2.00 27.00 2.000.1514-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.000.1514-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.000.1514-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.000.1514-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.000.1514-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.000.1514-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.000.1514-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.000.1514-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.000.1514-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.000.1514-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.1515-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:18:28 1.00 2.00 27.00 2.000.1515-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:15:58 0.45 1.00 0.50 2.00 27.00 2.000.1515-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:05:58 0.45 1.00 0.50 2.00 27.00 2.000.1515-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 0:55:22 0.45 1.00 0.50 2.00 27.00 2.000.1515-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:48:03 0.45 1.00 0.50 2.00 27.00 2.000.1515-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:44:43 0.45 1.00 0.50 2.00 27.00 2.000.1515-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:38:42 0.45 1.00 0.50 2.00 27.00 2.000.1515-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:32:26 0.45 1.00 0.50 2.00 27.00 2.000.1515-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:22:17 0.45 1.00 0.50 2.00 27.00 2.000.1515-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:12:51 0.45 1.00 0.50 2.00 27.00 2.000.1515-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:06:08 0.45 1.00 0.50 2.00 27.00 2.000.1515-12 27# Linear Spacer and Dart Drop 20 1,470 35 35 0:01:45 0:01:45 1.00 2.00 27.00 2.000.1516-1 27# Linear Pre-Pad 20 2,100 50 50 0:02:30 1:27:36 1.00 2.00 27.00 2.000.1516-2 27# Delta Frac Establish Stable Fluid 20 8,400 200 200 0:10:00 1:25:06 0.45 1.00 0.50 2.00 27.00 2.000.1516-3 27# Delta Frac Pad 20 8,915 212 212 0:10:37 1:15:06 0.45 1.00 0.50 2.00 27.00 2.000.1516-4 27# Delta Frac Conditioning Pad 100M 0.50 20 6,000 143 146 3,000 0:07:18 1:04:29 0.45 1.00 0.50 2.00 27.00 2.000.1516-5 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 2.00 20 2,575 61 67 5,150 0:03:21 0:57:11 0.45 1.00 0.50 2.00 27.00 2.000.1516-6 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 4.00 20 4,270 102 120 17,080 0:06:01 0:53:50 0.45 1.00 0.50 2.00 27.00 2.000.1516-7 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 6.00 20 4,130 98 125 24,780 0:06:16 0:47:50 0.45 1.00 0.50 2.00 27.00 2.000.1516-8 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 7.00 20 6,470 154 202 45,290 0:10:10 0:41:34 0.45 1.00 0.50 2.00 27.00 2.000.1516-9 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 8.00 20 5,800 138 187 46,400 0:09:25 0:31:24 0.45 1.00 0.50 2.00 27.00 2.000.1516-10 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 9.00 20 4,000 95 133 36,000 0:06:43 0:21:59 0.45 1.00 0.50 2.00 27.00 2.000.1516-11 27# Delta Frac Proppant Laden Fluid Wanli 16/20 Ceramic 10.00 20 2,530 60 87 25,300 0:04:23 0:15:16 0.45 1.00 0.50 2.00 27.00 2.000.1516-12 27# Linear Flush 20 4,097 98 98 0:04:53 0:10:53 1.00 2.00 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-In1,184,803 28,210 31,660 3,248,00023:23:47 Interval 12Coyote@ 8410.31999999999 - 8414.31999999999 ft - °FInterval 13Coyote@ 7910.62999999999 - 7914.62999999999 ft - °FInterval 14Coyote@ 7411.37999999999 - 7415.37999999999 ft - °FInterval 15Coyote@ 6912.04999999999 - 6916.04999999999 ft - °FInterval 16Coyote@ 6409.85999999999 - 6413.85999999999 ft - °FConoco Phillips - 3S-705Planned Design4 CUSTOMERConoco Phillips FALSEAPIBFD (lb/gal)8.54LAT 70.39426745LEASE3S-705SALES ORDERBHST (°F)LONG-150.1954682FORMATIONCoyoteDATE Max Pressure (psi)Prop Slurry Design Clean Design Clean Design Slurry Design Prop Stage Interval BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTEBE-6TreatmentStage Fluid Stage Proppant Conc Rate Volume Volume Volume Total Time TimeCrosslinker Surfactant Buffer Catalyst BufferInterval Number Description Description Description(ppg) (bpm) (gal) (bbl) (bbl) (lbs) (hh:mm:ss) (hh:mm:ss)(gpt) (gpt) (gpt) (gpt) (gpt) (ppt) (ppt) (ppt) (ppt)Liquid AdditivesDry Additives50-103-20915Design Total (gal)Design Total (lbs)BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTE BE-6866,4983,200,000(gal) (gal) (gal) (gal) (gal) (lbs) (lbs) (lbs) (lbs)103,12548,000Initial Design Material Volume 389.9 969.6 433.2 1,939.2 26,179.8 1,939.2 145.4-6,780- 0.3703 Whole Units to be ordered--BC-140X2 Losurf-300D MO-67 CAT-3 BA-20 WG-36 OPTIFLO-II OPTIFLO-HTE BE-6-(gpm) (gpm) (gpm) (gpm) (gpm) ppm ppm ppm ppm-Max Additive Rate 0.4 0.8 0.4 1.7 22.7 1.7 1.7 0.1-Min Additive RateProppant TypeWanli 16/20 Ceramic100M---Fluid Type27# Delta Frac27# LinearSeawaterFreeze Protect----Conoco Phillips - 3S-705Planned Design5 Stage Job Size (lb) Top MD (ft) Top TVD (ft) Propped Half- Length (ft) Fracture Height (ft) Avg Fracture Width (in) 1 203,000 13,975 4,048 410 160 0.271 2 203,000 13,420 4,047 410 160 0.288 3 203,000 12,920 4,047 400 160 0.276 4 203,000 12,421 4,049 400 160 0.289 5 203,000 11,912 4,051 400 160 0.285 6 203,000 11,412 4,048 390 165 0.276 7 203,000 10,915 4,047 390 165 0.278 8 203,000 10,416 4,045 400 160 0.278 9 203,000 9,916 4,038 400 160 0.282 10 203,000 9,416 4,032 400 160 0.284 11 203,000 8,909 4,024 440 160 0.301 12 203,000 8,410 4,012 430 165 0.31 13 203,000 7,911 4,011 450 160 0.279 14 203,000 7,411 4,014 440 155 0.278 15 203,000 6,912 4,001 460 165 0.264 16 203,000 6,410 3,999 440 160 0.267 Disclaimer Notice: KRU 3S-705 This model was generated using commercially available modeling software and is based on engineering estimates of reservoir properties. Conoco Phillips is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results Hydraulic Fracturing Fluid Product Component Information Disclosure 2025-06-14 Alaska HARRISON BAY 50-103-20915-00-00 CONOCOPHILLIPS 3S 705 -150.19546822 70.39426745 NAD83 none Oil 4212 1126062.85 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 Produced Water (Density 8.5)Operator Base Fluid Density = 8.50 SEAWATER (SG 8.52)Operator Base Fluid Density = 8.52 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 LoSurf-300D Halliburton Non-ionic Surfactant MO-67 Halliburton pH Control OPTIFLO-HTE Halliburton Breaker OPTIFLO-II DELAYED RELEASE BREAKER Halliburton Breaker WG-36 GELLING AGENT Halliburton Gelling Agent Ceramic Proppant - Wanli Wanli Proppant Sand-Common White-100 Mesh, SSA-2 Halliburton Proppant Calcium Chloride Customer Salt Solution Flow Insurance Copper Patina Energy Tracer OPT 2002-2054 ResMetrics Tracer WPT 1001-1052 ResMetrics Tracer Ingredients Water 7732-18-5 95.00%71.46152%9589796 Corundum 1302-74-5 60.00%14.30751%1920000 Mullite 1302-93-8 40.00%9.53834%1280000 Sodium chloride 7647-14-5 5.00%3.76113%504727 Crystalline silica, quartz 14808-60-7 100.00%0.36026%48345 Guar gum 9000-30-0 100.00%0.19509%26180 Water 7732-18-5 100.00%0.16927%22716 Calcium Chloride 10043-52-4 100.00%0.07452%10000 EDTA/Copper chelate Proprietary 30.00%0.03615%4852 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%0.03296%4424 Water 7732-18-5 100.00%0.03167%4250 Monoethanolamine borate 26038-87-9 100.00%0.02953%3963 Heavy aromatic petroleum naphtha 64742-94-5 30.00%0.01648%2212 Oxyalkylated nonyl phenolic resin Proprietary 30.00%0.01648%2212 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Ammonium persulfate 7727-54-0 100.00%0.01445%1939 Sodium hydroxide 1310-73-2 30.00%0.01025%1376 Ethylene glycol 107-21-1 30.00%0.00886%1189 Ammonium chloride 12125-02-9 5.00%0.00603%809 Oxyalkylated phenolic resin Proprietary 10.00%0.00549%738 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Borate salts Proprietary 60.00%0.00473%636 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Oxylated phenolic resin Proprietary 30.00%0.00433%582 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Walnut hulls NA 100.00%0.00373%500 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Flow Insurance Copper Proprietary 100.00%0.00362%486 Patina Energy Product Stewardship test@patinae nergy.com 6692416025 Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega-hydroxy-, branched 127087-87-0 5.00%0.00275%369 Naphthalene 91-20-3 5.00%0.00275%369 Ammonia 7664-41-7 1.00%0.00121%162 Polyamine Proprietary 30.00%0.00112%150 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00%0.00108%145 Glycol Ether Proprietary 85.00%0.00081%109 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Ammonium acetate 631-61-8 100.00%0.00068%92 1,2,4 Trimethylbenzene 95-63-6 1.00%0.00055%74 Inorganic mineral 1317-65-3 5.00%0.00039%53 Potassium chloride 7447-40-7 5.00%0.00039%53 Sodium chloride 7647-14-5 1.00%0.00034%46 Confidential Proprietary 20.00%0.00029%39 ResMetrics Product Stewardship info@resmetri cs.com 8325921900 Acetic acid 64-19-7 30.00%0.00021%28 Ethylene Glycol 107-21-1 20.00%0.00020%27 Hemicellulase 9025-56-3 5.00%0.00019%25 C.I. pigment Orange 5 3468-63-1 1.00%0.00014%20 Gluteraldehyde 111-30-8 1.00%0.00008%11 Inorganic mineral Proprietary 1.00%0.00008%11 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Calcium magnesium carbonate 16389-88-1 1.00%0.00008%11 Polymer Proprietary 1.00%0.00008%11 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 Cured acrylic resin Proprietary 1.00%0.00004%5 Halliburton Denise Tuck Denise.Tuck @Halliburton. com 281-871-6226 C.I. Pigment Red 5 6410-41-9 1.00%0.00004%5 2,7-Naphthalenedisulfonic acid, 3- hydroxy-4-[(4-sulfor-1- naphthalenyl) azo] -, trisodium salt 915-67-3 0.10%0.00003%4 Methanesulfonic acid, 1-hydroxy-, sodium salt 870-72-4 0.10%0.00001%2 Sodium bisulfate 7681-38-1 0.10%0.00001%2 2-Methyl-4-isothiazolin-3-one 2682-20-4 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 5-Chloro-2-methyl-3(2H)- Isothaiazolone 26172-55-4 0.01%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 supplier’s 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 Administration’s (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: 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 3S’s facilities. Once the well’s 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:Woodard, Madeline E To:Dewhurst, Andrew D (OGC) Cc:Hobbs, Greg S; Lau, Jack J (OGC); Wallace, Chris D (OGC); Guhl, Meredith D (OGC); Ruysschaert, Rodrigo Subject:RE: [EXTERNAL]KRU 3S-705 Frac Sundry (325-375) Date:Tuesday, June 24, 2025 3:00:46 PM Andy, Glad the AOR Excel table is helpful, please let us know of any feedback and we can continue to update its format. The 3S-705 well path is oriented along the measured maximum horizontal stress to create longitudinal fractures along the wellbore. Although there is potential the fracture deviates from longitudinal due to uncertainty in the orientation of the maximum horizontal stress, ConocoPhillips thinks the risk of loss of containment of frac fluids to the 3S-15 wellbore is low. Also, the modeled fracture half-lengths do not exceed the distance from 3S-705 to 3S-15 (stage 10 = 1,335’ away, stage 11 = 1,182’, and stage 12 = 1,220’, measured from the top of the Coyote to the sleeve, which is 85-100’ TVD below the top of the Coyote). 3S-23A is in the ½ mile radius, but 3S-23 and 3S-701A are not. Thanks! Madeline From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, June 24, 2025 11:51 AM To: Woodard, Madeline E <Madeline.E.Woodard@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Lau, Jack J (OGC) <jack.lau@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: [EXTERNAL]KRU 3S-705 Frac Sundry (325-375) 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. Madeline, I am completing my review of the KRU 3S-705 frac sundry and have a question: On previous 3S frac sundries, the KRU 3S-15 well was flagged as not having cement across the Coyote interval. I know it is fully abandoned and not monitorable. Would you confirm the planned frac is not expected to reach this offset well location at the Coyote interval? I also note the statement in your AOR that it should be isolated from above from the 9-5/8” x 7” OA down squeeze. Would you confirm that the following wells are outside the ½-mile radius of the fracturing zone: KRU 3S-23 KRU 3S-23A KRU 3S-701A If so, no need to make any changes, I just want to confirm the offset well locations. I also wanted to say that the AOR Excel table and data delivery changes are helping us efficiently review these frac sundries. Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 From:Loepp, Victoria T (OGC) To:Greg S Hobbs Cc:AOGCC Reporting (CED sponsored); Wallace, Chris D (OGC); Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC) Subject:APPROVAL Re: 3S-705 PTD 225-047 Cement Job Approval and 3S-719 Permit Approval Date:Friday, June 20, 2025 4:07:03 PM Greg, Approval is granted to set the tubing hanger and proceed with operations with the condition that if the memory data indicates a different interpretation of the TOC, CPAI may be required to remediate. I will also forward Talib’s analysis and request that you CPAI address his questions and comments. Thank you, Victoria Sent from my iPhone > On Jun 20, 2025, at 8:51 AM, Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> wrote: > > 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. > Good Morning Victoria, > > Morning Meeting Update from our side on Doyon 25. > > The rig is running tubing, about 500’ into a 5,000’ tubing run. It is anticipated that they will complete the run this evening around 7pm. > > Current forecast is moving the rig tomorrow with spud of 3S-719 late Sunday. > > As Abby noted in her email, the cement job on 3S-705 placed cement well above the 4858’ MD requirement with well bonded cement ~1,000’ MD above that from my review. > > We appreciate the efforts of the AOGCC as the efficiency of our two string well program has significantly reduced originally planned times. > > Have a great weekend! > > Greg > > Greg Hobbs, P.E. > Regulatory Engineer | Wells Team > ConocoPhillips Alaska Inc. > Office: 907-263-4749 > Cell: 907-231-0515 > > <FW: 3S-705 PTD #225-047 - 4-1_2" x 7-5_8" Production Casing Cement.eml> 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); Doyon 25 Drilling Supv; Njoku, Johnson Cc:Davies, Stephen F (OGC); Dewhurst, Andrew D (OGC); AOGCC Reporting (CED sponsored); Coldiron, Samantha J (OGC) Subject:RE: [EXTERNAL]KRU 3S-705 (PTD 225-047) Diverter variance approved Date:Tuesday, June 3, 2025 9:41:15 AM Received, Thank you. Cam Johnson | Drilling Engineer | ConocoPhillips Alaska O: 907.223.6277 | M: 907.720.3162 | ANO-938, 700 G Street, Anchorage, AK From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Tuesday, June 3, 2025 9:23 AM To: Johnson, Cameron <Cameron.Johnson2@conocophillips.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; AOGCC Reporting (CED sponsored) <aogcc.reporting@alaska.gov>; Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Subject: [EXTERNAL]KRU 3S-705 (PTD 225-047) Diverter variance approved 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. Cam, The diverter variance is approved per 20 AAC 25.035(h)(2) for this PTD. Please include this approval with your approved copy of the PTD. Thank you, Victoria Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Chris Brillon Wells Engineering Manager Conoco Phillips Alaska, Inc. 700 G Street Anchorage, AK, 99501 Re: Kuparuk River Field, Coyote Oil Pool, KRU 3S-705 Conoco Phillips Alaska, Inc. Permit to Drill Number: 225-047 Surface Location: 2478 FNL, 898 FEL, S18 T12N R8E, UM Bottomhole Location: 508 FSL, 4854 FWL, S1 T12N R7E, UM Dear Mr.Brillon: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCCreserves 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 AOGCCspecifically 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 AOGCCorder, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 3rdday of June2025. . Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.03 08:03:04 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 14,076 TVD: 4185 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): 64.6 15. Distance to Nearest Well Open Surface: x-476362 y- 5993937 Zone- 4 25.1 to Same Pool: 417' to 3S-714 16. Deviated wells: Kickoff depth: 400 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 2661 40 40 2701 2556 9-7/8" x 8-3/4"7-5/8" 29.7# L80 H563 4991 40 40 5031 3887 9-7/8" x 8-3/4"7-5/8" 33.7# P110-S H563 800 5031 3887 5831 4138 8-3/4" 4-1/2" 12.6# P110-S H563 8244 5656 4082 14076 4185 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: Chris Brillon Contact Email:cameron.johnson2@cop.com Wells Engineering Manager 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 Commission Use Only See cover letter for other requirements. 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. Cameron Johnson Authorized Name: Authorized Title: Authorized Signature: Liner Perforation Depth MD (ft):Perforation Depth TVD (ft): Intermediate Production Conductor/Structural Surface Casing Length Size Cement Volume MD 1152 sx of 11.0 ppg DeepCRETE + 270 sx of 15.8 ppg Class G 196 sx of 11.0 ppg CRETE + 2014 sx of 15.3 ppg Class G + Add's Total Depth MD (ft):Total Depth TVD (ft):Plugs (measured):Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks (including stage data) Cemented to surface with ~10 yds slurry 508 FSL, 4854 FWL, S1 T12N R7E, UM 2560 / 2437 / 2448 415' to ADL380106 GL / BF Elevation above MSL (ft): 1915 1496 P.O. Box 100360 Anchorage, Alaska, 99510-0360 Kuparuk River Field Coyote Oil Pool 2478 FNL, 898 FEL, S18 T12N R8E, UM ADL025528 / ADL380106 / ADL380107 1879 FNL, 858 FWL, S18 T12N R8E, UM 6/17/2025 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ConocoPhillips Alaska Inc 59-52-180 KRU 3S-705 s ype of W l 1b S Class: os N s s N D h Ye h o : well is p G S S 20 A SS S s s No S G E S s s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 11:02 am, May 05, 2025 225-047 YesYes SFD SFD VTL 6/2/2025 Initial BOP test to 5000 psig; subsequent BOP test to 3500 psig Annular preventer test to 2500 psig Intermediate I cement evaluation may use SonicScope under the attached Conditions of Approval Surface casing LOT and annular LOT to the AOGCC as soon as available BOPE testing on a 21-day interval is approved with the attached conditions Review results of cement evaluation logs with AOGCC as soon as available 6/4/2025 50-103-20915-00-00 SFD 6/2/2025 X DSR-5/6/2*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.03 08:03:18 -08'00'06/03/25 06/03/25 RBDMS JSB 060425 <Zhϯ^ͲϳϬϱ 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. .58'66 CPAI’s request to allow BOPE testing on a 21-day interval is approved with the following conditions: - CPAI must continue to implement the Between Wells Maintenance Program as approved by AOGCC. - The initial test after rigging up BOPE to drill a well must be to the rated working pressure as provided in API Standard 53. - CPAI is encouraged to take advantage of opportunities to test within the 21-day time limit. - CPAI must adhere to original equipment manufacturer recommendations and replacement parts for BOPE. - Requests for extensions beyond 21 days must include justification with supporting information demonstrating the additional time is necessary for well control purposes or to mitigate a stuck drill string. ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage , Alaska 99510-0360 Telephone 907-276-1215 May 1, 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill KRU 3S-705 Dear Sir or Madam: ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill an onshore Coyote Injector well from the 3S drilling pad. Th e intended spud date for this well is June 17, 2025. It is intended that Doyon 25 be used to drill the well. 3S-705 will utilize a 13-1/2"” surface hole drilled to TD and 10-3/4" casing will be set and cemented to surface. The 9-7/8” hole will be drilled to ~5381’ MD, where the underreamer will be closed and the 8-3/4" horizontal section will be drilled and geosteered in the Coyote formation. A 7-5/8” x 4-½” tapered casing string will be set and cemented from TD to secure the production casing and cover a 500’ or 250’ TVD above any hydrocarbon-bearing zones (Coyote) per AOGCC regulations. The well will be completed as a cemented, fracture stimulated injector with 7-5/8” x 4-1/2” casing with frac sleeves and fiber optic cable. The 4-½” upper completion will include a production packer with GLM’s and a downhole gauge tied back to surface. A variance is requested for a BOPE test interval of 21 days for this project. Doyon 25 is a strong participant in the CPAI BOPE between well maintenance program, reflected by low failure rates in BOP tests since its entry into the CPAI fleet. The variance allows effective drilling and completion of problematic zones, or longer intervals during the well construction. It is also requested that a variance of the diverter requirement under 20AAC 25.035(h)(2) is granted for well KRU 3S- 705. At 3S , there has not been a significant indication of shallow gas hydrates to date, through the surface hole interval. Please find attached the information required by 20 ACC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1.Form 10-401 Application for Permit to Drill per 20 ACC 25.005 (a) 2.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) or Chris Brillon at 907-265-6120. Sincerely, cc: 3S-705 Well File / Jenna Taylor ATO 1804 Will Earhart ATO 1552 Cameron Johnson Chris Brillon ATO 1548 Drilling Engineer Pat Perfetta ATO-06-662 requested variance of the diverter requirement KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 1 | 12 KRU 3S-705 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 ................................................................................................................ 5 5. MASP Calculations ................................................................................................................................. 5 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 .......................................................................................................... 12 16. Area of Review..................................................................................................................................... 12 KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 2 | 12 1. Well Name Requirements of 20 AAC 25.005 (f) The well for which this application is submitted will be designated as KRU 3S-705 2. Location Summary Requirements of 20 AAC 25.005(c)(2) Location at Surface 2478 FNL, 898 FEL, S18 T12N R8E, UM NAD27 Northing: 5993936.55 Easting: 476361.94 RKB Elevation 39.5’ AMSL Pad Elevation 25.1’ AMSL Top of Productive Horizon (Heel) 1879 FNL, 858 FWL, S18 T12N R8E, UM NAD27 Northing: 5994546.37 Easting: 473314.18 Measured Depth, RKB: 6298‘ MD True Vertical Depth, RKB: 4185‘ TVD True Vertical Depth, SS: 4120‘ TVDss Total Depth (Toe) 508 FSL, 4854 FWL, S1 T12N R7E, UM NAD27 Northing: 6002216.81 Easting: 472058.53 Measured Depth, RKB: 14076‘ MD True Vertical Depth, RKB: 4185‘ TVD True Vertical Depth, SS: 4120‘ TVDss Pad Layout KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 3 | 12 Well Plat KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 4 | 12 3. Proposed Drilling Program Requirements of 20 AAC 25.005(c)(13) 1. MIRU Doyon 25 onto well over pre-installed 20” insulated conductor. 2. Rig up and test riser, dewater cellar as needed. 3. Drill 13-1/2"hole to the surface casing point as per the directional plan, with Spud Mud. (LWD Program: GR/RES/GWD). 4. Run and cement 10-3/4" surface casing to surface. Pressure test casing, if possible, on plug bump to 3500 psi. Results of the cementing operation will be submitted as soon as possible. 5. Install BOPE with the following equipment/configuration: 13-5/8” annular preventer, 7-5/8” fixed rams, blind rams, and 2- 7/8” x 5” VBR’s. 6. Test BOPE to 250 psi low / 5,000 psi high (24-48 hr. regulatory notice). 7. Pick up and run in hole with 8-3/4” x 9-7/8" drilling BHA to drill the production hole section. 8. Pressure test 10-3/4” surface casing to 3500 psi for 30 minutes, if not tested on plug bump. 9. Drill out shoe track and 20’ of new hole. 10. Perform LOT. Minimum LOT required to drill ahead is 11 ppg EMW. 11. Drill 9-7/8" hole to ~5831’ MD (~50’ TVD below top of Coyote). Close the underreamer and drill 8-3/4” to section TD (LWD Program: GR/RES/DEN/NEU) 12. POOH and lay down drilling BHA. 13. Run tapered 7 5/8” x 4-1/2” casing with fiber optic cable and cement to a minimum of 250’ TVD or 500’ MD above any hydrocarbon bearing zones (cementing schematic attached). Pressure test casing, if possible, on plug bump to 4000 psi. 14. RU wireline and log TOC. If casing was not pressure tested on plug bump, pressure test to 4000 psi. 15. RU to run upper completion. 16. Run 4-1/2” upper completion with glass plug, production packer, downhole gauge, and gas lift mandrels. Space out and land tubing hanger. 17. Pressure test hanger seals to 5,000 psi. 18. Pressure test against the glass plug to set production packer, test tubing to 4,200 psi differential pressure, chart test. 19. Bleed tubing pressure to 2200 psi and test IA to 3,850 psi, chart test. 20. Install HP-BPV and test to 1500 psi. 21. Nipple down BOP. 22. Install tubing head adapter assembly. N/U tree and test to 10,000 psi/10 minutes. 23.Freeze protect down tubing and annulus. 24. Secure well. Rig down and move off. Please note – This well will be frac’d tapered 7 5/8” x 4-1/2” casing KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 5 | 12 4. BOP and Diverter Information Requirements of 20 AAC 25.005(c)(3 & 7) Please reference BOP and diverter schematics on file for Doyon 25 Per 20 AAC 25.035.e.1.A: For an operation with a maximum potential surface pressure of 3,000 psi or less, BOPE must have at least three preventers, including: Production Drill and Casing Ram configuration 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 sized to bottom-hole assemblies and drill collars. ii. One with blind rams iii. One annular type x 13-5/8” Annular Preventer x 7-5/8” FBR x Blind Rams x 2-7/8” x 5” VBR It is requested that a variance of the diverter requirement under 20 AAC 25.035(h)(2) is granted. At 3S , there has not been significant indication of shallow gas or gas hydrates through the surface hole interval. There are 5 previously drilled wells (3S-26, 3S-613, 3S-625, 3S-701, 3S-704) within 500’ of the proposed KRU 3S-705 surface shoe location. None of these wells encountered any significant indication of shallow gas or gas hydrates. 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 5 previously drilled wells (3S-26, 3S-613, 3S-625, 3S-701, 3S-704) within 500’ of the proposed KRU 3S-705 surface shoe location. None of these wells encountered any significant indication of shallow gas or gas hydrates. requested variance of the diverter requirement KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 6 | 12 Method 1 Method 2 ܯܲܵܲ = [(ܨܩ × 0.052 )െܩܽݏ ܩݎܽ݀݅݁݊ݐ] × ܸܶܦ ܯܲܵܲ = ܨܲܲ െ (ܩܽݏ ܩݎܽ݀݅݁݊ݐ) × ܸܶܦ Where: FG – Fracture gradient at the casing seat in lb/gal 0.052 – Conversion from lb/gal to psi/ft Gas Gradient – 0.1 psi/ft TVD – True Vertical Depth of casing seat in ft RKB Where: FPP – Formation Pore Pressure at the next casing point Gas Gradient – 0.1 psi/ft The following presents data used for calculation of Maximum Potential Surface Pressure (MPSP) while drilling: Section Hole Size Previous CSG Section TD MPSP psi MPSP MPSP Size MD TVD FG ppg Pore Pressure ppg | psi MD TVD Pore Pressure ppg | psi Method 1 psi Method 2 psi SURF 13-1/2" 20" 80 80 13.2 8.7 36 2701 2556 8.7 1,156 47 47 900 PROD 9-7/8" x 8-3/4" 10-3/4" 2701 2556 14 8.8 1,170 14076 4185 8.8 1,915 1497 2383 1497 (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 KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 7 | 12 6. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) Drill out casing shoe 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 OD (in) Hole Size (in) Weight (lb/ft) Grade Conn. Cement Program 20 42 94 H40 Welded Cemented to surface with 10 yds slurry 10-3/4" 13-1/2" 45.5# L80 H563 Cement to Surface 7-5/8" 9-7/8" 29.7# 33.7# L80 P110-S H563 250’ TVD or 500’ MD, whichever is greater, above highest significant hydrocarbon bearing zone 4-1/2" 8-3/4" 12.6# P110-S H563 10-3/4" Surface Casing run to 2701' MD/ 2556' TVD Cement Plan: Cement from 2701’ MD to 2201’ (500’ of tail) with Class G + Adds @ 15.8 ppg, and from 2201' to surface with 11.0 ppg DeepCRETE. Assume 200% excess annular volume in permafrost and 50% excess below the permafrost (1757’ MD), zero excess in 20” conductor. Lead 390 bbls => 1152 sx of 11.0 ppg DeepCRETE + Add's @ 1.9 ft³/sk Tail 56 bbls => 270 sx of 15.8 ppg Class G + Add's @ 1.17 ft³/sk 7-5/8" x 4-1/2” Production Casing run to 14076' MD/ 4185' TVD Cement Plan: Primary cement job consists of a 15.3 ppg Class G slurry from TD to the heel at 6298’ MD and 11.0 ppg CRETE lead cement with a designed top at 4919’ MD, which is 250' TVD above the prognosed shallowest hydrocarbon bearing zone Top Coyote, K3. If a shallower hydrocarbon zone of producible volumes, is encountered while drilling, a longer primary job or a 2 nd stage cement job will be performed to isolate this zone. Assume 10% excess annular volume. Lead 66 bbls => 196 sx of 11.0 ppg CRETE + Add's @ 1.9 ft³/sk Tail 470 bbls => 2014 sx of 15.3 ppg Class G + Add's + Add's @ 1.31 ft³/sk KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 8 | 12 8. Drilling Fluid Program (Requirements of 20 AAC 25.005(c)(8)) Surface Production Hole Size in 13-1/2" 9-7/8" 8-3/4" Casing Size in 10-3/4" 7-5/8" 4-1/2" Density ppg 9-9.8 ppg 9.5-10.0 ppg 9.5-10.0 ppg PV cP ALAP 10-30 10-30 YP lb./100 ft2 35-50 8-16 8-16 Funnel Viscosity s/qt 150-300 40 - 65 40-65 Initial Gels lb./100 ft2 50 N/A N/A 10 Minute Gels lb./100 ft2 60 N/A N/A API Fluid Loss cc/30 min <45 N/A N/A HPHT Fluid Loss cc/30 min n/a <4 <4 pH 8.5-9.5 9.5 – 10.0 9.5-10.0 Oil/Water Ratio N/A 65/35 – 70/30 65/35 – 70/30 Surface Hole: A freshwater Spud Mud will be used for the surface interval. Keep flow line viscosity at ± 200 sec/qt while drilling and running casing. Reduce viscosity prior to cementing. Maintain mud weight ч10.0 ppg by use of solids control system and dilutions where necessary. Production: NAF system will be used. Ensure good hole cleaning by maximizing fluid annular velocity and monitoring drilling trends and adjusting drilling parameters. Maintain mud weight from 9.5-10.0 ppg and be prepared to add loss circulation material as needed. The horizontal production interval will be drilled with NAF system weighted to 9.5-10.0 ppg. MPD will be available for adding backpressure during connections if necessary. Diagram of Doyon 25 Mud System on file. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 9 | 12 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) disposed of in the landfill. KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 10 | 12 14. Drilling Hazards Summary 13-1/2" Hole | 10-3/4" Casing Interval Event Risk Level Mitigation Strategy Conductor Broach Low Monitor cellar continuously during interval. Well Collision Low Anti-collision shows no close approach wells, traveling cylinder diagrams used. Gas Hydrates Low If observed – control drill, reduce pump rates and circulating time, reduce mud temperatures Clay Balling Medium Maintain planned mud parameters and flow rates, increase mud weight, use sweeps to scour tools, reduce fluid viscosity, control ROP Abnormal Pressure Low Evacuation drills, increased mud weight. Shallow hazard study noted minimal risk Lost Circulation Medium Reduce pump rates, maintain mud rheology, add lost circulation material, follow casing tripping surge schedule, use of low density cement slurries, 9-7/8" Hole | 7-5/8" Casing Interval Event Risk Level Mitigation Strategy Lost circulation Low Reduce pump rates, reduce tripping speeds, ECD monitoring, mud rheology, add lost circulation material Hole swabbing on trips Medium Reduce trip speeds, condition fluid before trips, monitor hole fill, pump out of hole, follow tripping schedules, Use of MPD system to offset swab effects Abnormal Pressure in Overburden Formations Low Well control drills, check for flow during connections, increase mud weight as needed. Shallow hazard study noted minimal risk Hole Cleaning Low Monitor drilling trends (ECD, pump pressure, torque/drag trends). Control drill and use best hole cleaning practices 8-3/4" Hole | 4-1/2" Casing - Horizontal Production Hole Event Risk Level Mitigation Strategy Lost circulation Low Reduce pump rates, reduce tripping speeds, ECD monitoring, maintain mud rheology, add lost circulation material Hole swabbing on trips Medium Reduce trip speeds, condition mud prior to trips, monitor hole fill, pump out of hole, real time ECD monitoring, use of MPD system to offset swab Abnormal Reservoir Pressure Low Well control drills, check for flow during connections, increased mud weight if needed Differential Sticking Low Uniform reservoir pressure along lateral, keep pipe moving, control mud weight Hydrogen Sulfide gas Low H2S drills, gas detection systems, alarms, standard well control practices, H2S scavengers available To be posted in Rig Floor Doghouse Prior to Spud KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 11 | 12 Well Proximity Risks: 3S will be a multi-well pad. Directional drilling / collision avoidance information as required by AOGCC 20 ACC 25.050 (b) is provided in the following attachments. Drilling Area Risks: x Reservoir Pressure: Unlikely to encounter any abnormal pressure however, the rig will be prepared to weight up the drilling fluid if required. Weak sand stringers could be present in the overburden. LCM material will be available to heal any lost circulation in the intermediate section. x Lost Circulation: Standard LCM material and well bore strengthening pills are expected to be effective in dealing with lost circulation, if encountered x Swabbed Kicks Good drilling and tripping practices will be stressed to minimize the potential of swabbing in an influx. Hole fill will be continuously monitored during trips. KRU 3S-705 AOGCC 10-401 APD 5/2/2025 KRU 3S-705 AOGCC 10-401 APD 12 | 12 15. Proposed Completion Schematic 16. Area of Review See Below P&A'd WellsWell Name PTD API StatusTop of Zone of InterestIsolation Stage TOCMethod of TOC LossesZonal isolationComments3S-15 202-254 50-103-20444-00-00 P&Ad59448130CBLNoThis well targeted the Kuparuk formation. The well was completely plugged and abandoned per state regulations. A cement retainer was set at 7790' RKB and 25.6 ppg of 15.8 ppg Class G cement was pumped through the retainer across the perforations into the tubing. 1 bbl of cement was left on top of the retainer. TOC was tagged at 7749' RKB. Tubing was punched from 7692' RKB to 7696' RKB. Production by surface casing annulus (OA) was cemented with 120 bbls of permafrost cement as an OA down squeeze from surface to the surface casing shoe at 3561' RKB. 294 bbls of 15.8 ppg Class G was pumped down the tubing and up the IA to surface. The well was excavated 4' below original grade, tree and wellhead removed, well capped, and excavation back-filled. Abandonment approved by AOGCC on September 8, 2020.The 7" CBL log data was re-evaluated and the top of quality cement was confirmed at 8130' MD / 5923' TVD (RKB). There is no data to evaluate cement coverage across the Coyote interval.3S-17A / 17 203-080 50-103-20448-01-00 P&Ad5806Perf/Wash/Cement above the Coyote5707 LogTOC: 5707' MD / 3965' TVDSS in annulus and cement seen at surface.The Coyote was cemented via perf wash and cement operations. Perforations from 5,707'-5,857' MD in the 7" casing were cemented through with 68 bbls of 15.8ppg cement. The 7" casing was cemented via coil with 22bbls of 15.8ppg cement. The top cement job was completed with 223 bbls of 15.8 ppg Class G cement to surface. Final abandonment operations were then conducted and witnessed by AOGCC.TOC in the annulus was determined by log at 5,707' MD. TOC in the casing was tagged at 5,273' MD and a MIT-T performed to 1,500 psi, witnessed by AOGCC. Final abandonment was witnessed and approved by AOGCC on 9/25/233S-18 202-206 50-103-20433-00-00 P&Ad4661Perf/Wash/Cement above the Coyote4561 IBC/CBLTOC: 4561' MD / 4000' TVDA cement retainer was set at 6564' MD. 18 bbls of15.8 ppg Class G cement was pumped through the retainer, squeezing 10.2 bbls into the perfs in the Kuparuk A and C. 2 bbls of 15.8 ppg Class G cement was left on top of the retainer. This was tagged at 6300' MD and pressure tested, witnessed by AOGCC. The 3-1/2" tubing was pulled from a cut at 6283' MD. A CIBP was set 4736' MD. The 7" casing was perforated from 4561' MD -4711' MD. The perfs were washed. The performations were cemented 67.8 bbls of 15.9 ppg cement. TOC inside casing was tagged at 3625' RKB and pressure tested. An OA downsqueeze was performed to cement the OA to the surface casing shoe by pumping 52 bbls of 15.8 ppg lead cement with LCM followed by 40 bbls of 15.8 ppg tail cement. The 7" casing was cemented from 3683' MD to surface with 158 bbls of Class G Cement. Final abandonment operations were completed and approved by AOGCC on March 31, 2024.3S-22 203-011 50-103-20446-00-00 P&Ad5391Perf/Wash/Cement above the Coyote5291 CBLTOC: 5,291' MD / 3,960' TVDSS in annulus and cement seen at surface.Original drilling did not cover the zone of interest. A CBL was run prior to the P&A showing the orginal cement height at 6255' MD. The P&A of the well included a perf/wash/cementing operation. A CIBP was set at 5467' MD, the casing was then perforated from 5291' MD to 5441' MD. 68 bbls of cement was pumped leaving cement ~150' MD above the perforations inside casing. The cement inside the casing was cleaned out and a CBL was run, confirming TOC at 5291' MDMoraineWell Name PTD API StatusTop of Zone of Interest Isolation StageTOCMethod of TOC LossesZonal isolationComments3S-606 223-111 50-103-20870-00-00 Water Injection5545 7-5/8" Casing Cement3950SonicScopeNoTOC: 3950' MD / 3163' TVDFlood lines with 5 bbls of water @ 2 bpm, 100 psi and kick out lower wiper plug. PT lines to 4000 psi (good). Pump 61 bbls of tuned 10.5 ppg prime spacer @ 3-5 bpm 430 psi, 15% f/o. Kick out 2nd plug with 111 bbls of 15.3 ppg cement (with BMII, cement wet @ 04:40) @ 3 bpm, ICP - 300, FCP - 294, 17% f/o. Pump 29 bbls of 15.3 ppg cement(without BMII) @ 3 bpm 294 psi (140 bbls total cement). Drop top plug and chase with 20 bbls of fresh water @ 5 bpm, 169 psi, 12% f/o. Line rig pumps and chase cement with 9.6 treated FWP @ 8 bpm, 61 psi, 24% f/o. Catch cement @ 1883 strokes (189 bbls). Observe psi climb to 150. Reduce rate to 6 bpm, 700 psi, 27% f/o. Observe pressure climb to 1184 psi @ 3000 stks. Reduce rate to 3 bpm, 1025 psi. Bump plug @ 3132 stks (315 bbls). Increase pressure to 1500 and hold for 5 min. Bleed off pressure and check floats (good). CIP @ 6:38 hrs. Full returns through job.3S-610 223-126 50-103-20875-00-00 Producer5775 7-5/8" Casing Cement3548SonicScopeNoTOC: 3548' MD / 3156' TVDCement 7-5/8" intermediate casing string.Drop 1st bottom wiper plug, flood lines with water and pressure test lines to 4000 psi.Pump 60 bbls of 10.5 ppg tuned primed spacer at 4 BPM and 360 psi. Drop 2nd bottom wiper plug and pump 201 bbls of 15.3 ppg primary cement with BMII at 4 BPM and 100 PSI ICP.Follow with 22 bbls of 15.3 ppg primary cement without BMII at 4 BPM. Shut down cement pumps and drop top wiper plug.Pump 20 bbls 8.33 ppg fresh water. Line up on rig mud pumps to displace cement with 389.5 bbls of 9.5 ppg FWP at 8 BPM.151 psi ICP. Pump at 8 BPM to1919 strks, slow rate to 6 BPM 1016 psi and pump to 3713 stks and slow rate to 3 BPM at 3915 strks. Did not bump plugs. FCP 1140 psi. Cement in place at 04:56. Bleed down pressure and check floats, floats are holding. 3S-611 218-103 50-103-20774-00-00 Producer8775 7-5/8" Casing Cement 8228SonicScopeNoTOC: 8228' MD / 3968' TVDPump 5 bbls water. Test lines to 4000 psi. Drop lower bottom plug. Batch up and pump 76.3 bbls of 12.5 ppg MudPush II, 4 bpm, 380 psi, 15% FO. Drop upper bottom plug. Batch up and pump 270.7 bbls 15.8 ppg Class G cement , 5.2 bpm, 215 psi, 22% FO. Drop top plug. Pump 10 bbls water. Swap to rig and displace with 9.4 ppg LSND. Land casing at 3350 stks with 83K hookload. Reduce rate to 3 bpm at 4600 stks. Initial rate at 7 bpm, 180 psi, 24% FO. Final rate 3 bpm, 1080 psi, 12% FO. Bump plug at 5629 stks. Pressure up to 1500 psi and hold for 5 mins. CIP at 04:59 hrs. Full returns through job.3S-612 218-111 50-103-20777-00-00 WAG Injection9471 7-5/8" Casing Cement8270SonicScopeNoTOC: 8270' MD / 3832' TVDPump 5 bbls water. Test lines to 4000 psi. Drop bottom plug. Batch & pump 75 bbls of 12.5 ppg MudPush II, @ 3 bpm, W/ ICP=450 FCP=220 W/ 8% FO. Drop intermediate plug. Batch & pump 303 bbls 15.8 ppg Class G cement @ 5 BPM ICP=305 FCP=215 psi, w/15% FO. Drop top plug. Pump 10 bbls water. Swap to rig and displace with 9.5 ppg treated LSND @ 7 bpm ICP=121psi, FCP= 676 psi. Land casing @ 3650 STKS W/67K hookload. Reduce rate t/6 bpm @ 5075 stks, w/ 1100 psi, F/O=16% Reduce Rate T/ 3 bpm, @ 6700 STKS,ICP= 955 FCP=1071 8% F/O. Bump plug 6166 STKS. Pressure up to 1500 psi, hold 5 Mins, verify floats. CIP at 1705 hrs. Full returns through job.Very close proximity to 3S-705. Careful monitoring during future operations recommended. SFDThere is no data to evaluate cement coverage across the Coyote interval.The Coyote was cemented via perf wash and cement operations.Separated from 3S-705 by over 1,000 feet, so interference with frac ops is highly unlikely. Monitoring during future ops recommended. SFDabove the Coyote 3S-613 216-020 50-103-20735-00-00 WAG Injection72677-5/8" Casing Cement Two stage6100 SonicScopeNoTOC: 6100' MD / 3713' TVDPJSM- PT lines to 4000 psi. Pump 25 bbls of CW100 @ 4.5 bpm, 236 psi, FO 12%. Pump 20 bbls of 12.5 ppg MPII @ 4.5 bpm, 200 psi, FO 12%. Drop bottom plug. Chase w/ 47 bbls of 15.8 ppg cement @ 4.5 bpm, ICP 200 psi, FCP 130 psi, FO 18%. Drop top plug. Pump 10 bbls of H2O @ 4.5 bpm, 21 psi, FO 3%. Swap to rig pump & chase with 9.3 ppg LSND mud @ 4.5 bpm, catching plugs @ 1300 strokes, 97 psi, FO 14%, FCP 441 psi, FO 12%. Bump plug @ 4800 strokes pressuring up to 941 psi. Hold pressure for 5 min & check floats good. Reciprocated casing through out job to 4300 strokes displacement, landing hanger. PU 305K, SO 127K. CIP @ 16:15 hrs. Full returns through job.PJSM- line up to cementer. SLB pump 30 bbls of CW100 @ 6 bpm, 290 psi. Pump 30 bbls of 12.5 ppg MPII @ 4.5 bpm, 180 psi. Pump 189 bbls of 15.8 ppg cement @ 5 bpm, 200 psi, slow to 3 bpm, 57 psi. Drop top closing plug. Pump 10 bbls of H2O at 3 bpm, 190 psi. Swap to rig & pump 9.3 ppg LSND @ 5 bpm, ICP 250 psi, FCP 870 psi. Reduce rate at 4470 strokes to 3 bpm, 800 psi. Bump plug @ 4593 strokes. Pressure up & close stage collar @ 1800 psi, increase to 2100 psi & hold for 5 min. Bleed off pressure & check stage collar closed, good. CIP @ 23:11. Full returns through job.3S-617 223-085 50-103-20864-00-00 Water Injection5911 7-5/8" Casing Cement3841SonicScopeNoTOC: 3841' MD / 3155' TVDPerform cement job for 7-5/8”" intermediate. casing as per Halliburton program, Flood lines with 5 bpm H2O 278 psi, Pressure Test lines to 4000psi,Drop #1 bottom plug , pump 60 bbls tuned 10.5 ppg spacer @ 3.75 bpm/ 573 psi 12% F/O, Drop #2 bottom plug, pump 142 bbls 15.3 ppg primary cmt with BM11 @ 6 bpm 787 psi 14% f/o, pump 22 bbls 15.3 ppg primary cmt without BM11 @ 4 bpm 275 psi 10% f/o, Drop top plug, pump 20 bbls fresh H2O, line up to rig pumps to displace. with 337 bbls @ 6 bpm 207 psi 14% f/o f/ 2620 strokes. Cont. displacement @ 6 bpm 1045 psi F/O 13% f/ 3400 strokes, Slow rate to 3 bpm 852 psi f/200 strokes, Slow rate to 2.5 bpm 887 psi for 200 strokes, Slow rate t/3 bpm @ 975 psi, Did not Bump plug. Stop pumping at 3593 strokes hold for 10 min. Bleed off/ check floats. Shut in to monitor floats Cement in place at 2315 hrs. Full returns observed through job.3S-620 214-167 50-103-20695-00-00 Producer6534 7-5/8" Casing Cement5400Sonic ScopeYes - 48.45 bblsLog started below TOC. TOC is above 5400' MD / 3514' TVDPJSM, batch up CW-100, flood lines w/ H2O & test lines 300 & 4100 psi. Pump 50 bbls CW-100 @ 4 bpm, 400 psi. Pump 53 bbls of Mud Push II, 11.5 ppg, 4-6 bpm, 250-575 psi. Batch cement & drop bottom plug. Pump 181 bbls of Tail Cement, 15.8 ppg, 4-6 bpm, 150-300 psi. Drop top plug & pump 10 bbls of H2O. Swap to rig & pump 419 bbls of 9.7 ppg mud, 6 bpm, ICP 170 psi, FCP 1000 psi. Pressure up 500 psi over FCP to 1500 psi & hold for 5 min. Bleed off & check floats, good. CIP @ 20:38 hrs. Total losses for cement job 48 bbls.3S-624 223-104 50-103-20868-00-00 Producer5649 7-5/8" Casing Cement3555Sonic ScopeNoTOC: 5649' MD / 4092' TVDPerform cement job for 7-5/8”" intermediate. casing as per Halliburton program, Flood lines with 5 bpm H2O 278 psi, Pressure Test lines to 4000psi. Drop #1 bottom plug , pump 60 bbls tuned 10.5 ppg spacer @ 4.5 bpm/ 435 psi 12% F/O, Drop #2 bottom plug, pump 123 bbls 15.3 ppg primary cmt with BM11 @ 5.7 bpm 500 psi 14% f/o, pump 22 bbls 15.3 ppg primary cmt without BM11 @ 5.5 bpm 2212 psi 10% f/o, Drop top plug, pump 20 bbls fresh H2O, line up to rig pumps to displace. with 321 bbls @ 6 bpm 1230 psi 14% f/o from 2979 strokes. Cont. displacement @ 3 bpm 1135 psi F/O 13%, Slow rate to 3 bpm @ 1135 psi, Bump plug 3189 strokes.1824 psi, Stop pumping at strokes hold for 5 min. Bleed off/ check floats. floats held.Cement in place at 23:00 hrs.3S-625 222-079 50-103-20842-00-00 WAG Injection8415 7-5/8" Casing Cement7850Sonic ScopeYes - 21 bblsTOC: 7850' MD / 3969' TVDDropped 1st bottom plug, Pumped 60 Bbl's tuned prime spacer 12.5 ppg with BMII @ 5 BPM while reciprocating, PUW 175K, SOW 120K. Dropped 2nd bottom wiper plug and followed with 264 bbls 15.3 ppg Lead Cement with BMII, pumped at average 3-5 bpm. Followed with 33 bbls 15.3 ppg Tail Cement without BMII, pumped at average 3-5 bpm. Dropped top plug. HES displaced with 10 bbls fresh water. Displaced 574 bbls with 9.6 ppg mud using rig pump at 6 bpm, ICP 150 psi, FCP 1,440 psi slowing to 3 bpm last 10 bbls. Did not bump plug (pumped 50% shoe track volume). Observed burst disk at 475 psi 231 bbls into displacement (14 bbls late). CIP at 06:04 hrs 9-29-2022. Standing pressure 666 psi. Bleed pressure off (1.6 bbls back) and floats held. Note: Shoe @ 12,842.72', F.Collar @ 12,753.60'. Losses circulating and cementing 21 bbls. Note: Casing was reciprocated and rotated at 20 rpm with 15k-18k torque during job with StreamFlo equipment and landed when plugs dropped, spacer and lead cement cleared shoe then resumed reciporicating and rotating. 480 bbls into displacement SOW decreased from initial of 155k to 111k while rotating and the decision was made to land the casing hanger and not reciprocate or rotate any longer. SOW without rotating 75k prior to landing - block weight 62k.3S-626 224-007 50-103-20878-00-00 WAG Injection6731 7-5/8" Casing Cement5908Sonic ScopeNoTOC: 5908' MD / 3775' TVDPump stage #1 15.3 PPG primary cement @ 3.74 BPM, 275 PSI, 29% F/O, 184 BBLS pumped. 00:37 hr dropped top shut off plug witnessed by CPAI Rep. Pump 20 BBLS fresh H2O @ 2 BPM, 138 PSI, 27% F/O. 00:40 HRS displace with rig pumps with 9.6 PPG FWP, @ 3 BPM, 27 PSI, 26% F/O 800 strokes total, pump 10.5 PPG tuned prime spacer @ 3 BPM, 60 PSI, 24% F/O, 558 strokes total, displace with 9.6 PPG FWP as per step down schedule initial rate @ 5.5 BPM 57 PSI, 23% F/O, final rate @ 2 BPM 1275 PSI, 21% F/O. bump plug @ 1808 PSI, 3972 strokes total. check floats (good) open stage cementer @ 3492 PSI2ND stage cement job 7 5/8" intermediate casing as per HES pump 62.5 BBLS 10.5 PPG, spacer@ 4 BPM / @ 345 PSI, PUMP 42.3 BBLS 15.3 PPG of primary cement BMII @ 3.4 BPM/ @ 375 PSI, shutdown and drop closing plug & chase with 20 BBLS H20, swap to rig & displace with 282 BBLS @ 6 BPM/ 368 PSI @ 2,930 Strokes Initial pressure 1,100PSI, pressure up to 2,400PSI hold for 5 minutes3S-626PB1 224-007 50-103-20878-70-00 P&Ad6743 7-5/8" Casing Cement4523Sonic ScopeNoTOC: 4523' MD / 3179' TVDCement job 7 5/8" intermediate. casing as per Halliburton pump schedule, flood lines with 20 bbls H2O @ 2.5 bpm/40 PSI, pressure test lines to 4,500 PSI (witnessed by CPAI Rep.), pump 59 BBLS tuned 10.5 PPG prime spacer bridge maker 2 @ 4.5 BPM 290 PSI, drop bottom plug, pump 160 BBLS 15.3 PPG primary cement with bridge maker 2 followed by 22 BBLS 15.3 PPG primary cement @ 3.5 BPM 170 PSI, shutdown and drop top plug kick out with 20 BBLS fresh H20, line up to rig pumps & displace. with 405 BBLS @ 8 BPM /60 PSI. @ 1,500 strokes slow rate to 6 BPM, 41 PSI for 1,775 strokes, @ 3,275 stroke slow to 4 BPM, 785 PSI for final strokes, bump plug @ 4,007 strokes 1,050 PSI , pressure up to 1,630 PSI, hold for 5 minutes. bleed back 4bbls, check floats, (good) OWFFCoyote3S-714 224-151 50-103-20903-00-00 WAG Injection6431 7-5/8" Casing Cement5530Sonic ScopeNoTOC: 5530' MD / 3765' TVDLine up to cementers. Load bottom plug #1 and pump 5 bbls of H2O. Test lines to 4000 PSI – test good. Shut Down. Load bottom plug #2 pump 60 BBLS 12.5 PPG Mud Push 5 BPM/150 PSI. Swap to cementers. Pump 57 BBLs 15.3 PPG Tail cement. Shut Down. Load top plug. Cementers pump 10 BBLS FW. Swap to rig pumps. Displace w/ rig at 6 BPM. Slow rate to 3 BPM at 20 BBLs left. Bump plug at 2873 Stks. FCP= 380 PSI. Pressure up to 1902 PSI and hold. Bleed off and check floats. Good. 40 498 498 798 798 1098 1098 1498 1498 1998 1998 2498 2498 2998 2998 4998 4998 7998 7998 10998 10998 18618 3S-705 (I12) wp09.1 Plan Summary 3S-705 (I12) wp09.1 3S-714 3S-723 3S-18 3S-07 3S-14 3S-615 3S-701A 3S-701 3S-739 (I11) wp03 3S-613 3S-606 3S-611 3S-611PB1 3S-03 3S-735 (P11) wp04 3S-26 PALM 1 3S-22 3S-719 (P02) wp05 3S-612 3S-610 3S-6243S-722 3S-16 3S-718 3S-08CL1 3S-08CL1PB1 3S-09 3S-704 3S-703 (P12) wp05.1 3S-17 3S-17A 3S-08C 3S-08 3S-08B 3S-08A 3S-06 3S-626 3S-626PB1 3S-602 3S-15 3S-10 3S-737 (P05) wp03 3S-625 3S-620 3S-617 3S-06A 0 4 Dogleg Severity0 2000 4000 6000 8000 10000 12000 14000 Measured Depth 10-3/4" Surface Casing 7" Intermediate Casing 4-1/2" Production Liner 50 50 100 100 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [100 usft/in] 3S-07 3S-701A 3S-701 3S-729 (I22A) wp03 3S-606 3S-731 (P07) wp04 3S-610 3S-718 3S-08CL1 3S-08CL1PB1 3S-09 3S-704 3S-728 (I09) wp04 3S-703 (P12) wp05.1 3S-08C 3S-08 3S-08B 3S-08A 3S-06 3S-733 (I07) wp04 3S-602 3S-10 3S-06A 0 4500 True Vertical Depth0 2000 4000 6000 8000 10000 12000 Vertical Section at 332.35° 10-3/4" Surface Casing 7" Intermediate Casing 4-1/2" Production Liner 0 28 55 Centre to Centre Separation0 2000 4000 6000 8000 10000 12000 14000 Measured Depth Equivalent Magnetic Distance DDI 6.911 SURVEY PROGRAM Date: 2019-05-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 39.50 1500.00 3S-705 (I12) wp09.1 (3S-705)r.5 SDI_URSA1 1500.00 2597.13 3S-705 (I12) wp09.1 (3S-705)MWD+IFR2+SAG+MS 2597.13 14075.78 3S-705 (I12) wp09.1 (3S-705)MWD+IFR2+SAG+MS Surface Location North / 5993687.09 East / 1616394.01 Ground / 25.10 CASING DETAILS TVD MD Name 2472.00 2597.13 10-3/4" Surface Casing 4184.60 6297.81 7" Intermediate Casing 4184.62 14046.71 4-1/2" Production Liner Mag Model & Date:BGGM2024 31-May-25 Magnetic North is 13.73° East of True North (Magnetic Declination) Mag Dip & Field Strength:80.60°57172.25nT SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Annotation 1 39.50 0.00 0.00 39.50 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Build 1.50 3 400.00 1.50 200.00 399.99 -1.23 -0.45 1.50 200.00 -0.88 Start DLS 2.00 TFO 10.00 4 550.00 4.48 206.67 549.77 -8.32 -3.75 2.00 10.00 -5.63 Start 250.00 hold at 550.00 MD 5 800.00 4.48 206.67 799.00 -25.78 -12.53 0.00 0.00 -17.03 Start Build 2.50 6 1503.71 22.08 206.67 1481.20 -169.67 -84.82 2.50 0.00 -110.94 Start 107.91 hold at 1503.71 MD 7 1611.62 22.08 206.67 1581.20 -205.92 -103.02 0.00 0.00 -134.60 Start DLS 3.50 TFO 135.00 8 1811.62 17.79 223.05 1769.32 -261.90 -140.81 3.50 135.00 -166.66 Start DLS 3.00 TFO 60.00 9 2597.13 35.74 259.40 2472.00 -393.66 -452.66 3.00 60.00 -138.67 Start 50.00 hold at 2597.13 MD 10 2647.13 35.74 259.40 2512.58 -399.03 -481.37 0.00 0.00 -130.10 Start DLS 3.50 TFO 5.02 11 3210.88 55.42 261.46 2905.25 -464.41 -876.63 3.50 5.02 -4.60 Start 835.95 hold at 3210.88 MD 12 4046.83 55.42 261.46 3379.69 -566.60 -1557.27 0.00 0.00 220.71 Start DLS 3.75 TFO 87.04 13 6097.81 85.00 339.00 4174.13 413.58 -2978.44 3.75 87.04 1748.43 Start Build 2.00 14 6297.81 89.00 339.00 4184.60 600.00 -3050.00 2.00 0.00 1946.77 Start 20.00 hold at 6297.81 MD 15 6317.81 89.00 339.00 4184.95 618.67 -3057.17 0.00 0.00 1966.63 Start DLS 2.00 TFO 85.10 16 6920.65 90.04 351.01 4190.00 1199.89 -3212.83 2.00 85.10 2553.73 Start 7155.12 hold at 6920.65 MD 17 14075.78 90.04 351.01 4184.60 8267.16 -4330.64 0.00 0.00 9332.76 TD at 14075.78 FORMATION TOP DETAILS TVDPath Formation 1455.60 Top Ugnu 1714.60 Base Permafrost 2026.60 Top West Sak 2469.60 Base West Sak 2678.60 Campanian Sand (C-80) 3458.60 C-50 3909.60 C-35 4085.60 Top Coyote (Top Nanushuk), K3 Plan 39.5 + 25.1 @ 64.60usft (Doyon 25) Project: Kuparuk River Unit_2Site: Kuparuk 3S PadWell: Plan: 3S-705 (I12)Wellbore: 3S-705Design: 3S-705 (I12) wp09.1040008000South(-)/North(+) (2000 usft/in)-8000 -4000 0 4000 8000West(-)/East(+) (2000 usft/in)3S-705 TD 1320 ft3S-705 T1 1320 ft3S-705 TD 0328243S-7143S-183 S -0 7 3S-143S-6153S-727 (P23A) wp033S-729 (I22A) wp033S-739 (I11) wp033S-6133S-6063S-6113S-611PB13 S -0 33S-731 (P07) wp043S-735 (P11) wp043 S -2 6 PALM 13 S -2 2 3S-719 (P02) wp053S-6123S-6103S-6243S-7223S -163S-7183S-08CL13S-08CL1PB13S-093S-728 (I09) wp043S-703 (P12) wp05.13S-173 S -1 7 A 3 S -0 8 C 3S-083S-08B3S-08A 3S-063S-6263S-626PB13S-733 (I07) wp043S-6023S-153S-103S-737 (P05) wp033S-6253S-6203S-6173S-06A3S-72310-3/4" Surface Casing7" Intermediate Casing4-1/2" Production Liner500100015002 0 0 0 2 5 0 0 3 0 0 0 3500400041853S-705 (I12) wp09.1Plan View with offset wells Project: Kuparuk River Unit_2Site: Kuparuk 3S PadWell: Plan: 3S-705 (I12)Wellbore: 3S-705Design: 3S-705 (I12) wp09.1040008000South(-)/North(+) (2000 usft/in)-8000 -4000 0 4000 8000West(-)/East(+) (2000 usft/in)3S-705 TD 1320 ft3S-705 T1 1320 ft3S-705 TD 03282410-3/4" Surface Casing7" Intermediate Casing4-1/2" Production Liner500100015002 0 0 0 2 5 0 0 3 0 0 0 3500400041853S-705 (I12) wp09.1Plan View 019003800True Vertical Depth (950 usft/in)0 3000 6000 9000 12000Vertical Section at 332.35° (1500 usft/in)10-3/4" Surface Casing7" Intermediate Casing4-1/2" Production Liner1000200030004000500060007000 8000 9000 10000 11000 12000 13000 14000 Plan: 3S-705 (I12)/3S-705 (I12) wp09.1Start Build 1.50Start DLS 2.00 TFO 10.00Start 250.00 hold at 550.00 MDStart Build 2.50Start 107.91 hold at 1503.71 MDStart DLS 3.50 TFO 135.00Start DLS 3.00 TFO 60.00Start 50.00 hold at 2597.13 MDStart DLS 3.50 TFO 5.02Start 835.95 hold at 3210.88 MDStart DLS 3.75 TFO 87.04Start Build 2.00Start 20.00 hold at 6297.81 MDStart DLS 2.00 TFO 85.10Start 7155.12 hold at 6920.65 MDTD at 14075.78Section View Project: Kuparuk River Unit_2Site: Kuparuk 3S PadWell: Plan: 3S-705 (I12)Wellbore: 3S-705Design: 3S-705 (I12) wp09.1 ! 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" B * 8/ -2 + & AC 1/ C < & 4++ ,! - 4++ , + ,! - %& ' & ( )*&) + , 1 / -2 ? ; + ? 3 From:Johnson, Cameron To:Davies, Stephen F (OGC) Cc:Hobbs, Greg S; Dewhurst, Andrew D (OGC); Loepp, Victoria T (OGC) Subject:RE: [EXTERNAL]RE: KRU 3S-705 Permit Application Date:Monday, June 2, 2025 1:47:23 PM Attachments:3S-703_IBC-CBL-VDL_7in_31-May-2025_Cement_Evaluation_Report.pdf 3S-703_IBC-CBL-VDL_7in_31-May-2025_Cement_Evaluation_Processed Log.pdf FW KRU 3S-703 Production Cement Log.msg FW KRU 3S-703 Production Cement Log.msg 3S-703 Production Treatment Report.pdf FW KRU 3S-703 Surface Casing Cement Test FIT Report.msg Steve, Please find the 3S-703 cement evaluation log, SLB interpretation of the cement log, ConocoPhillips cementing SME’s cement interpretation, and AOGCC correspondence on the surface and production jobs attached to this email. The FE .LAS files are too large to email. They will be uploaded in sharepoint shortly. The Coyote formation in the 3S-17 well was abandoned as designed per abandonment regulations as designed, placing cement 50’ into the Coyote and 100’ above. The mechanical limitations of the perf/wash/cement allow a maximum plug length of 150’. The intent of this abandonment was to prevent upward pressure transmission from the Coyote into the formations above. The fracture stimulation of this wellbore is designed to be a longitudinal frac along the wellbore. The proximity to the 3S-17/17A wellbores will be considered when designing the completion and placement of frac sleeves to avoid un-intentional communication. For these reasons, ConocoPhillips is not concerned with the containment of Frac/Injection fluids from the 3S-705 well in relation to the abandoned 3S-17 well. Thank you, Cam Johnson | Drilling Engineer | ConocoPhillips Alaska O: 907.223.6277 | M: 907.720.3162 | ANO-938, 700 G Street, Anchorage, AK From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, June 2, 2025 12:13 PM To: Johnson, Cameron <Cameron.Johnson2@conocophillips.com> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL]RE: KRU 3S-705 Permit Application Hello Cam, I’m the geologist reviewing the Permit to Drill application for KRU 3S-705. Has CPAI’s proposed KRU 3S-703 well been drilled? (The estimated spud date was May 12, 2025.) If so, please provide field-quality log data in .las format, cement evaluation logs in .pdf format, all available cementing reports, and CPAI’s evaluation of the zonal isolation of the Coyote and associated confining intervals in that well. The Coyote within the KRU 3S-17 and 3S-17A wells is located very near to 3S-705. According to my notes, in 3S-17 and 3S-17A the perforations for the perf, wash, and cementing operations were shot and cemented from 5707’ to 5857’ MD and the top of the Coyote is about 5807’ MD. 3S-17 was plugged back and the KOP for 3S-17A was at 6160' MD, within lower portion of Coyote interval. Does CPAI have any concerns that the lower portion of the Coyote may be uncemented in those wellbores, and that they may pose a risk to containment of the frac fluids for nearby frac stages in 3S-705? If not, why not? If so, what mitigations measures will be implemented? Thank You and Be Well, Steve Davies AOGCC From: Johnson, Cameron <Cameron.Johnson2@conocophillips.com> Sent: Thursday, May 29, 2025 3:00 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: [EXTERNAL]RE: KRU 3S-705 Permit Application Thank you for the quick response. Please let me know if you have any questions. Cam Johnson | Drilling Engineer | ConocoPhillips Alaska O: 907.223.6277 | M: 907.720.3162 | ANO-938, 700 G Street, Anchorage, AK From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Thursday, May 29, 2025 1:44 PM To: Johnson, Cameron <Cameron.Johnson2@conocophillips.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: [EXTERNAL]RE: KRU 3S-705 Permit Application 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. It’s in process now. We will try. Victoria Loepp Senior Petroleum Engineer 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. Alaska Oil & Gas Conservation Commission Work: (907)793-1247 From: Johnson, Cameron <Cameron.Johnson2@conocophillips.com> Sent: Thursday, May 29, 2025 1:15 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: KRU 3S-705 Permit Application Good afternoon, Doyon 25 is expected to release from the 3S-703 well on Monday, June 2nd and will completing a short move to the 3S-705 conductor. The API and PTD numbers will be required to get the drilling program, associated service vendor programs, and well signs approved and ordered. Would the AOGCC be able to return the PTD tomorrow, Friday May 30th? This would allow time over the weekend to get the final documentation in order for spud of the 3S-705 well early next week. Thank you, Cam Johnson | Drilling Engineer | ConocoPhillips Alaska O: 907.223.6277 | M: 907.720.3162 | ANO-938, 700 G Street, Anchorage, AK From: Johnson, Cameron Sent: Monday, May 19, 2025 10:06 AM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: KRU 3S-705 Permit Application Good morning, Victoria, Operations on Doyon 25 (3S-721 and 3S-703) have been proceeding very efficiently. I wanted to give you an updated spud date for the 3S-705 well with Doyon 25. As of today, the estimated rig release from 3S-703 is June 2nd with an anticipated spud on 3S-705 on June 4th. Please do not hesitate to reach out to me if you have any questions on the 3S-705 permit. Thank you, Cam Johnson | Drilling Engineer | ConocoPhillips Alaska O: 907.223.6277 | M: 907.720.3162 | ANO-938, 700 G Street, Anchorage, AK From: Johnson, Cameron Sent: Monday, May 5, 2025 9:32 AM To: AOGCC Permitting (CED sponsored <aogcc.permitting@alaska.gov> Cc: Loepp, Victoria T (DOA <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC <steve.davies@alaska.gov>; Guhl, Meredith D (OGC <meredith.guhl@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Taylor, Jenna <Jenna.L.Taylor@conocophillips.com>; Earhart, Will C <William.C.Earhart@conocophillips.com> Subject: KRU 3S-705 Permit Application Good morning, Attached is the drilling permit package for the KRU 3S-705 well. The current anticipated spud date is June 17, 2025. Please let me know if you have any questions regarding the permit application. Thanks, Cam Johnson | Drilling Engineer | ConocoPhillips Alaska O: 907.223.6277 | M: 907.720.3162 | ANO-938, 700 G Street, Anchorage, AK CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Johnson, Cameron To:Loepp, Victoria T (OGC); Davies, Stephen F (OGC) Cc:Hobbs, Greg S Subject:RE: [EXTERNAL]RE: KRU 3S-705 Permit Application Date:Thursday, May 29, 2025 3:00:34 PM Thank you for the quick response. Please let me know if you have any questions. Cam Johnson | Drilling Engineer | ConocoPhillips Alaska O: 907.223.6277 | M: 907.720.3162 | ANO-938, 700 G Street, Anchorage, AK From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Thursday, May 29, 2025 1:44 PM To: Johnson, Cameron <Cameron.Johnson2@conocophillips.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: [EXTERNAL]RE: KRU 3S-705 Permit Application 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. It’s in process now. We will try. Victoria Loepp Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Work: (907)793-1247 From: Johnson, Cameron <Cameron.Johnson2@conocophillips.com> Sent: Thursday, May 29, 2025 1:15 PM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: KRU 3S-705 Permit Application Good afternoon, Doyon 25 is expected to release from the 3S-703 well on Monday, June 2nd and will completing a short move to the 3S-705 conductor. The API and PTD numbers will be required to get the drilling program, associated service vendor programs, and well signs approved and ordered. Would the AOGCC be able to return the PTD tomorrow, Friday May 30th? This would allow time over the weekend to get the final documentation in order for spud of the 3S-705 well early next week. Thank you, Cam Johnson | Drilling Engineer | ConocoPhillips Alaska O: 907.223.6277 | M: 907.720.3162 | ANO-938, 700 G Street, Anchorage, AK From: Johnson, Cameron Sent: Monday, May 19, 2025 10:06 AM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com> Subject: RE: KRU 3S-705 Permit Application Good morning, Victoria, Operations on Doyon 25 (3S-721 and 3S-703) have been proceeding very efficiently. I wanted to give you an updated spud date for the 3S-705 well with Doyon 25. As of today, the estimated rig release from 3S-703 is June 2nd with an anticipated spud on 3S-705 on June 4th. Please do not hesitate to reach out to me if you have any questions on the 3S-705 permit. Thank you, Cam Johnson | Drilling Engineer | ConocoPhillips Alaska O: 907.223.6277 | M: 907.720.3162 | ANO-938, 700 G Street, Anchorage, AK From: Johnson, Cameron Sent: Monday, May 5, 2025 9:32 AM To: AOGCC Permitting (CED sponsored <aogcc.permitting@alaska.gov> Cc: Loepp, Victoria T (DOA <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC <steve.davies@alaska.gov>; Guhl, Meredith D (OGC <meredith.guhl@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Taylor, Jenna <Jenna.L.Taylor@conocophillips.com>; Earhart, Will C <William.C.Earhart@conocophillips.com> Subject: KRU 3S-705 Permit Application Good morning, Attached is the drilling permit package for the KRU 3S-705 well. The current anticipated spud date is June 17, 2025. Please let me know if you have any questions regarding the permit application. Thanks, Cam Johnson | Drilling Engineer | ConocoPhillips Alaska O: 907.223.6277 | M: 907.720.3162 | ANO-938, 700 G Street, Anchorage, AK CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Johnson, Cameron To:AOGCC Permitting (CED sponsored) Cc:Loepp, Victoria T (OGC); Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Hobbs, Greg S; Taylor, Jenna; Earhart, Will C Subject:KRU 3S-705 Permit Application Date:Monday, May 5, 2025 9:32:50 AM Attachments:3S-705 AOGCC PTD_Combined.pdf 3S-705 (I12) wp091.txt 3S-705 (I12) wp09.1 MIA.txt Good morning, Attached is the drilling permit package for the KRU 3S-705 well. The current anticipated spud date is June 17, 2025. Please let me know if you have any questions regarding the permit application. Thanks, Cam Johnson | Drilling Engineer | ConocoPhillips Alaska O: 907.223.6277 | M: 907.720.3162 | ANO-938, 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. KUPARUK RIVER 225-047 KRU 3S-705 KUPARUK RIVER, COYOTE OIL WELL PERMIT CHECKLISTCompanyConocoPhillips Alaska, Inc.Well Name:KUPARUK RIV UNIT 3S-705Initial Class/TypeSER / PENDGeoArea890Unit11160On/Off ShoreOnProgramSERWell bore segAnnular DisposalPTD#:2250470Field & Pool:KUPARUK RIVER, COYOTE OIL - 490120NA1 Permit fee attachedYes Surf Loc & Top Prod Int lie in ADL0380107; Portion of Well Passes Thru ADL0380106; TD lies within ADL0025528.2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes KUPARUK RIVER, COYOTE OIL - 490120 - governed by CO 6185 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes AIO 4514 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sYes Yes, AOR wells intercepting Coyote and associated confining zones reviewed. Nearest wells (3S-17 and 3S-17A)15 All wells within 1/4 mile area of review identified (For service well only)No likely not cemented across lower portion of Coyote reservoir, but abandonment perf, wash, and cementing16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA isolated uppermost 50' of Coyote and 100' of overlying confining interval. This will prevent upward migration.17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 80'18 Conductor string providedYes SC set at 2701' MD19 Surface casing protects all known USDWsYes 155% excess20 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 pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes Max reservoir pressure is 1915 psig(8.8 ppg EMW);will drill w/ 9.5-10.0 ppg EMW28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP is 1496 psig; will initially test BOPs to 5000 psig and subsuquently to 3500 psig30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No H2S Measures Required: KRU 3S-718 measured 50 ppm H2S on 11/15/2024.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure is(8.7 to 8.8 ppg EMW. Operator's planned mud program36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/2/2025ApprVTLDate6/2/2025ApprSFDDate6/2/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate($8JLC 6/3/2025
