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Home My WebLink About225-101 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDBi-006 (50-103-20926-0000) Final Well data Submittal - Details on following pages. Received by:_____________________________ Date: _____________ Please sign and return one copy to: Santos ATTN: Shannon Koh 601 W 5th Ave., Anchorage, AK 99501 shannon.koh@santos.com DATE: 1/6/2026 From: Shannon Koh Santos 601 W 5th Ave. Anchorage, AK 99501 To: Gavin Glutas AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 TRANSMISSION TYPE: ܈External Request ܆Internal Request TRANSMISSION METHOD: ܆CD ܆ Thumb Drive ܆Email ܆SharePoint/Teams ܆Hardcopy ܈Other - FTP REASON FOR TRANSMITTAL: ܆Approved ܆Approved with Comments ܆For Approval ܈Information Only ܆For Your Review ܆For Your Use ܆To Be Returned ܆With Our Comments ܆Other COMMENTS: 225-101 T41238 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.01.07 09:12:57 -09'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDBi-006 Comparison View-1.pdf ؒ NDBi-006 Comparison View-2.pdf ؒ NDBi-006 Definitive Compass Survey Report - NAD27.pdf ؒ NDBi-006 Definitive Compass Survey Report - NAD83.pdf ؒ NDBi-006 Definitive Survey - NAD27.txt ؒ NDBi-006 Definitive Survey - NAD83.txt ؒ NDBi-006 Definitive Survey Report.xlsx ؒ NDBi-006 Plan View.pdf ؒ NDBi-006 Vertical Section.pdf ؒ ؤؐؐؐLog Digital Data and Plots جؐؐؐBaker ؒ جؐؐؐDigital Data ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_21149ft .las ؒ ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_BROOH_21144ft-767ft.las ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDBi-006_AP_R01_RM.las ؒ ؒ ؒ NDBi-006_AP_R02_RM.las ؒ ؒ ؒ NDBi-006_AP_R03_RM.las ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDBi-006_DMD_RM_21149ft.las ؒ ؒ NDBi-006_DMT_R01_RM.las ؒ ؒ NDBi-006_DMT_R02_RM.las ؒ ؒ NDBi-006_DMT_R03_RM.LAS ؒ ؒ ؒ جؐؐؐGeoscience Deliverables ؒ ؒ جؐؐؐImageTrak - Acoustic Image ؒ ؒ ؒ ؤؐؐؐFinal Processing and Interpretation ؒ ؒ ؒ Santos - NDBi-006_MEMORY_PROCESSED_IMAGE.dlis ؒ ؒ ؒ Santos NDBi-006 FINAL MEMORY ITK IMAGE_1_240.meta ؒ ؒ ؒ Santos NDBi-006 FINAL MEMORY ITK IMAGE_1_240.PDF ؒ ؒ ؒ Santos NDBi-006 FINAL MEMORY ITK IMAGE_1_240.tif ؒ ؒ ؒ Santos NDBi-006 FINAL MEMORY ITK IMAGE_1_48.meta ؒ ؒ ؒ Santos NDBi-006 FINAL MEMORY ITK IMAGE_1_48.PDF ؒ ؒ ؒ Santos NDBi-006 FINAL MEMORY ITK IMAGE_1_48.tif ؒ ؒ ؒ ؒ ؒ ؤؐؐؐSoundTrak Acoustic Data ؒ ؒ ؤؐؐؐTOC Logging LETTER OF TRANSMITTAL ؒ ؒ NDBi-006 SoundTrak TOC Report.pdf ؒ ؒ NDBi-006_LWD_SDTK_TOC_2600_11850.cgm ؒ ؒ NDBi-006_LWD_SDTK_TOC_2600_11850.PDF ؒ ؒ NDBi-006_LWD_SDTK_TOC_2600_5900_stage_3.dlis ؒ ؒ NDBi-006_LWD_SDTK_TOC_2600_5900_stage_3.las ؒ ؒ NDBi-006_LWD_SDTK_TOC_2600_5900_stage_3_dlis.txt ؒ ؒ NDBi-006_LWD_SDTK_TOC_9650_11850_stage_1_2.dlis ؒ ؒ NDBi-006_LWD_SDTK_TOC_9650_11850_stage_1_2.las ؒ ؒ NDBi-006_LWD_SDTK_TOC_9650_11850_stage_1_2_dlis.txt ؒ ؒ ؒ ؤؐؐؐGraphic Images ؒ جؐؐؐCGM ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_21149ft_2MD.cgm ؒ ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_21149ft_2TVD.cgm ؒ ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_21149ft_5MD.cgm ؒ ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_21149ft_5TVD.cgm ؒ ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_BROOH_21144ft-11833ft_5MD.cgm ؒ ؒ ؒ NDBi-006_LWD_GR_Res_RM_BROOH_11828ft-11515ft_5MD.cgm ؒ ؒ ؒ NDBi-006_LWD_GR_Res_RM_BROOH_2900ft-767ft_5MD.cgm ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDBi-006_AP_RM.cgm ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDBi-006_DMD_RM_21149ft.cgm ؒ ؒ NDBi-006_DMT_RM.cgm ؒ ؒ ؒ ؤؐؐؐPDF ؒ جؐؐؐFE ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_21149ft_2MD.pdf ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_21149ft_2TVD.pdf ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_21149ft_5MD.pdf ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_21149ft_5TVD.pdf ؒ ؒ NDBi-006_LWD_GR_Res_Den_Neu_Cal_RM_BROOH_21144ft-11833ft_5MD.pdf ؒ ؒ NDBi-006_LWD_GR_Res_RM_BROOH_11828ft-11515ft_5MD.pdf ؒ ؒ NDBi-006_LWD_GR_Res_RM_BROOH_2900ft-767ft_5MD.pdf ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDBi-006_AP_RM.pdf ؒ ؒ ؒ ؤؐؐؐVSS LETTER OF TRANSMITTAL ؒ NDBi-006_DMD_RM_21149ft.pdf ؒ NDBi-006_DMT_RM.pdf ؒ ؤؐؐؐHalliburton ؤؐؐؐTOC CASTM-CBLM_5625head.pdf NDBi-006_CAST-CBL_02DEC25_ProcessedLog.pdf NDBi-006_CAST-CBL_02DEC25_Report_9.625in.pdf TRACTOR_CBL_CAST_7in.pdf Welltec Toolstring - Santos NDBi-06 CASTM Conveyance.pdf 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: Well Clean Up 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: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 21,148' N/A Casing Collapse Conductor Surface 2,260 Intermediate 4,750 Tieback 4,750 Production 9,210 Liner 9,210 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email:scott.leahy@santos.com Contact Phone: 907-330-4595 Authorized Title: Completions Specialist 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 2,313' 4-1/2" 21,148'9,496' 4-1/2" 12.6ppf 20"x34" 13-3/8" 128' 9-5/8"9,106' 2,883' 6,870 5,020 128' 2,384' 128' 2,883' 11,824' 4,044' Size Proposed Pools: P110S TVD Burst 11,690 Pikka Nanushuk Oil Pool N/A MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 393016, 393015, 391455, 393011, 391454 225-101 601 W 5th Avenue, Suite 600, Anchorage, AK 99501 50-103-20926-00-00 Oil Search Alaska, LLC Pikka NDBi-006 AOGCC USE ONLY 11,590 Tubing Grade: Tubing MD (ft): See attached packer report 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 Scott Leahy 11,690' 4-1/2" 11,690' 4,014' 11,590 1/7/2026 4,093' See attached packer report Perforation Depth MD (ft): 2,718' Tieback 2,718' 6,870 4,093 21,132 4,093 Length m n P s 2 6 5 6 t t p N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov e foregoing is true and th 12/16/2025 325-761 By Grace Christianson at 11:05 am, Dec 16, 2025 10-404 DSR-12/19/25 Variance to 20 AAC 25.283(a)(6)(B) is approved, recognizing that some of the upper Nanushuk is not isolated with cement per 20 AAC 25.030, however the Nanushuk 3.2 is sufficiently isolated to contain the frac and water injected into that interval. An abbreviated variance request is attached to this sundry. CDW 12/18/2025 A.Dewhurst 23DEC25 1/7/2026 BJM 12/30/25JLC 12/30/2025 12/30/25 Page 1 of 1 Packer Set Depths - NDBi-006 Wellbore Name Item Des Btm (ftKB) Btm (TVD) (ftKB) Original Hole ZXtreme Liner Top Packer W/HRD-E Profile 11,677.3 4,011.5 Original Hole HES Zoneguard OH Packer #25 11,945.6 4,064.0 Original Hole HES Zoneguard OH Packer #24 12,013.0 4,073.0 Original Hole HES Zoneguard OH Packer #23 12,556.1 4,084.3 Original Hole HES Zoneguard OH Packer #22 13,016.5 4,084.9 Original Hole HES Zoneguard OH Packer #21 13,125.1 4,085.2 Original Hole HES Zoneguard OH Packer #20 13,682.3 4,086.7 Original Hole HES Zoneguard OH Packer #19 13,832.5 4,087.2 Original Hole HES Zoneguard OH Packer #18 14,415.8 4,088.6 Original Hole HES Zoneguard OH Packer #17 14,524.1 4,088.8 Original Hole HES Zoneguard OH Packer #16 14,940.3 4,089.9 Original Hole HES Zoneguard OH Packer #15 15,131.3 4,089.9 Original Hole HES Zoneguard OH Packer #14 15,634.6 4,092.1 Original Hole HES Zoneguard OH Packer #13 16,094.4 4,094.5 Original Hole HES Zoneguard OH Packer #12 16,633.4 4,096.8 Original Hole HES Zoneguard OH Packer #11 17,133.0 4,098.8 Original Hole HES Zoneguard OH Packer #10 17,634.3 4,100.1 Original Hole HES Zoneguard OH Packer #9 18,131.8 4,100.3 Original Hole HES Zoneguard OH Packer #8 18,632.1 4,101.3 Original Hole HES Zoneguard OH Packer #7 19,176.1 4,102.6 Original Hole HES Zoneguard OH Packer #6 19,636.9 4,103.7 Original Hole HES Zoneguard OH Packer #5 20,136.6 4,100.8 Original Hole HES Zoneguard OH Packer #4 20,245.9 4,097.2 Original Hole HES Zoneguard OH Packer #3 20,682.6 4,094.2 Original Hole HES Zoneguard OH Packer #2 20,789.6 4,093.2 Original Hole HES Zoneguard OH Packer #1 21,045.1 4,092.7 Page 1 of 21 NDBi-006 Sundry Application Requirements 1. Affidavit of Notice Attachment A 2. Plot showing well location, as well as ½ mile radius around well with all well penetrations, fractures, and faults within that radius Attachment B 3. Identification of freshwater aquifers within ½ mile radius There are no known underground sources of drinking water within a one-half mile radius of the current proposed well bore trajectory for NBDi-006. At the NDBi-006 location, the Permafrost interval extends down to approximately 1000-1400 ft and therefore, no shallow aquifers are located at the NDBi-006 location. Wells within the Pikka unit (see table below) have measured water salinity values >10,000 ppm and are not considered freshwater. 4. Plan for freshwater sampling There are no known freshwater wells proximal to the proposed operations, therefore no water sampling planned. 5. Detailed casing and cementing information Attachment C 6. Assessment of casing and cementing operations Attachment C 7. Casing and tubing pressure test information Attachment D 8. Pressure ratings for wellbore, wellhead, BOPE and treating head Attachments D and I 9. Lithological and geological descriptions of each zone Attachment E and below Prince Creek Formation Depth/Thickness: Surface to 977 feet (ft) total vertical depth subsea (TVDSS)/ 977 ft thick Lithological Description: The Prince Creek Formation (Fm) in the Pikka Unit area consists predominantly of massive, unconsolidated sand and gravel sequence with minor clays that were deposited in a non-marine, fluvial setting. Schrader Bluff Formation (Upper, Middle, Lower) Depth/Thickness: 977 to 2,376 ft TVDSS/1,399 ft thick Lithological Description: The Schrader Bluff Fm in the Pikka Unit area was deposited in a shallow marine to shelf setting and dominantly consists of light grey claystone in the Upper Schrader Bluff (including shell fragments, lignite, and cherts), grading to a dark mudstone in the Middle Schrader and grading to a massive blocky shale in the Lower Schrader Bluff. Interbedded volcanic ash was observed and increasing from the Lower Schrader Bluff Fm. There are some thin (<15 ft), poor-quality (high clay content, low permeability) sands present in the Upper Schrader Bluff Fm within the Pikka Unit. Tuluvak Formation Depth/Thickness: 2,376 to 3,193 ft TVDSS/ 817 ft thick Hydrocarbon Zone: 2,754 to 3,193 ft TVDSS Lithological Description: The Tuluvak Fm in the Pikka Unit area consists predominantly of claystone, siltstone, and thinly interbedded sandstones deposited in a prograding, shallow marine setting, grading with depth to the deep marine shales of the Seabee Fm. Sandstones. Upper Confining Zone Name Seabee Formation Depth/Thickness: 3,193 to 3,669 ft TVDSS/ 476 ft thick Lithological Description: The Seabee Fm in the Pikka Unit area consists predominantly of claystone, shale, and volcanic tuff deposited in a deep marine setting. The base of the Seabee Fm grades into a condensed organic shale and provides an excellent seal and confining interval above the Nanushuk Fm reservoirs and also acts as a thick second overlying confining unit. Nanushuk Formation Depth/Thickness: 3,669 to 4,623 ft TVDSS/ 954 ft thick Lithological Description: The Nanushuk Fm is the primary oil production zone for the Pikka Development. This formation is a thick accumulation of fluvial, deltaic, and shallow marine deposits and is the up-dip, shelf topset equivalent of the deeper water, slope-to-basin floor Torok Fm. The Nanushuk-Torok clinoform sets sequentially prograde from west to east. The Nanushuk Fm is often highly laminated and comprised of fine-grained sand, silt, and shale. It can contain lithic-clasts from various sedimentary and metamorphic sources. Distributary channel mouth bar deposits and shoreface sands comprise major sand packages in the Nanushuk Fm. Lower Confining Zone Name: Torok Formation Depth/Thickness: 4,623 to 5,522 ft TVDSS/899 ft thick Lithological Description: The Lower Torok sands are overlain by the Upper Torok Fm, which is up to 1,200 feet thick in the Pikka Unit. The Upper Torok is composed primarily of shale (Hue Shale) with some thin interbedded siltstones. Within the Upper Torok Fm, several condensed, impermeable shale layers called maximum flooding surfaces (MFS) are present. These are regionally extensive and provide excellent confining intervals. 10.Estimated fracture pressure for each zone listed below: Held IA Pressure (psi) IA PRV (psi) GORV (psi) Pump Trip Pressure (psi) Surface Line Pressure Test (psi) MAWP (psi) Stages 1-15 3,800 4,100 7,000 6,600 9,200 8,800 Note: GORV and Pump trips to be set to 8,700 psi to open Toe Sleeve. GORV may be increased to 8,000 psi and pump trips to 7,600 psi should treating pressures be higher than expected. Fracture gradient values for each stage are listed in detail within Attachment K. In general, the fracture gradient values for the confining zones and pay zone are listed below: Upper confining: Shale gradient 0.71 psi/ft Fracturing: Sand gradient- 0.61 psi/ft Lower confining: Shale gradient- 0.69 psi/ft Stage MD Perf Depth (ft) TVD Perf Depth (ft) Max Frac Height (ft) Frac ½ Length (ft) Max Rate (bpm) Est. Max Pressure (psi) Max Prop Conc. (PPA) 1 21,014 4,093 192 368 30 4,372 8 2 19,862 4,104 221 259 25 3,458 8 3 19,360 4,103 221 260 25 3,376 8 4 18,857 4,102 225 286 30 3,966 8 5 18,358 4,101 233 318 40 5,498 8 6 17,858 4,100 234 325 40 5,385 8 7 17,358 4,100 260 283 40 5,262 8 8 16,858 4,098 233 338 40 5,545 10 9 16,360 4,096 224 271 40 5,469 10 10 15,859 4,093 233 329 40 5,256 10 11 15,357 4,091 267 307 40 5,105 10 12 14,749 4,089 236 368 40 4,461 8 13 14,098 4,088 244 334 40 4,637 10 14 12,782 4,085 242 342 40 3,903 8 15 12,238 4,084 244 356 40 4,087 10 5,545 11.Mechanical condition of wells transecting the confining zones NDB-010 is within 1/2-mile radius of NDBi-006. Please see Attachment B as reference. 12.Suspected fault or fracture that may transect the confining zones: There are 5 known faults within the ½ mile radius of NDBi-006. Fault locations along the lateral are noted in Attachment J. Please See Attachment B. Note: Fractures are estimated to propagate along wellbore longitudinally at ~330 o. 13.Detailed proposed fracturing program Attachments F & K 14.Well Clean Up procedure Attachment G Section (b) Casing Pressure Test We will not be treating through production or intermediate casing strings. Section (c) Fracture String Pressure Test Attachment H Section (d) Pressure Relieve Valve Attachment I Proposed Wellbore Schematic Attachment J Attachment A Oil Search (Alaska), LLC a subsidiary of Santos Limited 601 W 5th Avenue Anchorage, Alaska 99501 (T) +1 907 375 4642 santos.com 1/2 , 2025 Owners, Landowners, Surface Owners and Operators See Distribution List Colville River Area North Slope Basin, Alaska Re: Notice of Operations under 20 AAC 25.283 of Oil Search (Alaska), LLCs Sundry Application for a Fracture Stimulation for the Proposed NDB -0 Well Dear Owner, Landowner, Surface Owner and/or Operator, Oil Search (Alaska), LLC (OSA) is applying for a Sundry Application under 20 AAC 25.283 to perform a fracture stimulation of the proposed NDB -0 well. This Notice is being sent by certified mail to meet the notification requirements under 20 AAC 25.283(a)(1)(A) and 20 AAC 25.283(a)(1)(B). The complete application is available for review upon request. If you wish to review the application, please contact Tim Jones, Land Manager, at the following: Tim Jones Land Manager Oil Search (Alaska), LLC 601 W 5th Ave Anchorage, AK 99501 Direct: 907-375-4624 tim.jones3@santos.com OSA, through a search of the public record, has identified you as an Owner, Landowner, Surface Owner or Operator (as defined in AOGCC regulations) within ½ mile of the proposed NDB -0 well trajectory and fracture stimulation. Please contact Tim Jones should you require additional information. Sincerely, Jacob Owens Commercial Analyst Distribution List: Alaska Division of Oil and Gas Arctic Slope Regional Corp. Kuukpik Corp. Oil Search (Alaska), LLC Repsol E&P USA LLC Sincerely, Jacob Owens 2/2 Contact Information: State of Alaska CERTIFIED MAIL Department of Natural Resources Alaska Division of Oil and Gas 550 W 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Arctic Slope Regional Corp. CERTIFIED MAIL Attn: David Knutson 3900 C Street, Suite 801 Anchorage, AK 99503-5963 Kuukpik Corp CERTIFIED MAIL 582 E. 36th Avenue Anchorage, AK 99503 Oil Search (Alaska), LLC CERTIFIED MAIL 601 W 5th Ave Anchorage, AK 99501 Repsol E&P USA LLC CERTIFIED MAIL 2455 Technology Forest Blvd. The Woodlands, TX 77381 ADL 392963 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 392984 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 393021 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 19.22% DNR - 80.78% ADL 393019 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.1% DNR - 66.9% ADL 393018 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 29.67% DNR - 70.33% ADL 393020 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 26.59% DNR - 73.41% ADL 393015 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 31.69% DNR - 68.31% ADL 393017 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSO SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 393016 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.17% DNR - 66.83% ADL 393006 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 28.11% DNR - 71.89% ADL 393007 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 34.35% DNR - 65.65% ADL 393008 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSO SUBS.OWNERS: ASRC - 28.29% DNR - 71.7 ADL 391322 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSO SUBS.OWNERS: ASRC - 28.25% DNR - 71.7 ADL 391445 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.98% DNR - 58.02% ADL 391453 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSO SUBS.OWNERS: ASRC - 22.43% DNR - 77.5 ADL 391454 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 36.61% DNR - 63.39% ADL 391455 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 46.4% DNR - 53.6% ADL 393009 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 40.59% DNR - 59.41% ADL 393011 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 25.71% DNR - 74.29% ADL 393010 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 38.54% DNR - 61.46% OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD 0.5-MILE BUFFER NDBI-006 BOTTOM HOLE NDBI-006 SURFACE LOCATION PRODUCTION INTERVAL SANTOS LEASES NDBI-006 SECTIONS DATE: 12/3/2025. By: JB 0 1,000 2,000 Feet Project: AP-DRL-GEN_assorted Layout: AP-DRL-PE-M_NDBi006_well_ownership Map Frame: AP-DRL-PE-M_NDBi-006_well_ownership GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 200 400 Meters PIKKA DEVELOPMENT NDBi-006 WELL AREA Attachment B Fault NameMDEst. Throw in NT3 ReservoirConfidenceVisible on seismicDip Direction CommentsSM_NDB_0181160299 ftHighYes 110Fault location picked based on missing section on LWD logs but no obvious drilling parameter impact. Fault tip terminates within upper Seabee. Fault intersects the wellbore in the intermediate hole section above the reservoir in the NT4 or upper NT3. Fault is adequately isolated in intermediate hole section and is not considered a risk for frac. or containment. Fault is 580 away from Stage 15Merged_SM_NDB_013_019_025 147900-30 ftLowYes265Low confidence fault. Image log detected dip change but no clear fault plane . Some displacement is visible in seismic around NT3; no displacement in upper Nanushuk. Displacement below NT3 uncertain due to low reflectivity. SM_NDB_0212054750-80 ftHighYes 95Seismic interpretation indicates termination within Middle Schrader Bluff Fm.SM_NDB_025Does not intersect wellbore < 30 ftHighYes 250Terminates within Nanushuk and is contained within pool. Not considered a risk for containment.SM_NDB_005Does not intersect wellbore70 ftHighYes 115Terminates in Nanushuk and is within pool. Not considered a risk for containment.NDBi-006 Fault SummarySM_NDB_018SM_NDB_999SM_NDB_023SM_NDB_025SM_NDB_021NT3 TopReservoirNDB PadMap showing the location and orientation of geologic data for each prognosed fault within one quarter and one-half mile radius of wellbore trajectory. Faults have been named and mapped from seismic.SM_NDB_005Merged_SM_NDB_013_019_025 WELL NAME STATUS Casing SizeTop of Oil Pool Confining Layer (MD)Top of Oil Pool Confining Layer (TVDSS)Top of Cement (MD)Top of Cement (TVDSS)Top of Cement Determined ByReservoir Status Zonal IsolationCement Operations SummaryMechanical IntegrityNDB-010 ACTIVE 9-5/8" 47ppf 8,188' (Nanushuk) 3,717' (Nanushuk) 7,170'' 3,462.4' log open hole liner for productionTOC 8,188'MD' & packer @ 9,460'9-5/8 1st Stage:-The Baker TOC log indicates there is good cement coverage across and above the Upper Nanushuk formations. Summary as follows:oTop of Cement is 7,170 MD / 3,532 TVD. 1,018 MD / 255 TVD above the Top NanushukoTop of Nanushuk is 8,188 MD / 3,787 TVD9-5/8 2nd Stage:-For the 2nd stage of the cement job, based on job execution results, cement isolation was achieved across the hydrocarbon zone within the upper Tuluvak formation.8/16/2025, 9-5/8" casing pressure tested to 4,300 psi for 30 min. Attachment C 9-5/8 47# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensil e (klbs) ID (in) Drift ID (in) Connecti on OD (in) Make-up Torque (ft-lbs) Make-Up Loss (in) 6870 4750 1086 8.681 8.525 10.625 15800 4.050 Intermediate Liner Cement Job Execution Cement job pumped following the Halliburton Cementing Program Well Design 9-5/8 Intermediate 1 Liner 9-5/8 Liner Top at 2,720 MD 13-3/8 shoe at 2,883 MD 9-5/8 Archer 1st Cflex Mechanical Stage tool: 5,305 MD 9-5/8 Archer 2nd Cflex Mechanical Stage tool: 10,349 MD (Note 2 nd CFLEX was run to give best possible chance for cement isolation given the losses associated with fault at 11,600) 9-5/8 Shoe at 11,828 MD Geology Top of Tuluvak TS 790 formation at 5,253 MD. Top of the Nanushuk picked at 10,330 MD. Top significant hydrocarbon in the Nanushuk was is in the NT8 based on relevant offsets Cement Job Planning/Execution Below and noted in attached cementing reports on subsequent pages for a summary of the work performed. 9-5/8 Intermediate Liner: 1st Stage 1st stage of the cement job planned with 15.3 ppg tail slurry at 30% excess, targeting TOC 10,950 MD (~26 MD above NT6). Due to losses encountered with a fault crossing at ~11,600 MD, the goal of this job was to attempt to cover the loss zone in preparation for the 2nd stage job. During execution of the 1st stage cement, nearly full losses were encountered throughout the job. An estimated 70 bbls (of 70 bbls cement pumped) was lost after cement exited the shoe. However, some lift pressure was observed, indicating the cement did move up the annulus toward the loss zone. Good/hard cement was encountered in the shoe track and rathole. After drilling out the 9- 5/8 shoe a LOT was conducted to 13.63 ppg. 2nd Stage 2nd Stage of cement job planned with CFLEX at 10,349 MD at the Top Nanushuk formation (~19 MD below Top Nan). Also planned with a full 15.3 ppg tail slurry at 30% excess, targeting TOC 200 TVD above the Top Nanushuk (~9335 MD), for a job volume of ~74 bbls. After opening the lower CFLEX, severe losses were still encountered, so the decision was made to pump all extra cement on location (total of 172 bbls 15.3ppg tail). During execution of the 2nd stage cement, minimal returns were noted, but some lift pressure was observed. An estimated 162 bbls (of 172 bbls cement pumped) was lost after cement exited the lower CFLEX tool. 3rd Stage 3rd Stage of cement job planned with CFLEX ~52 below the TS790. Also planned with a full 15.3 ppg tail slurry at 100% excess, targeting TOC at the 9- 5/8 liner top. During execution of the 3rd stage cement, no losses were encountered during mud conditioning or pumping cement (288 bbls 15.3ppg tail). While displacing cement with OBM, complete losses were encountered after pumping 39 bbls of the 111bbls displacement. Lift pressure was observed prior to losing full returns. After the CFLEX was closed and the LTP set, we circulated off the top of the liner and dumped ~160 bbls of spacer with trace cement and 452 bbls of contaminated interface. An estimated 72 bbls (of 288 bbls cement pumped) was lost after cement exited the upper CFLEX tool. Observations 9-5/8 Intermediate Liner: For the 1st and 2nd stage of the cement job, Baker TOC log indicates no cement from top Nanushuk (10,330 MD) to 11,225 MD. 11,225 11450 MD contained intervals of partial bond, and Top of good cement was at 11,490 MD. Cement isolation was achieved across the 9-5/8 shoe. The upper Nanushuk formations across the hydrocarbon-bearing formations (NT4 through NT8) have not been fully covered by cement based on the measured TOC at 11,490 MD. For the 3rd stage of the cement job, based on Baker TOC log, cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation with many intervals of partial cement bond. Intervals of partial cement bond are above, across, and below the Tuluvak Hydrocarbon bearing formation. As there was insufficient cement coverage across the upper Nanushuk Oil Pool, a variance was submitted by Rob Williams to Bryan McLellan on 12/06/25. As there was insufficient cement coverage across the upper Nanushuk Oil Pool, a variance was submitted by Rob Williams to Bryan McLellan on 12/06/25. Recommend approval of variance request as dated 12/06/2025. Frac should be confined to zones by 4.5" liner and packers, and 9-5/8" liner shoe as evidenced by TOC logging, drill out, and shoe test. CDW 12/18/2025. Page 1/1 Well Name: NDBi-006 Report Printed: 12/15/2025www.peloton.com Cement API/UWI 50103209260000 Surface Legal Location Field Name Pikka PTD # 225-101 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.83 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.00 KB-Casing Flange Distance (ft) Spud Date 11/7/2025 21:30 Rig Release Date 12/7/2025 04:00 Surface Casing Cement Surface Casing Cement, Casing, 11/11/2025 00:00 Type Casing Cementing Start Date 11/11/2025 Cementing End Date 11/11/2025 Wellbore Original Hole String Surface Casing, 2,883.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results Good lift pressure observed. 189 bbls of cement returns to surface. 108 bbls losses after cement exited the shoe. Comment Cement 13-3/8 surface casing as follows: Hold PJSM with rig & Halliburton crews. -Fill lines with 5 water and pressure test to 2500 psi for 5 minutes - Good test -Drop 1st bottom plug -Pump 80 bbls of 10.5 ppg Tuned Spacer at 3.0 bpm, 195psi. -Release 2nd bottom plug -Pump 440 bbls of 11.0 ppg ArcticCem lead cement at 5 bpm, excess volume 200% (975 sacks, yield 2.535 cu.ft/sk) - Pump 69 bbls of 15.3 ppg Type I/II tail at 5 bpm, excess volume 50% (312 sacks, yield 1.24 cu.ft/sk) -Drop top plug and followed by 20 bbls wash water. -Perform displacement with rig pumps and 9.4 ppg mud - At ~110 bbls into displacement, experienced full packoff at the hanger flutes. Decision to pull hanger up ~6-12". Regained circulation, but unable to land hanger back on the landing ring. - 424 bbls displaced at 1-6 bpm: ICP 475 psi 11% return flow, FCP 700 psi. Bump plug on calculated displacement and pressure up to 1,200 psi. Bleed off and check floats, floats held. - 189 bbls cement to surface. -Total losses from cement exit shoe to cement in place: 108 bbls - CIP at 06:18 hrs. 1, 0.0-2,900.0ftKB Top Depth (ftKB) 0.0 Bottom Depth (ftKB) 2,900.0 Full Return? No Vol Cement Ret (bbl) 189.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 2 Final Pump Pressure (psi) 700.0 Plug Bump Pressure (psi) 1,200.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Spacer Fluid Type Spacer Fluid Description Tuned Spacer (Add 8lb RED DYE to first 20 bbl) Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) 2,900.0 Percent Excess Pumped (%) Yield (ft³/sack) 1.82 Mix H20 Ratio (gal/sack) 12.17 Free Water (%) Density (lb/gal) 10.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Lead Fluid Type Lead Fluid Description ArcticCem Lead Amount (sacks) 975 Class Volume Pumped (bbl) 440.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) 2,900.0 Percent Excess Pumped (%) 200.0 Yield (ft³/sack) 2.54 Mix H20 Ratio (gal/sack) 12.21 Free Water (%) Density (lb/gal) 11.00 Plastic Viscosity (cP) 15.8 Thickening Time (hr) 22.50 1st Compressive Strength (psi) 500.0 Cement Stage Fluid Additives Add Type Conc Tail Fluid Type Tail Fluid Description 15.3ppg Tail Amount (sacks) 312 Class Volume Pumped (bbl) 69.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) 2,900.0 Percent Excess Pumped (%) 50.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.59 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) 57.8 Thickening Time (hr) 10.80 1st Compressive Strength (psi) 500.0 Cement Stage Fluid Additives Add Type Conc Page 1/1 Well Name: NDBi-006 Report Printed: 12/15/2025www.peloton.com Cement API/UWI 50103209260000 Surface Legal Location Field Name Pikka PTD # 225-101 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.83 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.00 KB-Casing Flange Distance (ft) Spud Date 11/7/2025 21:30 Rig Release Date 12/7/2025 04:00 Intermediate Casing Cement Stage 1 Intermediate Casing Cement Stage 1, Casing, 11/18/2025 18:30 Type Casing Cementing Start Date 11/18/2025 Cementing End Date 11/19/2025 Wellbore Original Hole String Intermediate Liner, 11,824.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Bond Log Cement Evaluation Results Logged with Halliburton CAST-M. Logged 1st and 2nd stage cement jobs from 11,798' MD to 9,450' MD. Top of good cement at 11,458' MD with top of fair cement at 11,183' MD. Intermittent areas of poor cement and free pipe from 11.183' MD to 9,450' MD. See Halliburton report for more details. Comment Cement 1st stage 9-5/8" Intermediate liner. - Pump 5 bbls water & pressure test cement lines to 500 psi low 5,000 psi High 5 minutes - Pump 80 bbl 12.5 ppg Tuned Spacer with red dye, Surfactant B and Musol A - (65 gallons each) downhole at 3 bpm with 350 psi, - Release bottom pump down dart, chase with 70 bbls of 15.3 ppg Versacem tail cement type I/II at 3 bpm, 200 psi. - Open hole excess volume 30% - Release top pump down dart - Flush lines with 20 bbl. water to cuttings box - Perform displacement with rig pumps and 11.5 ppg MOBM as follows: - Begin pumping 708 bbls 11.5 ppg OBM at 3 bpm, ICP 316 psi, FCP 422 psi. No measurable returns. - 70 bbls lost after cement exited the shoe. (Bottom pump down dart latch up confirmed at 1,386 psi.) - Pressured up 500 psi over FCP (943 psi) and held 5 min, bled off, checked floats. Floats held. - Total displacement volume 708 bbls (measured by strokes at 96% pump efficiency). CIP @ 00:10hrs. - MOBM losses during cement job 864 bbls 1, 11,183.0-11,824.0ftKB Top Depth (ftKB) 11,183.0 Bottom Depth (ftKB) 11,824.0 Full Return? No Vol Cement Ret (bbl) 0.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 400.0 Plug Bump Pressure (psi) 510.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Tuned Spacer Fluid Type Tuned Spacer Fluid Description Tuned Spacer 4# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Versacem Tail Fluid Type Versacem Tail Fluid Description Versacem Tail Type I/II Amount (sacks) 317 Class I/II Volume Pumped (bbl) 70.0 Estimated Top (ftKB) 11,183.0 Estimated Bottom Depth (ftKB) 11,824.0 Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 93.0 Thickening Time (hr) 8.50 1st Compressive Strength (psi) 1,000.0 Cement Stage Fluid Additives Add Type Conc Page 1/1 Well Name: NDBi-006 Report Printed: 12/15/2025www.peloton.com Cement API/UWI 50103209260000 Surface Legal Location Field Name Pikka PTD # 225-101 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.83 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.00 KB-Casing Flange Distance (ft) Spud Date 11/7/2025 21:30 Rig Release Date 12/7/2025 04:00 Intermediate Casing Cement Stage 2 Intermediate Casing Cement Stage 2, Casing, 11/19/2025 18:00 Type Casing Cementing Start Date 11/19/2025 Cementing End Date 11/19/2025 Wellbore Original Hole String Intermediate Liner, 11,824.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Bond Log Cement Evaluation Results Logged with Halliburton CAST-M. Logged 1st and 2nd stage cement jobs from 11,798' MD to 9,450' MD. Top of good cement at 11,458' MD with top of fair cement at 11,183' MD. Intermittent areas of poor cement and free pipe from 11.183' MD to 9,450' MD. See Halliburton report for more details. Comment Conduct 2nd stage cementing of 9-5/8 47# Intermediate casing by open hole annulus through Archer cementing tool as follows: -Fill lines with water and test 1,000 psi low, 4,500 psi high. - Mix and pump 80 bbls of 12.5 ppg Mud Flush at 4 bpm, ICP 550 psi, FCP 425 psi, 55 bbls loss. - Mix and pump 172 bbls of 15.3 ppg Versacem Type I-II Tail cement at 4 bpm, ICP 767 psi, Final pump rate 4 bpm, FCP 485 psi. 94 bbls loss. - Total volume pumped 172 bbls cement - Excess Volume 30% - Displace with calculated volume of 233 bbls of 11.5 ppg OBM using rig pumps to Archer stage collar, 203 bbl loss. - Displace cement at 4 bpm, 109 psi ICP, 369 psi FCP with 70 bbls pumped and partial returns, slowed pump to 3 bpm, 369 psi ICP and 447 psi FCP. Maintained 3 bpm to calculated 2,527 calculated strokes, with minimal returns, 233 bbls total displacement to Archer tool. - 162 bbls lost after cement passed through C-Flex tool. - CIP @ 20:52 hrs. 2, 10,349.0-10,349.5ftKB Top Depth (ftKB) 10,349.0 Bottom Depth (ftKB) 10,349.5 Full Return? No Vol Cement Ret (bbl) 0.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 700.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Tuned Spacer Fluid Type Tuned Spacer Fluid Description Mud Flush Spacer Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Versacem Tail Fluid Type Versacem Tail Fluid Description Versacem Tail Type I/II Amount (sacks) 780 Class Type I/II Volume Pumped (bbl) 172.0 Estimated Top (ftKB) 11,183.0 Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 93.0 Thickening Time (hr) 8.50 1st Compressive Strength (psi) 1,000.0 Cement Stage Fluid Additives Add Type Conc Page 1/1 Well Name: NDBi-006 Report Printed: 12/15/2025www.peloton.com Cement API/UWI 50103209260000 Surface Legal Location Field Name Pikka PTD # 225-101 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.83 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.00 KB-Casing Flange Distance (ft) Spud Date 11/7/2025 21:30 Rig Release Date 12/7/2025 04:00 Intermediate Casing Cement Stage 3 Intermediate Casing Cement Stage 3, Casing, 11/20/2025 12:30 Type Casing Cementing Start Date 11/20/2025 Cementing End Date 11/20/2025 Wellbore Original Hole String Intermediate Liner, 11,824.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Bond Log Cement Evaluation Results Logged with Halliburton CAST-M. Logged 3rd stage cement jobs from 6,350' MD to 2,646' MD. Several areas of good cement noted from 2,916'-3,285' MD, 4,125-4,154' MD, and 5,548'-5,603' MD, indicated good isolation above and below the Tuluvak hydrocarbon bearing sands. The remaining interval indicates all fair to poor cement bond classification. See Halliburton report for more details. Comment Conduct 3nd stage cementing of 9-5/8 47# Intermediate casing by open hole annulus through Archer cementing tool as follows: -Fill lines with Water and test 1,000 psi low, 4,500 psi high. -Mix and pump 80 bbls of 12.5 ppg Mud Flush w/ Red Die at 4 bpm, ICP 340 psi, FCP 308 psi, No Losses. -Mix and pump 80 bbls 13.5 ppg Tuned spacer at 4.2 bpm ICP 328 psi, FCP 248 psi. No losses. -Mix and pump 288 bbls of 15.3 ppg Versacem Type I-II Tail cement at 4 bpm, ICP 484 psi, Final pump rate 4 bpm, FCP 610 psi. No Losses. -Displace with calculated volume of 111 bbls of 11.5 ppg OBM thru Archer Stage Collar set at 5,305. Initial pump rate 4 bpm ICP 336 psi slowed rate to 3 bpm 40 bbls into displacement after losing full returns. 72 bbl lost during displacement. -CIP @ 16:00 hrs. - Close C-flex and Set LTP. Circulate off liner top and dump 160 bbls of spacer + trace cement, and 452 bbls of contiminated interface to cuttings box. 3, 2,718.0-5,656.0ftKB Top Depth (ftKB) 2,718.0 Bottom Depth (ftKB) 5,656.0 Full Return? No Vol Cement Ret (bbl) Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 600.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Mud Flush Spacer Fluid Type Mud Flush Spacer Fluid Description Mud Flush Spacer 8# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 2.22 Mix H20 Ratio (gal/sack) 12.89 Free Water (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Tuned Spacer Fluid Type Tuned Spacer Fluid Description Tuned Spacer 4# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) Density (lb/gal) 13.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Versacem Tail Fluid Type Versacem Tail Fluid Description Versacem Type I/II Amount (sacks) 1,295 Class I/II Volume Pumped (bbl) 285.0 Estimated Top (ftKB) 2,739.0 Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 122.3 Thickening Time (hr) 8.50 1st Compressive Strength (psi) 500.0 Cement Stage Fluid Additives Add Type Conc Attachment D Attachment E Attachment F Well NameNDBi-00612/11/25 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aWFbWF 261.000000c Pump Check WF26 403203201344013440320320dDrop Stage 1 Ball/Collet FP 0 403323 126 13566 3 323e DFITXL26 40280603 11760 25326 280 603fSlow for SeatXL26 1850653 2100 27426 50 653g DFIT Displacment then HSDWF26 40330983 13860 41286 330 983 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOBSTAGE CUMSTAGE CUM Size or Stage Cum# PPA TYPE (BPM) (BBL) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) Type (BBL) (BBL)10Line out XL XL 26184040 10231680 429660 0 40 102320Stage 1 PADXL 2618 325365 134813650 566160 0CSG-IV325 134831Flat; Add Patina Tracer to PODXL 2630 120485 14685040 616564826 4826CSG-IV115 146342FlatXL 2630 135620 16035670 6732610415 15241CSG-IV124 158753FlatXL 2630 145765 17486090 7341616122 31363CSG-IV128 171564FlatXL 2630 145910 18936090 7950620686 52049CSG-IV123 183875FlatXL 2630 1451055 20386090 8559624918 76966CSG-IV119 195786FlatXL 2630 1451200 21836090 9168628853 105819CSG-IV114 207197FlatXL 2630 1351335 23185670 9735630278 136098CSG-IV103 2174108FlatXL 2630 1151450 24334830 10218628512 164609CSG-IV85 2259110Clear Surface LinesXL 2630 251475 24581050 1032360 164609 25 2284120Spacer XL 2630151490 2473630 1038660 164609 15 2299130Drop Stage 2 Ball/Collet FP 03031493 2476126 1039920 164609 3 2302140Stage 2 PADXL 2630 2711764 274711382 1153740 164609 271 2573150Slow for Seat XL 2618501814 27972100 1174740 164609 50 2623160Resume PadXL 2625 11815 279842 1175160 164609 1 2624171FlatXL 2625 1001915 28984200 1217164021 168631CSG-IV96 2720182FlatXL 2625 1202035 30185040 1267569258 177888CSG-IV110 2830193FlatXL 2625 1352170 31535670 13242615010 192899CSG-IV119 2949204FlatXL 2625 1352305 32885670 13809619259 212158CSG-IV115 3064215FlatXL 2625 1352440 34235670 14376623199 235357CSG-IV110 3174226FlatXL 2625 1352575 35585670 14943626863 262220CSG-IV107 3281237FlatXL 2625 1252700 36835250 15468628036 290256CSG-IV95 3376248FlatXL 2625 1102810 37934620 15930627272 317528CSG-IV81 3457250Clear Surface LinesXL 2625 252835 38181050 1603560 317528 25 3482260Spacer XL 2625152850 3833630 1609860 317528 15 3497270Drop Stage 3 Ball/Collet FP 02532853 3836126 1611120 317528 3 3500280Stage 3 PADXL 2625 2643117 410011088 1722000 317528 264 3764290Slow for Seat XL 2618503167 41502100 1743000 317528 50 3814300Resume PadXL 2625 13168 415142 1743420 317528 1 3815311FlatXL 2625 1003268 42514200 1785424021 321549CSG-IV96 3911FLUID Neat WaterCOMMENTSEnsure Stage 2 ball/collet is loaded Prime and Pressure TestOpen well Well NameNDBi-00612/11/25 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUID Neat Water322FlatXL 2625 1203388 43715040 1835829258 330807CSG-IV110 4021333FlatXL 2625 1353523 45065670 18925215010 345817CSG-IV119 4140344FlatXL 2625 1353658 46415670 19492219259 365076CSG-IV115 4255355FlatXL 2625 1353793 47765670 20059223199 388276CSG-IV110 4365366FlatXL 2625 1353928 49115670 20626226863 415139CSG-IV107 4472377FlatXL 2625 1254053 50365250 21151228036 443174CSG-IV95 4567388FlatXL 2625 1104163 51464620 21613227272 470446CSG-IV81 4649390Clear Surface LinesXL 2625 254188 51711050 2171820 470446 25 4674400Spacer XL 2625154203 5186630 2178120 470446 15 4689410Drop Stage 4 Ball/Collet FP 02534206 5189126 2179380 470446 3 4692420Stage 4 PADXL 2625 2564462 544510752 2286900 470446 256 4948430Slow for Seat XL 2618504512 54952100 2307900 470446 50 4998440Resume PadXL 2630 444556 55391848 2326380 470446 44 5042451FlatXL 2630 1204676 56595040 2376784826 475272CSG-IV115 5157462FlatXL 2630 1354811 57945670 24334810415 485687CSG-IV124 5281473FlatXL 2630 1504961 59446300 24964816678 502365CSG-IV132 5413484FlatXL 2630 1505111 60946300 25594821399 523764CSG-IV127 5540495FlatXL 2630 1505261 62446300 26224825777 549541CSG-IV123 5663506FlatXL 2630 1505411 63946300 26854829848 579389CSG-IV118 5781517FlatXL 2630 1405551 65345880 27442831400 610789CSG-IV107 5888528FlatXL 2630 1255676 66595250 27967830991 641779CSG-IV92 5980530Clear Surface LinesXL 2630 255701 66841050 2807280 641779 25 6005540Spacer XL 2630155716 6699630 2813580 641779 15 6020550Drop Stage 5 Ball/Collet FP 03035719 6702126 2814840 641779 3 6023560Stage 5 PADXL 2630 2495968 695110458 2919420 641779 249 6272570Slow for Seat XL 2618506018 70012100 2940420 641779 50 6322580Resume PadXL 2640 766094 70773192 2972340 641779 76 6398591FlatXL 2640 1256219 72025250 3024845027 646806CSG-IV120 6518602FlatXL 2640 1406359 73425880 30836410801 657607CSG-IV129 6647613FlatXL 2640 1706529 75127140 31550418902 676509CSG-IV150 6797624FlatXL 2640 1706699 76827140 32264424252 700761CSG-IV144 6941635FlatXL 2640 1706869 78527140 32978429214 729975CSG-IV139 7080646FlatXL 2640 1707039 80227140 33692433827 763802CSG-IV134 7214657FlatXL 2640 1407179 81625880 34280431400 795202CSG-IV107 7321668FlatXL 2640 1257304 82875250 34805430991 826193CSG-IV92 7413670Clear Surface LinesXL 2640 257329 83121050 3491040 826193 25 7438680Spacer XL 2640157344 8327630 3497340 826193 15 7453690Drop Stage 6 Ball/Collet FP 04037347 8330126 3498600 826193 3 7456700Stage 6 PADXL 2640 2417588 857110122 3599820 826193 241 7697710Slow for Seat XL 2618507638 86212100 3620820 826193 50 7747720Resume PadXL 2640 1097747 87304578 3666600 826193 109 7856731FlatXL 2640 1507897 88806300 3729606032 832225CSG-IV144 8000742FlatXL 2640 1758072 90557350 38031013501 845726CSG-IV161 8161 Well NameNDBi-00612/11/25 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUID Neat Water753FlatXL 2640 2008272 92558400 38871022238 867964CSG-IV176 8337764FlatXL 2640 2008472 94558400 39711028532 896496CSG-IV170 8507775FlatXL 2640 2008672 96558400 40551034369 930865CSG-IV164 8671786FlatXL 2640 2008872 98558400 41391039797 970662CSG-IV158 8829797FlatXL 2640 1709042 100257140 42105038128 1008790CSG-IV130 8958808FlatXL 2640 1359177 101605670 42672033470 1042261CSG-IV100 9058810Clear Surface LinesXL 2640 259202 101851050 4277700 1042261 25 9083820Spacer XL 2640159217 10200630 4284000 1042261 15 9098830Drop Stage 7 Ball/Collet FP 04039220 10203126 4285260 1042261 3 9101840XL Flush (DFIT)XL 2640 2339453 104369786 4383120 1042261 233 9334850Slow for seat (DFIT) XL 2618509503 104862100 4404120 1042261 50 938486DFIT FlushWF 2640205 9708 106918610 449022205 9589873000 feet MD + Surface EqmtFP20 709778 107612949 451971TOTALS10761 4519711042261 Well NameNDBi-00612/11/25 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbWF 263.54040168016804040cWF 263.5265265945011130265305d Pump CheckWF26 41003654200153301004050 405 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOBSTAGE CUMSTAGE CUM Size or Stage Cum# PPA TYPE (BPM) (BBL) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) Type (BBL) (BBL)10Line out XL XL 26184040 4051680 170100 0 40 44520Stage 7 PADXL 2640 375415 78015750 327600 016/20-CL375 82031FlatXL 2640 125540 9055250 380105028 502816/20-CL120 94042FlatXL 2640 140680 10455880 4389010804 1583116/20-CL129 106853FlatXL 2640 170850 12157140 5103018910 3474116/20-CL150 121864FlatXL 2640 1701020 13857140 5817024265 5900716/20-CL144 136375FlatXL 2640 1701190 15557140 6531029233 8823916/20-CL139 150286FlatXL 2640 1701360 17257140 7245033853 12209216/20-CL134 163697FlatXL 2640 1401500 18655880 7833031426 15351816/20-CL107 1743108FlatXL 2640 1251625 19905250 8358031020 18453816/20-CL92 1836110Clear Surface LinesXL 2640 251650 20151050 846300 184538 25 1861120Spacer XL 2640151665 2030630 852600 184538 15 1876130Drop Stage 8 Ball/Collet FP 04031668 2033126 853860 184538 3 1879140Stage 8 PADXL 2640 2261894 22599492 948780 184538 226 2105150Slow for Seat XL 2618501944 23092100 969780 184538 50 2155160Resume PadXL 2640 1242068 24335208 1021860 184538 124 2279171FlatXL 2640 2002268 26338400 1105868044 19258216/20-CL192 2470182FlatXL 2640 2252493 28589450 12003617363 20994516/20-CL207 2677194FlatXL 2640 2752768 313311550 13158639253 24919816/20-CL234 2910206FlatXL 2640 2603028 339310920 14250651775 30097216/20-CL205 3116218FlatXL 2640 2403268 363310080 15258659558 36053016/20-CL177 32932210FlatXL 2640 2003468 38338400 16098658233 41876316/20-CL139 3432230Clear Surface LinesXL 2640 253493 38581050 1620360 418763 25 3457240Spacer XL 2640153508 3873630 1626660 418763 15 3472250Drop Stage 9 Ball/Collet FP 04033511 3876126 1627920 418763 3 3475260Stage 9 PADXL 2640 2183729 40949156 1719480 418763 218 3693270Slow for Seat XL 2618503779 41442100 1740480 418763 50 3743280Resume PadXL 2640 13780 414542 1740900 418763 1 3744291ScourXL 2640 603840 42052520 1766102413 42117640/70-CL57 3801303ScourXL 2640 1203960 43255040 18165013348 43452440/70-CL106 3907310Resume PadXL 2640 504010 43752100 1837500 434524 50 3957321FlatXL 2640 2004210 45758400 1921508044 44256816/20-CL192 4149332FlatXL 2640 2254435 48009450 20160017363 45993216/20-CL207 4355344FlatXL 2640 2754710 507511550 21315039253 49918416/20-CL234 4589Stage to "Line out XL"FLUID Neat WaterCOMMENTSEnsure Stage 8 ball/collet is loaded Prime and Pressure TestOpen wellPump Ball to Seat Well NameNDBi-00612/11/25 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUID Neat Water356FlatXL 2640 2604970 533510920 22407051775 55095916/20-CL205 4795368FlatXL 2640 2405210 557510080 23415059558 61051716/20-CL177 49723710FlatXL 2640 2005410 57758400 24255058233 66875016/20-CL139 5110380Clear Surface LinesXL 2640 255435 58001050 2436000 668750 25 5135390Spacer XL 2640155450 5815630 2442300 668750 15 5150400Drop Stage 10 Ball/Collet FP 04035453 5818126 2443560 668750 3 5153410Stage 10 PADXL 2640 2115664 60298862 2532180 668750 211 5364420Slow for Seat XL 2618505714 60792100 2553180 668750 50 5414430Resume PadXL 2640 1395853 62185838 2611560 668750 139 5553441FlatXL 2640 1906043 64087980 2691367642 67639216/20-CL182 5735453FlatXL 2640 2156258 66239030 27816623915 70030716/20-CL190 5925465FlatXL 2640 2406498 686310080 28824641270 74157716/20-CL197 6122477FlatXL 2640 2406738 710310080 29832653874 79545016/20-CL183 6305489FlatXL 2640 2206958 73239240 30756659475 85492516/20-CL157 64624910FlatXL 2640 1807138 75037560 31512652410 90733516/20-CL125 6587500Clear Surface LinesXL 2640 257163 75281050 3161760 907335 25 6612510Spacer XL 2640157178 7543630 3168060 907335 15 6627520Drop Stage 11 Ball/Collet FP 04037181 7546126 3169320 907335 3 6630530Stage 11 PADXL 2640 2037384 77498526 3254580 907335 203 6833540Slow for Seat XL 2618507434 77992100 3275580 907335 50 6883550Resume PadXL 2640 17435 780042 3276000 907335 1 6884561ScourXL 2640 607495 78602520 3301202413 90974840/70-CL57 6942573ScourXL 2640 1207615 79805040 33516013348 92309640/70-CL106 7048580FlatXL 2640 507665 80302100 3372600 923096 50 7098591FlatXL 2640 2007865 82308400 3456608044 93114116/20-CL192 7289602FlatXL 2640 2258090 84559450 35511017363 94850416/20-CL207 7496614FlatXL 2640 2758365 873011550 36666039253 98775716/20-CL234 7729626FlatXL 2640 2608625 899010920 37758051775 103953116/20-CL205 7935638FlatXL 2640 2408865 923010080 38766059558 109908916/20-CL177 81126410FlatXL 2640 2009065 94308400 39606058233 115732216/20-CL139 8251650Clear Surface LinesXL 2640 259090 94551050 3971100 1157322 25 8276660Spacer XL 2640159105 9470630 3977400 1157322 15 8291670Drop Stage 12 Ball/Collet FP 04039108 9473126 3978660 1157322 3 8294680XL Flush (DFIT)XL 2640 1949302 96678148 4060140 1157322 194 8488690Slow for seat (DFIT) XL 2618509352 97172100 4081140 1157322 50 8538700Resume DFITXL 2640 2069558 99238652 4167660 1157322 206 874471DFIT FlushWF 2640170 9728 100937140 422226170 8914723000 feet MD + Surface EqmtFP20 709798 101632949 425175TOTALS10163 4251751157322 Well NameNDBi-00612/11/25 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aFPbWF 2644040168016804040cWF 263.5225265945011130225265d Pump CheckWF26 41003654200153301003650 365 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOBSTAGE CUMSTAGE CUM Size or Stage Cum# PPA TYPE (BPM) (BBL) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) Type (BBL) (BBL)10Line out XL XL 26184040 4051680 170100 0 40 40520Stage 12 PADXL 2640 450490 85518900 359100 016/20-CL450 85531FlatXL 2640 175665 10307350 432607039 703916/20-CL168 102342FlatXL 2640 190855 12207980 5124014662 2170116/20-CL175 119753FlatXL 2640 2101065 14308820 6006023359 4506016/20-CL185 138364FlatXL 2640 2101275 16408820 6888029975 7503516/20-CL178 156175FlatXL 2640 2101485 18508820 7770036111 11114616/20-CL172 173386FlatXL 2640 2101695 20608820 8652041818 15296416/20-CL166 189997FlatXL 2640 1701865 22307140 9366038160 19112416/20-CL130 2029108FlatXL 2640 1552020 23856510 10017038464 22958816/20-CL114 2143110Clear Surface LinesXL 2640 252045 24101050 1012200 229588 25 2168120Spacer XL 2640152060 2425630 1018500 229588 15 2183130Drop Stage 13 Ball/Collet FP 04032063 2428126 1019760 229588 3 2186140Stage 13 PADXL 2640 1842247 26127728 1097040 229588 184 2370150Slow for Seat XL 2618502297 26622100 1118040 229588 50 2420160Resume PadXL 2640 1412438 28035922 1177260 229588 141 2561171FlatXL 2640 1902628 29937980 1257067642 23723016/20-CL182 2743183FlatXL 2640 2152843 32089030 13473623915 26114616/20-CL190 2933195FlatXL 2640 2403083 344810080 14481641270 30241516/20-CL197 3129207FlatXL 2640 2403323 368810080 15489653874 35628916/20-CL183 3313219FlatXL 2640 2203543 39089240 16413659475 41576416/20-CL157 34702210FlatXL 2640 1803723 40887560 17169652410 46817416/20-CL125 3595230Clear Surface LinesXL 2640 253748 41131050 1727460 468174 25 3620240Spacer XL 2640153763 4128630 1733760 468174 15 3635250Drop Stage 14 Ball/Collet FP 04033766 4131126 1735020 468174 3 3638260Stage 14 PADXL 2640 1643930 42956888 1803900 468174 164 3802270Slow for Seat XL 2618503980 43452100 1824900 468174 50 3852280Resume PadXL 2640 1864166 45317812 1903020 468174 186 4038291FlatXL 2640 1504316 46816300 1966026033 47420716/20-CL144 4181302FlatXL 2640 1754491 48567350 20395213505 48771216/20-CL161 4342313FlatXL 2640 2004691 50568400 21235222247 50995916/20-CL177 4519324FlatXL 2640 2004891 52568400 22075228547 53850616/20-CL170 4689335FlatXL 2640 2005091 54568400 22915234391 57289716/20-CL164 4852346FlatXL 2640 2005291 56568400 23755239827 61272416/20-CL158 5010FLUID Neat WaterCOMMENTSEnsure Stage 13 ball/collet is loaded Prime and Pressure TestDisplace PT- SD 5 MinPump Ball to SeatStage to "Line out XL" Well NameNDBi-00612/11/25 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUID Neat Water357FlatXL 2640 1755466 58317350 24490239283 65200716/20-CL134 5144368FlatXL 2640 1355601 59665670 25057233501 68550816/20-CL100 5244370Clear Surface LinesXL 2640 255626 59911050 2516220 685508 25 5269380Spacer XL 2640155641 6006630 2522520 685508 15 5284390Drop Stage 15 Ball/Collet FP 04035644 6009126 2523780 685508 3 5287400Stage 15 PADXL 2640 1565800 61656552 2589300 685508 156 5443410Slow for Seat XL 2618505850 62152100 2610300 685508 50 5493420Resume PadXL 2640 15851 621642 2610720 685508 1 5494431ScourXL 2640 605911 62762520 2635922413 68792140/70-CL57 5551443ScourXL 2640 1206031 63965040 26863213348 70126940/70-CL106 5657450Resume PADXL 2640 506081 64462100 2707320 701269 50 5707461FlatXL 2640 2006281 66468400 2791328044 70931316/20-CL192 5899472FlatXL 2640 2256506 68719450 28858217363 72667716/20-CL207 6105484FlatXL 2640 2756781 714611550 30013239253 76592916/20-CL234 6339496FlatXL 2640 2607041 740610920 31105251775 81770416/20-CL205 6545508FlatXL 2640 2407281 764610080 32113259558 87726116/20-CL177 67225110FlatXL 2640 2007481 78468400 32953258233 93549516/20-CL139 6860520XL FlushXL264010 7491 7856420 32827210 6870530LG FlushWF2640105 7596 79614410 332682105 6975543000 feet MD + Surface EqmtFP20 707666 80312949 335631TOTALS7991 335631935495 Additive Additive Description D206 Antifoam Agent 0.0 Gal/mGal 10 gal F103 Surfactant 1.0 Gal/mGal 913.0 gal J450 Stabilizing Agent 0.5 Gal/mGal 456.0 gal J475 Breaker J475 6.0 lb/mGal 5,477.0 lbm J511 Stabilizing Agent 2.0 lb/mGal 1,826.0 lbm J532 Crosslinker 2.5 Gal/mGal 2,282.0 gal J580 Gel J580 26.0 lb/mGal 23,736.0 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 68.0 gal M002 Additive 0.0 lb/mGal 2 lbm M117 Clay Control Agent 333.3 lb/mGal 304,304.0 lbm M275 Bactericide 0.3 lb/mGal 264.0 lbm S522-1620 Propping Agent varied concentrations 3,085,516.0 lbm S522-4070 Propping Agent varied concentrations 47,362.0 lbm ~ 70 % ~ 27 % ~ 3 % < 1 % < 1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.1 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.01 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.0001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % < 0.00001 % 100 % State: Alaska County/Parish: North Slope Borough Case: Client: Oil Search Alaska Well: PIKKA NDBi-006 Basin/Field: Pikka Fluid Name & Volume Concentration Volume Disclosure Type: Pre-Job Well Completed: Date Prepared: 12/15/2025 CAS Number Chemical Name Mass Fraction - Water (Including Mix Water Supplied by Client)* YF126ST:WF126 912,910 gal Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. 68715-83-3 2-Butenedioic acid (2Z)-, polymer with sodium 2-propene-1-sulfonate 7647-14-5 Sodium chloride 7727-54-0 Diammonium peroxodisulphate 66402-68-4 Ceramic materials and wares, chemicals 7447-40-7 Potassium chloride 9000-30-0 Guar gum 9003-35-4 Phenolic resin 50-70-4 Sorbitol 67-63-0 Propan-2-ol 56-81-5 1, 2, 3 - Propanetriol 102-71-6 2,2`,2"-nitrilotriethanol 1303-96-4 Sodium tetraborate decahydrate 68131-39-5 Ethoxylated Alcohol 37288-54-3 Beta-Mannanase 91053-39-3 Diatomaceous earth, calcined 111-76-2 2-butoxyethanol 34398-01-1 Ethoxylated C11 Alcohol 25038-72-6 Vinylidene chloride/methylacrylate copolymer 14807-96-6 Magnesium silicate hydrate (talc) 9002-84-0 poly(tetrafluoroethylene) 111-42-2 2,2'-Iminodiethanol 112-42-5 1-undecanol (impurity) 7631-86-9 Silicon Dioxide (Impurity) 10377-60-3 Magnesium nitrate 67762-90-7 Siloxanes and silicones, dimethyl, reaction products with silica 127-08-2 Acetic acid, potassium salt (impurity) 14808-60-7 Quartz, Crystalline silica 55965-84-9 5-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one 7786-30-3 Magnesium chloride 63148-62-9 Dimethyl siloxanes and silicones 64-19-7 Acetic acid (impurity) 1310-73-2 Sodium hydroxide 68308-89-4 Fatty acids, C18-unsatd., dimers, ethoxylated propoxylated 14464-46-1 Cristobalite 532-32-1 Sodium benzoate 1338-41-6 Sorbitan stearate 9005-65-6 Sorbitan monooleate, ethoxylated 11138-66-2 Xanthan Gum 9004-32-4 Sodium carboxymethylcellulose 36089-45-9 2-Propenoic acid, 2-ethylhexyl ester, polymer with 2-hydroxyethyl 2-propenoate 68937-55-3 Siloxanes and Silicones, di-Me, 3-hydroxypropyl Me, ethoxylated propoxylated 24634-61-5 Potassium (E,E)-hexa-2,4-dienoate 9000-90-2 Amylase, alpha Total * Mix water is supplied by the client. Schlumberger has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third-parties. * The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC - Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. 7632-00-0 Sodium nitrite 533-74-4 Tetrahydro-3,5-dimethyl-1,3,5-thiadiazine-2-thione 2634-33-5 1,2-benzisothiazolin-3-one # SLB-Private Page: 1 / 1 Updated 12/16/202512/16/2025TBDAK TSCA StatusNorth SlopeTBDPreTBDTBDTBDTrade Name Supplier Purpose Ingredients Name CAS #Percentage by Mass of IngredientPercent of Ingredient in Total Mass PumpedMass of Ingredient (lbs)SME Tracerco Carrier Fluid Soy Methyl Ester 67784-80-9 100 #VALUE! 112.6560820000T-160D Tracerco Chemical Tracer 2,4,5-Tribromotoluene 3278-88-4 100 #VALUE! 0.6613860000T-163B Tracerco Chemical Tracer 1,2-Diiodobenzene 615-42-9 100 #VALUE! 0.4409240000T-164C Tracerco Chemical Tracer 1-Iodonaphthalene 90-14-2 100 #VALUE! 0.4409240000T-165C Tracerco Chemical Tracer 9-Bromophenanthrene 573-17-1 100 #VALUE! 0.6613860000T-168A Tracerco Chemical Tracer 1-Chloro-4-iodobenzene 637-87-6 100 #VALUE! 0.4409240000T-168B Tracerco Chemical Tracer 1,2-Dichloro-4-iodobenzene 20555-91-3 100 #VALUE! 0.4409240000T-168C Tracerco Chemical Tracer 1-Bromo-4-iodobenzene 589-87-7 100 #VALUE! 0.4409240000T-716 Tracerco Chemical Tracer 1,3,5-Tribromobenzene 626-39-1 100 #VALUE! 0.4409240000T-718 Tracerco Chemical Tracer 4-Chlorobenzophenone 134-85-0 100 #VALUE! 0.6613860000T-729 Tracerco Chemical Tracer 1,4-Dibromo-2,5-dimethyl benzene 1074-24-4 100 #VALUE! 2.2046200000T-731 Tracerco Chemical Tracer 1-Bromo-3,5-dichlorobenzene 19752-55-7 100 #VALUE! 0.4409240000T-748 Tracerco Chemical Tracer 1-Bromo-2-chlorobenzene 694-80-4 100 #VALUE! 2.2046200000T-750 Tracerco Chemical Tracer 1,4-Dibromo-2-fluorobenzene 1435-52-5 100 #VALUE! 0.4409240000T-758 Tracerco Chemical Tracer 3,4-Difluorobenzophenone 85118-07-6 100 #VALUE! 0.4409240000T-784 Tracerco Chemical Tracer 2,4,6-Tribromoanisole 607-99-8 100 #VALUE! 0.4409240000Water Tracerco Carrier Fluid Water 7732-18-5 100 #VALUE! 131.7425500000T-140a Tracerco Chemical Tracer Sodium-2-fluorobenzoate 490-97-1 100 #VALUE! 0.7716170000T-158b Tracerco Chemical Tracer Sodium-2,5-Difluorobenzoate 522651-42-9 100 #VALUE! 0.7716170000T-158d Tracerco Chemical Tracer Sodium-3,4-Difluorobenzoate 522651-44-1 100 #VALUE! 0.7716170000T-158e Tracerco Chemical Tracer Sodium-3,5-Difluorobenzoate 530141-39-0 100 #VALUE! 0.7716170000T-190a Tracerco Chemical Tracer Sodium-2-(Trifluoromethyl) benzoate 2966-44-1 100 #VALUE! 0.7716170000T-804 Tracerco Chemical Tracer Sodium-2,3-dichlorobenzoate 118537-84-1 100 #VALUE! 0.7716170000T-808 Tracerco Chemical Tracer Sodium-3,4-dichlorobenzoate 17274-10-1 100 #VALUE! 0.7716170000T-809 Tracerco Chemical Tracer Sodium-3,5-dichlorobenzoate 154862-40-5 100 #VALUE! 0.7716170000T-910 Tracerco Chemical Tracer Sodium-2-chloro-3-fluorobenzoate 1382106-83-3 100 #VALUE! 0.7716170000T-911 Tracerco Chemical Tracer Sodium-2-chloro-4-fluorobenzoate 885471-43-1 100 #VALUE! 0.7716170000T-917 Tracerco Chemical Tracer Sodium-4-chloro-2,5-difluorobenzoate 1421029-91-5 100 #VALUE! 0.7716170000T-921 Tracerco Chemical Tracer Sodium-3-chloro-2-fluorobenzoate 1421029-89-1 100 #VALUE! 0.7716170000T-928 Tracerco Chemical Tracer Sodium-2-fluoro-4-methylbenzoate 1708942-19-1 100 #VALUE! 0.7716170000T-931 Tracerco Chemical Tracer Sodium-4-fluoro-2-methylbenzoate 1708942-23-7 100 #VALUE! 0.7716170000T-943 Tracerco Chemical Tracer Sodium-3-chloro-2-methylbenzoate 1708942-17-9 100 #VALUE! 0.7716170000Report Type (Pre or Post Job)Total Water Volume (gal):Water Mass FractionTotal Mass Pumped (lbs)County:API Number:Operator Name: Oil Search Alaska, LLCWell Name and Number: NDBi-06/012Hydraulic Fracturing Fluid Product Component Information DisclosureManufacturer Contact Tracerco 4106 New West Dr. Pasadena Texas 77507 Tel: 281-291-7769Fracture DateState: Approved For Tracerco Hydraulic Fracturing Chemical Information Disclosure Supplier: Patina Energy 20 Kg Patina Brass Flow Insurance Proprietary chemical information on le supplied by Patina Energy to the AOGCC. Attachment G NDBi-006 Well Clean Up Summary Flow Periods Flowback Period Duration (hours)Purpose/Remarks Ramp Up 72-96 Bring well on slowly (16/64th) via adjustable choke, change as necessary to achieve stable flow. Monitor returns for proppant and adjust choke as necessary to avoid damage to reservoir proppant pack and minimize surface equipment erosion. Santos Subsurface Team will advise choke changes/rates during ramp up period. Clean Up 48+ Continue clean up period until there is a meaningful decline in solids volume to surface in combination with 2-3% WC. See Chart 1. Step Down 48-72 Measure well productivity and inflow performance. Build Up 240-336 Goal to identify linear-flow period after 10 hours. Table 1 Chart 1 Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flare the produced gas for the duration of the development well flowback work. Total volume of gas per the flowback program outlined in Table 1 is approximately 15 MMscf. Well Flowback - Operational Summary: Total flowback volume (including ramp up, clean up and step down periods) not to exceed 2.0X TLTR (total load to recover) from the frac job. Santos to contact AOGCC when 1.5X TLTR is recovered and provide update on solids content and WC. If necessary, additional flowback volume exceeding 2.0X TLTR may be approved if both parties agree after reviewing actual flowback data. Target Clean Up Flow Rate: 4500 BPD & 2.2 mmscf/d. Choke Setting: Use adjustable choke to achieve a flow rate at approximately 100 psi per hour drawdown or until well is stable. Watch BS&W and adjust drawdown rate as needed. The Santos Subsurface Team or Santos Well Test Supervisor will advise choke changes based on well performance and solids production. Proppant Production: Proppant production is expected and will be managed by bringing on the well slowly and beaning up choke based on well performance and bottoms up solids production. Annulus Pressure: The annulus pressure is expected to increase due to thermal expansion. The maximum annular pressure is 2,000 psi, bleed down as necessary. Sampling: Per Surface Sampling Program below in Table 2. Metering Standard Fluid Rates & Volumes - Tank Straps will be used for all reported fluid rates & volumes, in addition there will be turbine meters on the oil and water legs of the separator for reference. Gas Rates & Volumes - A micromotion Coriolis flow meter will be used for gas rates & volumes. Table 2 g Attachment H NDBi-006 4-1/2 Production Liner Section Summary Procedure: 1. Run 4-1/2 12.6 ppf P-110S TSH563 lower completions per tally. 2. Drop 1.125 phenolic ball during circulation to close WIV collar. 3. Pressure up to close the WIV at 1,485 psi. 4. Continue increasing pressure to start setting the liner hanger/packer at 2,500 psi. 5. Set the openhole packers and neutralize pusher tool to 4,100 psi. 6. Before releasing, pressure test the IA to top liner hanger/packer to 3,500 psi. 7. Release running tool from liner hanger. 8. Flow check for 10 minutes. 9. POOH with liner hanger running tool. 10.Prepare to run upper completion. NDBi-006 4-1/2 Upper Completion Section Summary Procedure: 11.Run 4-1/2 12.6 ppf P110S TSH563 tubing and downhole jewellery. 12.Circulate 9.2 ppg NaCl Corrosion Inhibited Brine. 13.Land tubing hanger. 14.MIT-T to 3,500 psi. (Post drilling rig move, MIT-T to be tested to 5,500 psi) a. (8,800 psi MAWP 3,800 psi IA hold) * 1.1 = 5,500 psi 15.MIT-IA to 4,000 psi. (Post drilling rig move, MIT-IA to be tested to 4,300 psi) 16.Shear circulation valve. 17.Reverse circulate freeze protect and U-Tube. 18.Install TWCV into the tubing hanger and pressure test from direction of flow. 19.Nipple down BOP stack and install 10k frac tree. 20.RDMO NDBi-006 Well Clean Up Procedure 1. Move in and rig up Well Clean Up Surface Equipment as per P&ID and Pad Layout/Flow Diagram 2. Perform Low pressure air test of 100 120 psi, hold 10 minutes. (N2 will be used if hydrocarbon is present) 3. Pressure test all surface equipment and hardline upstream of the choke manifold to 5000psi and hold 15 minutes. Pressure test all surface equipment and hardline downstream of the choke manifold (with exception of flare) to 1000 psi and hold 15 minutes. Cap the gas line to the flare and test with air to 120 psi, hold 15 minutes. (N2 will be used if hydrocarbon is present). 4. Perform clean-up operations as per procedures. 5. Perform sampling as per procedures. 6. Rig down and demobilize equipment. Attachment I Attachment J Tuluvak Sand @ 3256' MD Top Nan 3.2 @11,785' MD NDBi-006 Well Schematic As-Built 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2718' MD 13-3/8" 68 ppf L-80 Surface Casing2883' MD 9-5/8", 47ppf L-80 Production Liner 11,824' MD 4-½, 12.6ppf P-110S Production Liner21,132' MD 4-½ Liner Hanger/ Top Packer11,652' MD GL 70.1' RKB Bottom Flange 12/15/2025 9-5/8" Tieback2718' MD 9-5/8" Cflex Stage Tool (50' MD below TS790) 5305' MD 8-½ Openhole TD21,148' MD Fault 20,532'/20612' MD Fault ~11,600' MD 9-5/8" Cflex Stage Tool (Placed @ Top Nan FM.)10349' MD 9-5/8" Primary TOC~11,183' MD Fault 14,790' MD Top of Nan 10,334' MD 1 2 3 4 5 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 6 # Completion Item TopDepth (MD') Depth (TVD') Inc ID" OD" 1 X LandingNipple 1601 1463 27 3.813 4.784 2 Gaslift Mandrel 1.5" 2198 1978 46 3.865 7.630 3 X LandingNipple 2268 2027 48 3.813 4.784 4 D/HPsi TempGauge 11490 3978 78 3.905 5.040 5 EGLValve 11554 3991 78 3.909 6.118 6 Tieback Seal Assy 11690 4014 78 3.860 5.230 7 9.625"x 4.5" LH/Packer 11652 4006 78 6.030 8.480 8 #25OHpacker 11939 4063 81 3.918 8.000 9 #24OHpacker 12006 4072 83 3.918 8.000 10 Stage 15 12238 4084 90 3.735 5.630 11 #23OHpacker 12550 4084 90 3.918 8.000 12 Stage 14 12782 4085 90 3.735 5.630 13 #22OHpacker 13010 4085 90 3.918 8.000 14 #21OHpacker 13118 4085 90 3.918 8.000 15 #20OHpacker 13676 4087 90 3.918 8.000 16 #19OHpacker 13826 4087 90 3.918 8.000 17 Stage 13 14098 4088 90 3.735 5.630 18 #18OHpacker 14409 4089 90 3.918 8.000 19 #17OHpacker 14517 4089 90 3.918 8.000 20 Stage 12 14749 4089 90 3.735 5.630 Fault 14790 4089 90 21 #16OHpacker 14934 4090 90 3.918 8.000 22 #15OHpacker 15125 4090 90 3.918 8.000 23 Stage 11 15357 4091 90 3.735 5.630 24 #14OHpacker 15628 4092 90 3.918 8.000 25 Stage 10 15859 4093 90 3.735 5.630 26 #13OHpacker 16088 4095 90 3.918 8.000 27 Stage 9 16360 4096 90 3.735 5.630 28 #12OHpacker 16627 4097 90 3.918 8.000 29 Stage 8 16858 4098 90 3.735 5.630 30 #11OHpacker 17126 4099 90 3.918 8.000 31 Stage 7 17358 4100 90 3.735 5.630 32 #10OHpacker 17628 4100 90 3.918 8.000 33 Stage 6 17858 4100 90 3.735 5.630 34 #9OHpacker 18125 4100 90 3.918 8.000 35 Stage 5 18358 4101 90 3.735 5.630 36 #8OHpacker 18626 4101 90 3.918 8.000 37 Stage 4 18857 4102 90 3.735 5.630 38 #7OHpacker 19169 4103 90 3.918 8.000 39 Stage 3 19360 4103 90 3.735 5.630 40 #6OHpacker 19630 4104 90 3.918 8.000 41 Stage 2 19862 4104 90 3.735 5.630 42 #5OHpacker 20130 4101 92 3.918 8.000 43 #4OHpacker 20239 4097 92 3.918 8.000 Fault 20532 20612 4092 89 44 #3OHpacker 20676 4094 90 3.918 8.000 45 #2OHpacker 20783 4093 91 3.918 8.000 46 Stage 1 21014 4093 90 3.735 5.630 47 #1OHpacker 21038 4093 90 3.918 8.000 48 Toe Sleeve 21104 4093 90 3.040 5.610 49 WIV Collar 21118 4093 90 0.880 5.610 50 Eccentricshoe 21130 4093 90 3.930 5.200 LinerToe 21132 4093 90 Attachment K Kinetix-Frac Completion Report Santos Country:United States Well Name:NDBi-006 Operator:Santos Field:Pikka Formation:Nanushuk Prepared By: Javier M. Del Real Report Date:December 11, 2025 Table of Contents Well Description ......................................................................................................................................................................................... 4 Stage 1 ....................................................................................................................................................................................................... 5 Zoneset Simulated: ................................................................................................................................................................................ 5 Pumping Schedule Simulated: ............................................................................................................................................................... 9 Simulation Summary: ........................................................................................................................................................................... 10 Stage 2 ..................................................................................................................................................................................................... 11 Zoneset Simulated: .............................................................................................................................................................................. 11 Pumping Schedule Simulated: ............................................................................................................................................................. 15 Simulation Summary: ........................................................................................................................................................................... 16 Stage 3 ..................................................................................................................................................................................................... 17 Zoneset Simulated: .............................................................................................................................................................................. 17 Pumping Schedule Simulated: ............................................................................................................................................................. 21 Simulation Summary: ........................................................................................................................................................................... 22 Stage 4 ..................................................................................................................................................................................................... 23 Zoneset Simulated: .............................................................................................................................................................................. 23 Pumping Schedule Simulated: ............................................................................................................................................................. 27 Simulation Summary: ........................................................................................................................................................................... 28 Stage 5 ..................................................................................................................................................................................................... 29 Zoneset Simulated: .............................................................................................................................................................................. 29 Pumping Schedule Simulated: ............................................................................................................................................................. 33 Simulation Summary: ........................................................................................................................................................................... 34 Stage 6 ..................................................................................................................................................................................................... 35 Zoneset Simulated: .............................................................................................................................................................................. 35 Pumping Schedule Simulated: ............................................................................................................................................................. 39 Simulation Summary: ........................................................................................................................................................................... 40 Stage 7 ..................................................................................................................................................................................................... 41 Zoneset Simulated: .............................................................................................................................................................................. 41 Pumping Schedule Simulated: ............................................................................................................................................................. 45 Simulation Summary: ........................................................................................................................................................................... 46 Stage 8 ..................................................................................................................................................................................................... 47 Zoneset Simulated: .............................................................................................................................................................................. 47 Pumping Schedule Simulated: ............................................................................................................................................................. 51 Simulation Summary: ........................................................................................................................................................................... 52 Attachment K: NDBI-006 Page 3 of 101 Stage 9 ..................................................................................................................................................................................................... 53 Zoneset Simulated: .............................................................................................................................................................................. 53 Pumping Schedule Simulated: ............................................................................................................................................................. 57 Simulation Summary: ........................................................................................................................................................................... 59 Stage 10 ................................................................................................................................................................................................... 60 Zoneset Simulated: .............................................................................................................................................................................. 60 Pumping Schedule Simulated: ............................................................................................................................................................. 64 Simulation Summary: ........................................................................................................................................................................... 65 Stage 11 ................................................................................................................................................................................................... 66 Zoneset Simulated: .............................................................................................................................................................................. 66 Pumping Schedule Simulated: ............................................................................................................................................................. 70 Simulation Summary: ........................................................................................................................................................................... 72 Stage 12 ................................................................................................................................................................................................... 73 Zoneset Simulated: .............................................................................................................................................................................. 73 Pumping Schedule Simulated: ............................................................................................................................................................. 80 Simulation Summary: ........................................................................................................................................................................... 81 Stage 13 ................................................................................................................................................................................................... 82 Zoneset Simulated: .............................................................................................................................................................................. 82 Pumping Schedule Simulated: ............................................................................................................................................................. 86 Simulation Summary: ........................................................................................................................................................................... 87 Stage 14 ................................................................................................................................................................................................... 88 Zoneset Simulated: .............................................................................................................................................................................. 88 Pumping Schedule Simulated: ............................................................................................................................................................. 92 Simulation Summary: ........................................................................................................................................................................... 93 Stage 15 ................................................................................................................................................................................................... 94 Zoneset Simulated: .............................................................................................................................................................................. 94 Pumping Schedule Simulated: ............................................................................................................................................................. 98 Simulation Summary: ......................................................................................................................................................................... 100 Attachment K: NDBI-006 Page 4 of 101 Well Description Completion Stages and Perforations Stage Perforation Top MD (ft) Perforation Bottom MD (ft) Spacing (ft) Perforation Top TVD (ft) Perforation Bottom TVD (ft) 15 12239 12245 538 4084.12 4084.15 14 12783 12789 1309 4084.45 4084.46 13 14098 14104 646 4087.84 4087.86 12 14750 14756 602 4089.21 4089.24 11 15358 15364 495 4090.65 4090.68 10 15859 15865 495 4093.29 4093.32 9 16360 16366 493 4095.66 4095.68 8 16859 16865 493 4097.9 4097.94 7 17358 17364 494 4099.49 4099.51 6 17858 17864 494 4100.14 4100.15 5 18358 18364 494 4100.73 4100.74 4 18858 18864 496 4101.93 4101.95 3 19360 19366 496 4103.12 4103.13 2 19862 19868 1170 4103.81 4103.82 1 21014 21020 0 4092.73 4092.72 Attachment K: NDBI-006 Page 5 of 101 Stage 1 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 1 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 4371.8 psi Zoneset name: ZS-1 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4002.69 10 0.74 2953.69 1461000.3 0.22 2500 Shale 4012.7 15 0.7 2794.01 1762000.5 0.22 2500 Nanushuk 3 SS 4027.69 15.3 0.68 2735.99 1898000.5 0.22 2000 Top Nan 4043.01 6 0.66 2650.13 838900.2 0.27 1000 SHALE 4049.02 2 0.71 2879.58 2665000.7 0.23 2500 DIRTY-SANDSTONE 4050.98 1.5 0.64 2601.25 819400.2 0.27 1500 DIRTY-SANDSTONE 4052.49 2 0.65 2634.76 1222000.3 0.26 1500 CLEAN-SANDSTONE 4054.49 13 0.64 2578.77 869100.2 0.27 1000 CLEAN-SANDSTONE 4067.49 1.5 0.62 2542.66 1002000.3 0.27 1000 Attachment K: NDBI-006 Page 6 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) CLEAN-SANDSTONE 4069 4 0.65 2646.21 706600.2 0.28 1000 CLEAN-SANDSTONE 4073 9 0.61 2475.07 1166000.3 0.27 1000 CLEAN-SANDSTONE 4081.99 7 0.66 2675.95 769000.2 0.27 1000 CLEAN-SANDSTONE 4089.01 5.5 0.61 2483.63 1278000.4 0.26 1000 CLEAN-SANDSTONE 4094.49 13 0.65 2682.04 691700.2 0.28 1000 DIRTY-SANDSTONE 4107.51 2.5 0.69 2835.05 1748000.4 0.26 1500 DIRTY-SANDSTONE 4110.01 12.5 0.65 2667.39 1111000.3 0.27 1500 DIRTY-SANDSTONE 4122.51 4 0.7 2907.72 1692000.4 0.26 1500 DIRTY-SANDSTONE 4126.51 2.5 0.65 2691.32 822100.2 0.27 1500 SHALE 4129 2 0.71 2932.37 2665000.7 0.23 2500 DIRTY-SANDSTONE 4131 4 0.66 2727.72 1159000.3 0.27 1500 DIRTY-SANDSTONE 4135.01 4 0.64 2643.6 838300.2 0.27 1000 SHALE 4139.01 4 0.69 2853.18 2665000.7 0.23 2500 DIRTY-SANDSTONE 4143.01 6 0.65 2699.01 1133000.3 0.27 1500 SHALE 4149.02 2 0.71 2946.44 2665000.7 0.23 2500 DIRTY-SANDSTONE 4150.98 2 0.62 2553.53 1078000.3 0.27 1500 Attachment K: NDBI-006 Page 7 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) DIRTY-SANDSTONE 4152.99 6.5 0.67 2797.2 1694000.4 0.26 1500 DIRTY-SANDSTONE 4159.51 4 0.62 2592.55 898500.2 0.27 1500 DIRTY-SANDSTONE 4163.48 3.5 0.66 2728.16 929100.3 0.27 1500 SHALE 4166.99 2 0.71 2959.2 2665000.7 0.23 2500 DIRTY-SANDSTONE 4169 12.5 0.65 2718.15 1562000.4 0.26 1500 DIRTY-SANDSTONE 4181.5 2 0.66 2764.56 1397000.4 0.26 1500 SHALE 4183.5 2 0.69 2883.06 2665000.7 0.23 2500 DIRTY-SANDSTONE 4185.5 2 0.65 2725.4 1242000.3 0.26 1500 SHALE 4187.5 8 0.71 2976.03 2665000.7 0.23 2500 DIRTY-SANDSTONE 4195.51 2 0.63 2627.07 932500.2 0.27 1500 SHALE 4197.51 4 0.71 2981.69 2665000.7 0.23 2500 DIRTY-SANDSTONE 4201.51 6 0.66 2796.04 1427000.4 0.26 1500 SHALE 4207.51 8 0.71 2990.1 2665000.7 0.23 2500 DIRTY-SANDSTONE 4215.49 6.5 0.66 2784.43 1469000.4 0.26 1500 SHALE 4222.01 6 0.71 2995.46 2665000.7 0.23 2500 DIRTY-SANDSTONE 4227.99 2 0.65 2744.55 838400.2 0.27 1000 Attachment K: NDBI-006 Page 8 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) SHALE 4229.99 2 0.69 2915.11 2665000.7 0.23 2500 DIRTY-SANDSTONE 4231.99 4 0.67 2836.79 1469000.4 0.26 1500 SHALE 4235.99 2 0.71 3008.23 2665000.7 0.23 2500 DIRTY-SANDSTONE 4237.99 6 0.68 2866.96 1545000.4 0.26 1500 SHALE 4244 12 0.69 2928.31 2665000.7 0.23 2500 DIRTY-SANDSTONE 4256 2.5 0.63 2690.6 1214000.3 0.27 1500 SHALE 4258.5 20 0.71 3026.36 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 9 of 101 Name: Stage 1 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 1 PAD 30 YF126ST 13650 325 10.83 2 1 PPA 30 YF126ST 4826.4 120 CarboLite 16/20 1 4826.4 4 3 2 PPA 30 YF126ST 5207.9 135 CarboLite 16/20 2 10415.8 4.5 4 3 PPA 30 YF126ST 5374.4 145 CarboLite 16/20 3 16123.2 4.83 5 4 PPA 30 YF126ST 5171.8 145 CarboLite 16/20 4 20687.2 4.83 6 5 PPA 30 YF126ST 4983.9 145 CarboLite 16/20 5 24919.5 4.83 7 6 PPA 30 YF126ST 4809.2 145 CarboLite 16/20 6 28855.2 4.83 8 7 PPA 30 YF126ST 4326.2 135 CarboLite 16/20 7 30283.4 4.5 9 8 PPA 30 YF126ST 3564.5 115 CarboLite 16/20 8 28516 3.83 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.29 23.05 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 51914.3 164626.7 1409.99 47 Attachment K: NDBI-006 Page 10 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 1 MD: [21014, 21020] 4371.8 191.51 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4010.4 4201.91 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 1 MD: [21014, 21020] 735.7 151.84 0.38 Attachment K: NDBI-006 Page 11 of 101 Stage 2 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 2 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 3457.7 psi Zoneset name: ZS-2 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4056.5 10 0.73 2981.11 1461000.3 0.22 1000 Shale 4066.5 15 0.7 2831.43 1762000.5 0.22 1000 Nanushuk 3 SS 4081.5 15.3 0.68 2772.4 1898000.5 0.22 1000 Top Nan CS 4096.78 19.5 0.64 2636.35 900400.2 0.27 1000 Nan SS 4116.31 2 0.69 2845.06 2665000.7 0.23 2500 Nan CS 4118.31 1.5 0.65 2693.79 1292000.4 0.26 1000 Nan CS 4119.78 4.5 0.62 2539.18 643500.2 0.28 1000 Nan DS 4124.28 3.5 0.69 2851.15 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 12 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4127.79 14.5 0.66 2733.24 1388000.3 0.26 1500 Nan CS 4142.29 1.5 0.66 2713.66 1145000.3 0.27 1000 Nan CS 4143.8 12.5 0.65 2680.88 882100.2 0.27 1000 Nan DS 4156.3 2 0.65 2698.14 1402000.4 0.26 1500 Nan CS 4158.3 9 0.61 2526.85 853600.2 0.27 1000 Nan DS 4167.29 7 0.67 2794.44 1397000.4 0.26 1500 Nan DS 4174.28 9 0.66 2745.42 1132000.3 0.27 1500 Nan DS 4183.3 3.5 0.66 2762.1 1688000.4 0.26 1500 Nan DS 4186.78 5 0.64 2672.76 757000.2 0.27 1000 Nan DS 4191.8 2 0.71 2968.49 1795000.5 0.25 1500 Nan CS 4193.8 10.5 0.63 2645.34 735600.2 0.27 1000 Nan CS 4204.3 3.5 0.64 2712.93 1098000.3 0.27 1000 Nan CS 4207.81 2 0.63 2651.58 670200.2 0.28 1000 Nan CS 4209.78 5.5 0.66 2776.02 1300000.3 0.26 1000 Nan DS 4215.29 3.5 0.71 2981.4 1531000.4 0.26 1500 Nan DS 4218.8 3.5 0.65 2739.18 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 13 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4222.28 5.5 0.7 2936.43 1416000.4 0.26 1500 Nan CS 4227.79 10.5 0.64 2700.75 1171000.3 0.27 1000 Nan DS 4238.29 1.5 0.66 2818.95 1376000.4 0.26 1500 Nan DS 4239.8 5 0.64 2710.76 1139000.3 0.27 1500 Nan DS 4244.78 2 0.67 2848.98 1560000.5 0.26 1500 Nan DS 4246.78 4 0.64 2727.72 896400.2 0.27 1500 Nan DS 4250.79 2 0.69 2916.71 1656000.4 0.26 1500 Nan DS 4252.79 10 0.63 2669.56 981000.2 0.27 1500 Nan DS 4262.8 4 0.65 2789.22 1633000.4 0.26 1500 Nan DS 4266.8 4 0.71 3018.09 1749000.4 0.26 1500 Nan DS 4270.8 9.5 0.65 2791.98 1327000.4 0.26 1500 Nan DS 4280.28 2 0.63 2688.71 781500.2 0.27 1000 Nan DS 4282.28 9.5 0.7 3018.09 1692000.4 0.26 1500 Nan DS 4291.8 2 0.66 2854.78 1365000.4 0.26 1500 Shale 4293.8 2 0.7 3010.69 2665000.7 0.23 2500 Nan DS 4295.8 2 0.64 2732.8 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 14 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4297.8 2 0.7 3013.45 2665000.7 0.23 2500 Nan DS 4299.8 4 0.66 2852.17 1287000.3 0.26 1500 Shale 4303.81 19.5 0.71 3058.27 2665000.7 0.23 2500 Nan DS 4323.29 2 0.65 2828.09 1356000.3 0.26 1500 Shale 4325.3 2 0.71 3067.4 2665000.7 0.23 2500 Nan DS 4327.3 8 0.66 2863.04 1373000.4 0.26 1500 Nan DS 4335.3 8 0.66 2881.32 1558000.4 0.26 1500 Shale 4343.31 20 0.71 3086.55 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 15 of 101 Name: Stage 2 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 2 PAD 25 YF126ST 13230 315 12.6 2 1 PPA 25 YF126ST 4022.1 100 CarboLite 16/20 1 4022.1 4 3 2 PPA 25 YF126ST 4629.2 120 CarboLite 16/20 2 9258.4 4.8 4 3 PPA 25 YF126ST 5003.7 135 CarboLite 16/20 3 15011.1 5.4 5 4 PPA 25 YF126ST 4815.1 135 CarboLite 16/20 4 19260.4 5.4 6 5 PPA 25 YF126ST 4640.3 135 CarboLite 16/20 5 23201.5 5.4 7 6 PPA 25 YF126ST 4477.8 135 CarboLite 16/20 6 26866.8 5.4 8 7 PPA 25 YF126ST 4005.5 125 CarboLite 16/20 7 28038.5 5 9 8 PPA 25 YF126ST 3409.5 110 CarboLite 16/20 8 27276 4.4 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.43 24.05 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 48233.2 152934.8 1310 52.4 Attachment K: NDBI-006 Page 16 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 2 MD: [19862, 19868] 3457.7 221.23 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4067.85 4289.08 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 2 MD: [19862, 19868] 517.57 181.33 0.3 Attachment K: NDBI-006 Page 17 of 101 Stage 3 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 3 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 3375.8 psi Zoneset name: ZS-3 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4050.79 10 0.73 2976.9 1461000.3 0.22 1000 Shale 4060.79 15 0.7 2827.51 1762000.5 0.22 1000 Nanushuk 3 SS 4075.79 15.3 0.68 2768.63 1898000.5 0.22 1000 Top Nan CS 4091.11 19.5 0.64 2632.73 900400.2 0.27 1000 Nan SS 4110.6 2 0.69 2841.14 2665000.7 0.23 2500 Nan CS 4112.6 1.5 0.65 2690.16 1292000.4 0.26 1000 Nan CS 4114.11 4.5 0.62 2535.69 643500.2 0.28 1000 Nan DS 4118.6 3.5 0.69 2847.24 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 18 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4122.11 14.5 0.66 2729.47 1388000.3 0.26 1500 Nan CS 4136.61 1.5 0.66 2710.03 1145000.3 0.27 1000 Nan CS 4138.09 12.5 0.65 2677.25 882100.2 0.27 1000 Nan DS 4150.59 2 0.65 2694.37 1402000.4 0.26 1500 Nan CS 4152.59 9 0.61 2523.37 853600.2 0.27 1000 Nan DS 4161.61 7 0.67 2790.67 1397000.4 0.26 1500 Nan DS 4168.6 9 0.66 2741.79 1132000.3 0.27 1500 Nan DS 4177.59 3.5 0.66 2758.33 1688000.4 0.26 1500 Nan DS 4181.1 5 0.64 2669.13 757000.2 0.27 1000 Nan DS 4186.09 2 0.71 2964.43 1795000.5 0.25 1500 Nan CS 4188.09 10.5 0.63 2641.86 735600.2 0.27 1000 Nan CS 4198.59 3.5 0.64 2709.16 1098000.3 0.27 1000 Nan CS 4202.1 2 0.63 2647.95 670200.2 0.28 1000 Nan CS 4204.1 5.5 0.66 2772.25 1300000.3 0.26 1000 Nan DS 4209.61 3.5 0.71 2977.48 1531000.4 0.26 1500 Nan DS 4213.09 3.5 0.65 2735.41 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 19 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4216.6 5.5 0.7 2932.52 1416000.4 0.26 1500 Nan CS 4222.11 10.5 0.64 2697.12 1171000.3 0.27 1000 Nan DS 4232.61 1.5 0.66 2815.18 1376000.4 0.26 1500 Nan DS 4234.09 5 0.64 2707.13 1139000.3 0.27 1500 Nan DS 4239.11 2 0.67 2845.06 1560000.5 0.26 1500 Nan DS 4241.11 4 0.64 2724.1 896400.2 0.27 1500 Nan DS 4245.11 2 0.69 2912.79 1656000.4 0.26 1500 Nan DS 4247.11 10 0.63 2666.08 981000.2 0.27 1500 Nan DS 4257.09 4 0.65 2785.45 1633000.4 0.26 1500 Nan DS 4261.09 4 0.71 3014.03 1749000.4 0.26 1500 Nan DS 4265.09 9.5 0.65 2788.21 1327000.4 0.26 1500 Nan DS 4274.61 2 0.63 2685.08 781500.2 0.27 1000 Nan DS 4276.61 9.5 0.7 3014.03 1692000.4 0.26 1500 Nan DS 4286.09 2 0.66 2850.86 1365000.4 0.26 1500 Shale 4288.09 2 0.7 3006.63 2665000.7 0.23 2500 Nan DS 4290.09 2 0.64 2729.18 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 20 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4292.09 2 0.7 3009.39 2665000.7 0.23 2500 Nan DS 4294.09 4 0.66 2848.25 1287000.3 0.26 1500 Shale 4298.1 19.5 0.71 3054.2 2665000.7 0.23 2500 Nan DS 4317.59 2 0.65 2824.32 1356000.3 0.26 1500 Shale 4319.59 2 0.71 3063.34 2665000.7 0.23 2500 Nan DS 4321.59 8 0.66 2859.27 1373000.4 0.26 1500 Nan DS 4329.59 8 0.66 2877.55 1558000.4 0.26 1500 Shale 4337.6 20 0.71 3082.49 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 21 of 101 Name: Stage 3 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 3 PAD 25 YF126ST 13230 315 12.6 2 1 PPA 25 YF126ST 4022.2 100 CarboLite 16/20 1 4022.2 4 3 2 PPA 25 YF126ST 4629.2 120 CarboLite 16/20 2 9258.4 4.8 4 3 PPA 25 YF126ST 5003.7 135 CarboLite 16/20 3 15011.1 5.4 5 4 PPA 25 YF126ST 4815.1 135 CarboLite 16/20 4 19260.4 5.4 6 5 PPA 25 YF126ST 4640.3 135 CarboLite 16/20 5 23201.5 5.4 7 6 PPA 25 YF126ST 4477.8 135 CarboLite 16/20 6 26866.8 5.4 8 7 PPA 25 YF126ST 4005.5 125 CarboLite 16/20 7 28038.5 5 9 8 PPA 25 YF126ST 3409.5 110 CarboLite 16/20 8 27276 4.4 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.43 24.05 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 48233.3 152934.9 1310 52.4 Attachment K: NDBI-006 Page 22 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 3 MD: [19360, 19366] 3375.8 221.36 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4062.54 4283.9 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 3 MD: [19360, 19366] 520.51 179.53 0.27 Attachment K: NDBI-006 Page 23 of 101 Stage 4 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 4 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 3965.5 psi Zoneset name: ZS-4 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4046.69 10 0.73 2974 1461000.3 0.22 1000 Shale 4056.69 15 0.7 2824.61 1762000.5 0.22 1000 Nanushuk 3 SS 4071.69 15.3 0.68 2765.87 1898000.5 0.22 1000 Top Nan CS 4087.01 19.5 0.64 2630.11 900400.2 0.27 1000 Nan SS 4106.5 2 0.69 2838.24 2665000.7 0.23 2500 Nan CS 4108.5 1.5 0.65 2687.4 1292000.4 0.26 1000 Nan CS 4110.01 4.5 0.62 2533.08 643500.2 0.28 1000 Nan DS 4114.5 3.5 0.69 2844.34 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 24 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4118.01 14.5 0.66 2726.85 1388000.3 0.26 1500 Nan CS 4132.51 1.5 0.66 2707.27 1145000.3 0.27 1000 Nan CS 4133.99 12.5 0.65 2674.64 882100.2 0.27 1000 Nan DS 4146.49 2 0.65 2691.76 1402000.4 0.26 1500 Nan CS 4148.49 9 0.61 2520.9 853600.2 0.27 1000 Nan DS 4157.51 7 0.67 2787.92 1397000.4 0.26 1500 Nan DS 4164.5 9 0.66 2739.04 1132000.3 0.27 1500 Nan DS 4173.49 3.5 0.66 2755.72 1688000.4 0.26 1500 Nan DS 4177 5 0.64 2666.52 757000.2 0.27 1000 Nan DS 4181.99 2 0.71 2961.53 1795000.5 0.25 1500 Nan CS 4183.99 10.5 0.63 2639.25 735600.2 0.27 1000 Nan CS 4194.49 3.5 0.64 2706.55 1098000.3 0.27 1000 Nan CS 4198 2 0.63 2645.34 670200.2 0.28 1000 Nan CS 4200 5.5 0.66 2769.64 1300000.3 0.26 1000 Nan DS 4205.51 3.5 0.71 2974.58 1531000.4 0.26 1500 Nan DS 4208.99 3.5 0.65 2732.8 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 25 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4212.5 5.5 0.7 2929.62 1416000.4 0.26 1500 Nan CS 4218.01 10.5 0.64 2694.51 1171000.3 0.27 1000 Nan DS 4228.51 1.5 0.66 2812.43 1376000.4 0.26 1500 Nan DS 4229.99 5 0.64 2704.52 1139000.3 0.27 1500 Nan DS 4235.01 2 0.67 2842.3 1560000.5 0.26 1500 Nan DS 4237.01 4 0.64 2721.49 896400.2 0.27 1500 Nan DS 4241.01 2 0.69 2910.04 1656000.4 0.26 1500 Nan DS 4243.01 10 0.63 2663.47 981000.2 0.27 1500 Nan DS 4252.99 4 0.65 2782.69 1633000.4 0.26 1500 Nan DS 4256.99 4 0.71 3011.13 1749000.4 0.26 1500 Nan DS 4260.99 9.5 0.65 2785.59 1327000.4 0.26 1500 Nan DS 4270.51 2 0.63 2682.47 781500.2 0.27 1000 Nan DS 4272.51 9.5 0.7 3011.13 1692000.4 0.26 1500 Nan DS 4281.99 2 0.66 2848.25 1365000.4 0.26 1500 Shale 4283.99 2 0.7 3003.73 2665000.7 0.23 2500 Nan DS 4285.99 2 0.64 2726.56 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 26 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4287.99 2 0.7 3006.63 2665000.7 0.23 2500 Nan DS 4289.99 4 0.66 2845.64 1287000.3 0.26 1500 Shale 4294 19.5 0.71 3051.3 2665000.7 0.23 2500 Nan DS 4313.48 2 0.65 2821.71 1356000.3 0.26 1500 Shale 4315.49 2 0.71 3060.44 2665000.7 0.23 2500 Nan DS 4317.49 8 0.66 2856.52 1373000.4 0.26 1500 Nan DS 4325.49 8 0.66 2874.79 1558000.4 0.26 1500 Shale 4333.5 20 0.71 3079.59 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 27 of 101 Name: Stage 4 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 STAGE 4 PAD 30 YF126ST 14700 350 11.67 2 1 PPA 30 YF126ST 4825.7 119.98 CarboLite 16/20 1 4825.7 4 3 2 PPA 30 YF126ST 5207.7 135 CarboLite 16/20 2 10415.4 4.5 4 3 PPA 30 YF126ST 5559.6 150 CarboLite 16/20 3 16678.8 5 5 4 PPA 30 YF126ST 5350.1 150 CarboLite 16/20 4 21400.4 5 6 5 PPA 30 YF126ST 5155.8 150 CarboLite 16/20 5 25779 5 7 6 PPA 30 YF126ST 4975.3 150 CarboLite 16/20 6 29851.8 5 8 7 PPA 30 YF126ST 4486.2 140 CarboLite 16/20 7 31403.4 4.67 9 8 PPA 30 YF126ST 3874.4 125 CarboLite 16/20 8 30995.2 4.17 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.15 23.81 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 54134.8 171349.7 1469.97 49 Attachment K: NDBI-006 Page 28 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 4 MD: [18858, 18864] 3965.5 225.39 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4056.56 4281.95 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 4 MD: [18858, 18864] 572.86 181.05 0.32 Attachment K: NDBI-006 Page 29 of 101 Stage 5 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 5 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5498.1 psi Zoneset name: ZS-5 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4042.81 10 0.73 2971.1 1461000.3 0.22 1000 Shale 4052.79 15 0.7 2821.85 1762000.5 0.22 1000 Nanushuk 3 SS 4067.81 15.3 0.68 2763.11 1898000.5 0.22 1000 Top Nan CS 4083.1 19.5 0.64 2627.65 900400.2 0.27 1000 Nan SS 4102.59 2 0.69 2835.63 2665000.7 0.23 2500 Nan CS 4104.59 1.5 0.65 2684.94 1292000.4 0.26 1000 Nan CS 4106.1 4.5 0.62 2530.76 643500.2 0.28 1000 Attachment K: NDBI-006 Page 30 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4110.6 3.5 0.69 2841.58 1774000.4 0.26 1500 Nan DS 4114.11 14.5 0.66 2724.24 1388000.3 0.26 1500 Nan CS 4128.61 1.5 0.66 2704.66 1145000.3 0.27 1000 Nan CS 4130.09 12.5 0.65 2672.03 882100.2 0.27 1000 Nan DS 4142.59 2 0.65 2689.14 1402000.4 0.26 1500 Nan CS 4144.59 9 0.61 2518.44 853600.2 0.27 1000 Nan DS 4153.61 7 0.67 2785.3 1397000.4 0.26 1500 Nan DS 4160.6 9 0.66 2736.43 1132000.3 0.27 1500 Nan DS 4169.59 3.5 0.66 2753.11 1688000.4 0.26 1500 Nan DS 4173.1 5 0.64 2664.05 757000.2 0.27 1000 Nan DS 4178.08 2 0.71 2958.77 1795000.5 0.25 1500 Nan CS 4180.09 10.5 0.63 2636.79 735600.2 0.27 1000 Nan CS 4190.58 3.5 0.64 2704.08 1098000.3 0.27 1000 Nan CS 4194.09 2 0.63 2642.88 670200.2 0.28 1000 Nan CS 4196.1 5.5 0.66 2767.03 1300000.3 0.26 1000 Nan DS 4201.61 3.5 0.71 2971.82 1531000.4 0.26 1500 Attachment K: NDBI-006 Page 31 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4205.09 3.5 0.65 2730.19 1193000.3 0.27 1500 Nan DS 4208.6 5.5 0.7 2926.86 1416000.4 0.26 1500 Nan CS 4214.11 10.5 0.64 2691.9 1171000.3 0.27 1000 Nan DS 4224.61 1.5 0.66 2809.82 1376000.4 0.26 1500 Nan DS 4226.12 5 0.64 2702.05 1139000.3 0.27 1500 Nan DS 4231.1 2 0.67 2839.69 1560000.5 0.26 1500 Nan DS 4233.1 4 0.64 2718.88 896400.2 0.27 1500 Nan DS 4237.11 2 0.69 2907.28 1656000.4 0.26 1500 Nan DS 4239.11 10 0.63 2661.01 981000.2 0.27 1500 Nan DS 4249.11 4 0.65 2780.23 1633000.4 0.26 1500 Nan DS 4253.08 4 0.71 3008.37 1749000.4 0.26 1500 Nan DS 4257.09 9.5 0.65 2782.98 1327000.4 0.26 1500 Nan DS 4266.6 2 0.63 2680.01 781500.2 0.27 1000 Nan DS 4268.6 9.5 0.7 3008.37 1692000.4 0.26 1500 Nan DS 4278.08 2 0.66 2845.64 1365000.4 0.26 1500 Shale 4280.09 2 0.7 3000.98 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 32 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4282.09 2 0.64 2724.1 1088000.3 0.27 1500 Shale 4284.09 2 0.7 3003.88 2665000.7 0.23 2500 Nan DS 4286.09 4 0.66 2843.03 1287000.3 0.26 1500 Shale 4290.09 19.5 0.71 3048.55 2665000.7 0.23 2500 Nan DS 4309.61 2 0.65 2819.1 1356000.3 0.26 1500 Shale 4311.61 2 0.71 3057.69 2665000.7 0.23 2500 Nan DS 4313.62 8 0.66 2853.91 1373000.4 0.26 1500 Nan DS 4321.59 8 0.66 2872.18 1558000.4 0.26 1500 Shale 4329.59 20 0.71 3076.83 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 33 of 101 Name: Stage 5 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 STAGE 5 PAD 40 YF126ST 15750 375 9.38 2 1 PPA 40 YF126ST 5027.5 125 CarboLite 16/20 1 5027.5 3.12 3 2 PPA 40 YF126ST 5400.5 140 CarboLite 16/20 2 10801 3.5 4 3 PPA 40 YF126ST 6300.9 170 CarboLite 16/20 3 18902.7 4.25 5 4 PPA 40 YF126ST 6063.6 170 CarboLite 16/20 4 24254.4 4.25 6 5 PPA 40 YF126ST 5843.3 170 CarboLite 16/20 5 29216.5 4.25 7 6 PPA 40 YF126ST 5638.5 170 CarboLite 16/20 6 33831 4.25 8 7 PPA 40 YF126ST 4486.2 140 CarboLite 16/20 7 31403.4 3.5 9 8 PPA 40 YF126ST 3874.5 125 CarboLite 16/20 8 30996 3.13 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.98 23.66 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 58385 184432.5 1584.98 39.62 Attachment K: NDBI-006 Page 34 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 5 MD: [18358, 18364] 5498.1 232.84 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4051.01 4283.85 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 5 MD: [18358, 18364] 635.29 196.11 0.34 Attachment K: NDBI-006 Page 35 of 101 Stage 6 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 6 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5385.1 psi Zoneset name: ZS-6 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4040.81 10 0.73 2969.65 1461000.3 0.22 1000 Shale 4050.79 15 0.7 2820.55 1762000.5 0.22 1000 Nanushuk 3 SS 4065.81 15.3 0.68 2761.81 1898000.5 0.22 1000 Top Nan CS 4081.1 19.5 0.64 2626.34 900400.2 0.27 1000 Nan SS 4100.59 2 0.69 2834.18 2665000.7 0.23 2500 Nan CS 4102.59 1.5 0.65 2683.63 1292000.4 0.26 1000 Nan CS 4104.1 4.5 0.62 2529.46 643500.2 0.28 1000 Nan DS 4108.6 3.5 0.69 2840.27 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 36 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4112.11 14.5 0.66 2722.94 1388000.3 0.26 1500 Nan CS 4126.61 1.5 0.66 2703.36 1145000.3 0.27 1000 Nan CS 4128.08 12.5 0.65 2670.72 882100.2 0.27 1000 Nan DS 4140.58 2 0.65 2687.84 1402000.4 0.26 1500 Nan CS 4142.59 9 0.61 2517.27 853600.2 0.27 1000 Nan DS 4151.61 7 0.67 2783.85 1397000.4 0.26 1500 Nan DS 4158.6 9 0.66 2735.12 1132000.3 0.27 1500 Nan DS 4167.59 3.5 0.66 2751.8 1688000.4 0.26 1500 Nan DS 4171.1 5 0.64 2662.75 757000.2 0.27 1000 Nan DS 4176.12 2 0.71 2957.32 1795000.5 0.25 1500 Nan CS 4178.08 10.5 0.63 2635.48 735600.2 0.27 1000 Nan CS 4188.62 3.5 0.64 2702.78 1098000.3 0.27 1000 Nan CS 4192.09 2 0.63 2641.72 670200.2 0.28 1000 Nan CS 4194.09 5.5 0.66 2765.72 1300000.3 0.26 1000 Nan DS 4199.61 3.5 0.71 2970.37 1531000.4 0.26 1500 Nan DS 4203.08 3.5 0.65 2728.89 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 37 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4206.59 5.5 0.7 2925.56 1416000.4 0.26 1500 Nan CS 4212.11 10.5 0.64 2690.74 1171000.3 0.27 1000 Nan DS 4222.6 1.5 0.66 2808.51 1376000.4 0.26 1500 Nan DS 4224.11 5 0.64 2700.75 1139000.3 0.27 1500 Nan DS 4229.1 2 0.67 2838.39 1560000.5 0.26 1500 Nan DS 4231.1 4 0.64 2717.72 896400.2 0.27 1500 Nan DS 4235.1 2 0.69 2905.98 1656000.4 0.26 1500 Nan DS 4237.11 10 0.63 2659.85 981000.2 0.27 1500 Nan DS 4247.11 4 0.65 2778.92 1633000.4 0.26 1500 Nan DS 4251.12 4 0.71 3006.92 1749000.4 0.26 1500 Nan DS 4255.09 9.5 0.65 2781.68 1327000.4 0.26 1500 Nan DS 4264.6 2 0.63 2678.85 781500.2 0.27 1000 Nan DS 4266.6 9.5 0.7 3007.07 1692000.4 0.26 1500 Nan DS 4276.12 2 0.66 2844.34 1365000.4 0.26 1500 Shale 4278.08 2 0.7 2999.67 2665000.7 0.23 2500 Nan DS 4280.09 2 0.64 2722.79 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 38 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4282.09 2 0.7 3002.43 2665000.7 0.23 2500 Nan DS 4284.09 4 0.66 2841.72 1287000.3 0.26 1500 Shale 4288.09 19.5 0.71 3047.24 2665000.7 0.23 2500 Nan DS 4307.61 2 0.65 2817.79 1356000.3 0.26 1500 Shale 4309.61 2 0.71 3056.24 2665000.7 0.23 2500 Nan DS 4311.61 8 0.66 2852.6 1373000.4 0.26 1500 Nan DS 4319.59 8 0.66 2870.88 1558000.4 0.26 1500 Shale 4327.59 20 0.71 3075.38 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 39 of 101 Name: Stage 6 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 6 PAD 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 6033.2 150 CarboLite 16/20 1 6033.2 3.75 3 2 PPA 40 YF126ST 6750.8 175 CarboLite 16/20 2 13501.6 4.38 4 3 PPA 40 YF126ST 7413 200 CarboLite 16/20 3 22239 5 5 4 PPA 40 YF126ST 7133.6 200 CarboLite 16/20 4 28534.4 5 6 5 PPA 40 YF126ST 6874.5 200 CarboLite 16/20 5 34372.5 5 7 6 PPA 40 YF126ST 6633.6 200 CarboLite 16/20 6 39801.6 5 8 7 PPA 40 YF126ST 5447.6 170 CarboLite 16/20 7 38133.2 4.25 9 8 PPA 40 YF126ST 4184.4 135 CarboLite 16/20 8 33475.2 3.38 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 24.97 21.86 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 67270.7 216090.7 1830 45.75 Attachment K: NDBI-006 Page 40 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 6 MD: [17858, 17864] 5385.1 233.86 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4048.8 4282.66 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 6 MD: [17858, 17864] 649.58 198.24 0.34 Attachment K: NDBI-006 Page 41 of 101 Stage 7 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 7 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5261.7 psi Zoneset name: ZS-7 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4037.8 10 0.73 2967.47 1461000.3 0.22 1000 Shale 4047.8 15 0.7 2818.37 1762000.5 0.22 1000 Nanushuk 3 SS 4062.8 15.3 0.68 2759.78 1898000.5 0.22 1000 Top Nan CS 4078.08 19.5 0.64 2624.46 900400.2 0.27 1000 Nan SS 4097.6 2 0.69 2832.15 2665000.7 0.23 2500 Nan CS 4099.61 1.5 0.65 2681.6 1292000.4 0.26 1000 Nan CS 4101.12 4.5 0.62 2527.72 643500.2 0.28 1000 Nan DS 4105.61 3.5 0.69 2838.24 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 42 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4109.09 14.5 0.66 2720.91 1388000.3 0.26 1500 Nan CS 4123.59 1.5 0.66 2701.47 1145000.3 0.27 1000 Nan CS 4125.1 12.5 0.65 2668.84 882100.2 0.27 1000 Nan DS 4137.6 2 0.65 2685.95 1402000.4 0.26 1500 Nan CS 4139.6 9 0.61 2515.53 853600.2 0.27 1000 Nan DS 4148.59 7 0.67 2781.97 1397000.4 0.26 1500 Nan DS 4155.61 9 0.66 2733.24 1132000.3 0.27 1500 Nan DS 4164.6 3.5 0.66 2749.77 1688000.4 0.26 1500 Nan DS 4168.11 5 0.64 2660.86 757000.2 0.27 1000 Nan DS 4173.1 2 0.71 2955.29 1795000.5 0.25 1500 Nan CS 4175.1 10.5 0.63 2633.6 735600.2 0.27 1000 Nan CS 4185.6 3.5 0.64 2700.89 1098000.3 0.27 1000 Nan CS 4189.11 2 0.63 2639.83 670200.2 0.28 1000 Nan CS 4191.11 5.5 0.66 2763.69 1300000.3 0.26 1000 Nan DS 4196.59 3.5 0.71 2968.2 1531000.4 0.26 1500 Nan DS 4200.1 3.5 0.65 2727 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 43 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4203.61 5.5 0.7 2923.38 1416000.4 0.26 1500 Nan CS 4209.09 10.5 0.64 2688.71 1171000.3 0.27 1000 Nan DS 4219.59 1.5 0.66 2806.48 1376000.4 0.26 1500 Nan DS 4221.1 5 0.64 2698.86 1139000.3 0.27 1500 Nan DS 4226.12 2 0.67 2836.36 1560000.5 0.26 1500 Nan DS 4228.08 4 0.64 2715.69 896400.2 0.27 1500 Nan DS 4232.09 2 0.69 2903.95 1656000.4 0.26 1500 Nan DS 4234.09 10 0.63 2657.96 981000.2 0.27 1500 Nan DS 4244.09 4 0.65 2776.89 1633000.4 0.26 1500 Nan DS 4248.1 4 0.71 3004.89 1749000.4 0.26 1500 Nan DS 4252.1 9.5 0.65 2779.79 1327000.4 0.26 1500 Nan DS 4261.61 2 0.63 2676.96 781500.2 0.27 1000 Nan DS 4263.62 9.5 0.7 3004.89 1692000.4 0.26 1500 Nan DS 4273.1 2 0.66 2842.3 1365000.4 0.26 1500 Shale 4275.1 2 0.7 2997.49 2665000.7 0.23 2500 Nan DS 4277.1 2 0.64 2720.91 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 44 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4279.1 2 0.7 3000.4 2665000.7 0.23 2500 Nan DS 4281.1 4 0.66 2839.69 1287000.3 0.26 1500 Shale 4285.1 19.5 0.71 3045.07 2665000.7 0.23 2500 Nan DS 4304.59 2 0.65 2815.91 1356000.3 0.26 1500 Shale 4306.59 2 0.71 3054.06 2665000.7 0.23 2500 Nan DS 4308.6 8 0.66 2850.57 1373000.4 0.26 1500 Nan DS 4316.6 8 0.66 2868.85 1558000.4 0.26 1500 Shale 4324.61 20 0.71 3073.2 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 45 of 101 Name: Stage 7 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 7 PAD 40 YF126ST 15750 375 9.38 2 1 PPA 40 YF126ST 5027.5 125 CarboLite 16/20 1 5027.5 3.12 3 2 PPA 40 YF126ST 5400.5 140 CarboLite 16/20 2 10801 3.5 4 3 PPA 40 YF126ST 6300.9 170 CarboLite 16/20 3 18902.7 4.25 5 4 PPA 40 YF126ST 6063.6 170 CarboLite 16/20 4 24254.4 4.25 6 5 PPA 40 YF126ST 5843.3 170 CarboLite 16/20 5 29216.5 4.25 7 6 PPA 40 YF126ST 5638.5 170 CarboLite 16/20 6 33831 4.25 8 7 PPA 40 YF126ST 4486.2 140 CarboLite 16/20 7 31403.4 3.5 9 8 PPA 40 YF126ST 3874.5 125 CarboLite 16/20 8 30996 3.13 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.98 23.66 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 58385 184432.5 1584.98 39.62 Attachment K: NDBI-006 Page 46 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 7 MD: [17358, 17364] 5261.7 260.29 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4037.25 4297.54 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 7 MD: [17358, 17364] 566.89 226.9 0.31 Attachment K: NDBI-006 Page 47 of 101 Stage 8 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 8 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5544.8 psi Zoneset name: ZS-8 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4032.81 10 0.73 2963.7 1461000.3 0.22 1000 Shale 4042.81 15 0.7 2815.04 1762000.5 0.22 1000 Nanushuk 3 SS 4057.81 15.3 0.68 2756.44 1898000.5 0.22 1000 Top Nan CS 4073.1 19.5 0.64 2621.12 900400.2 0.27 1000 Nan SS 4092.59 2 0.69 2828.67 2665000.7 0.23 2500 Nan CS 4094.59 1.5 0.65 2678.41 1292000.4 0.26 1000 Nan CS 4096.1 4.5 0.62 2524.53 643500.2 0.28 1000 Nan DS 4100.59 3.5 0.69 2834.76 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 48 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4104.1 14.5 0.66 2717.57 1388000.3 0.26 1500 Nan CS 4118.6 1.5 0.66 2698.14 1145000.3 0.27 1000 Nan CS 4120.11 12.5 0.65 2665.65 882100.2 0.27 1000 Nan DS 4132.61 2 0.65 2682.76 1402000.4 0.26 1500 Nan CS 4134.61 9 0.61 2512.49 853600.2 0.27 1000 Nan DS 4143.6 7 0.67 2778.49 1397000.4 0.26 1500 Nan DS 4150.59 9 0.66 2729.9 1132000.3 0.27 1500 Nan DS 4159.61 3.5 0.66 2746.43 1688000.4 0.26 1500 Nan DS 4163.09 5 0.64 2657.67 757000.2 0.27 1000 Nan DS 4168.11 2 0.71 2951.66 1795000.5 0.25 1500 Nan CS 4170.11 10.5 0.63 2630.55 735600.2 0.27 1000 Nan CS 4180.61 3.5 0.64 2697.56 1098000.3 0.27 1000 Nan CS 4184.09 2 0.63 2636.64 670200.2 0.28 1000 Nan CS 4186.09 5.5 0.66 2760.5 1300000.3 0.26 1000 Nan DS 4191.6 3.5 0.71 2964.72 1531000.4 0.26 1500 Nan DS 4195.11 3.5 0.65 2723.81 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 49 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4198.59 5.5 0.7 2919.9 1416000.4 0.26 1500 Nan CS 4204.1 10.5 0.64 2685.52 1171000.3 0.27 1000 Nan DS 4214.6 1.5 0.66 2803.14 1376000.4 0.26 1500 Nan DS 4216.11 5 0.64 2695.67 1139000.3 0.27 1500 Nan DS 4221.1 2 0.67 2833.02 1560000.5 0.26 1500 Nan DS 4223.1 4 0.64 2712.5 896400.2 0.27 1500 Nan DS 4227.1 2 0.69 2900.46 1656000.4 0.26 1500 Nan DS 4229.1 10 0.63 2654.77 981000.2 0.27 1500 Nan DS 4239.11 4 0.65 2773.7 1633000.4 0.26 1500 Nan DS 4243.11 4 0.71 3001.27 1749000.4 0.26 1500 Nan DS 4247.11 9.5 0.65 2776.46 1327000.4 0.26 1500 Nan DS 4256.59 2 0.63 2673.77 781500.2 0.27 1000 Nan DS 4258.6 9.5 0.7 3001.41 1692000.4 0.26 1500 Nan DS 4268.11 2 0.66 2838.97 1365000.4 0.26 1500 Shale 4270.11 2 0.7 2994.01 2665000.7 0.23 2500 Nan DS 4272.11 2 0.64 2717.72 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 50 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4274.11 2 0.7 2996.91 2665000.7 0.23 2500 Nan DS 4276.12 4 0.66 2836.36 1287000.3 0.26 1500 Shale 4280.09 19.5 0.71 3041.44 2665000.7 0.23 2500 Nan DS 4299.61 2 0.65 2812.57 1356000.3 0.26 1500 Shale 4301.61 2 0.71 3050.58 2665000.7 0.23 2500 Nan DS 4303.61 8 0.66 2847.38 1373000.4 0.26 1500 Nan DS 4311.61 8 0.66 2865.51 1558000.4 0.26 1500 Shale 4319.59 20 0.71 3069.72 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 51 of 101 Name: Stage 8 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 8 PAD 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 8044.5 200 CarboLite 16/20 1 8044.5 5 3 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 2 17359.2 5.63 4 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 4 39234.8 6.87 5 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 6 51742.2 6.5 6 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 8 59510.4 6 7 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 25.76 22.22 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 65213.3 234071.1 1800 45 Attachment K: NDBI-006 Page 52 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 8 MD: [16859, 16865] 5544.8 232.52 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4040.79 4273.31 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 8 MD: [16859, 16865] 675.58 194.61 0.38 Attachment K: NDBI-006 Page 53 of 101 Stage 9 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 9 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5468.8 psi Zoneset name: ZS-9 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4029.79 10 0.73 2961.53 1461000.3 0.22 1000 Shale 4039.8 15 0.7 2812.86 1762000.5 0.22 1000 Nanushuk 3 SS 4054.79 15.3 0.68 2754.41 1898000.5 0.22 1000 Top Nan CS 4070.11 19.5 0.64 2619.24 900400.2 0.27 1000 Nan SS 4089.6 2 0.69 2826.64 2665000.7 0.23 2500 Nan CS 4091.6 1.5 0.65 2676.38 1292000.4 0.26 1000 Nan CS 4093.11 4.5 0.62 2522.79 643500.2 0.28 1000 Nan DS 4097.6 3.5 0.69 2832.59 1774000.4 0.26 1500 Nan DS 4101.12 14.5 0.66 2715.69 1388000.3 0.26 1500 Attachment K: NDBI-006 Page 54 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4115.58 1.5 0.66 2696.25 1145000.3 0.27 1000 Nan CS 4117.09 12.5 0.65 2663.62 882100.2 0.27 1000 Nan DS 4129.59 2 0.65 2680.73 1402000.4 0.26 1500 Nan CS 4131.59 9 0.61 2510.6 853600.2 0.27 1000 Nan DS 4140.58 7 0.67 2776.6 1397000.4 0.26 1500 Nan DS 4147.6 9 0.66 2727.87 1132000.3 0.27 1500 Nan DS 4156.59 3.5 0.66 2744.55 1688000.4 0.26 1500 Nan DS 4160.1 5 0.64 2655.79 757000.2 0.27 1000 Nan DS 4165.09 2 0.71 2949.63 1795000.5 0.25 1500 Nan CS 4167.09 10.5 0.63 2628.52 735600.2 0.27 1000 Nan CS 4177.59 3.5 0.64 2695.67 1098000.3 0.27 1000 Nan CS 4181.1 2 0.63 2634.76 670200.2 0.28 1000 Nan CS 4183.1 5.5 0.66 2758.47 1300000.3 0.26 1000 Nan DS 4188.62 3.5 0.71 2962.54 1531000.4 0.26 1500 Nan DS 4192.09 3.5 0.65 2721.78 1193000.3 0.27 1500 Nan DS 4195.6 5.5 0.7 2917.87 1416000.4 0.26 1500 Attachment K: NDBI-006 Page 55 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan CS 4201.12 10.5 0.64 2683.63 1171000.3 0.27 1000 Nan DS 4211.61 1.5 0.66 2801.26 1376000.4 0.26 1500 Nan DS 4213.09 5 0.64 2693.79 1139000.3 0.27 1500 Nan DS 4218.11 2 0.67 2830.99 1560000.5 0.26 1500 Nan DS 4220.11 4 0.64 2710.61 896400.2 0.27 1500 Nan DS 4224.11 2 0.69 2898.43 1656000.4 0.26 1500 Nan DS 4226.12 10 0.63 2652.89 981000.2 0.27 1500 Nan DS 4236.09 4 0.65 2771.67 1633000.4 0.26 1500 Nan DS 4240.09 4 0.71 2999.09 1749000.4 0.26 1500 Nan DS 4244.09 9.5 0.65 2774.57 1327000.4 0.26 1500 Nan DS 4253.61 2 0.63 2671.89 781500.2 0.27 1000 Nan DS 4255.61 9.5 0.7 2999.24 1692000.4 0.26 1500 Nan DS 4265.09 2 0.66 2836.94 1365000.4 0.26 1500 Shale 4267.09 2 0.7 2991.98 2665000.7 0.23 2500 Nan DS 4269.09 2 0.64 2715.83 1088000.3 0.27 1500 Shale 4271.1 2 0.7 2994.74 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 56 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4273.1 4 0.66 2834.33 1287000.3 0.26 1500 Shale 4277.1 19.5 0.71 3039.41 2665000.7 0.23 2500 Nan DS 4296.59 2 0.65 2810.69 1356000.3 0.26 1500 Shale 4298.59 2 0.71 3048.4 2665000.7 0.23 2500 Nan DS 4300.59 8 0.66 2845.35 1373000.4 0.26 1500 Nan DS 4308.6 8 0.66 2863.63 1558000.4 0.26 1500 Shale 4316.6 20 0.71 3067.55 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 57 of 101 Name: Stage 9 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 9 PAD 40 YF126ST 10500 250 6.25 2 1 PPA Scour 40 YF126ST 2414.8 60 CarboLite 40/70 1 2414.8 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120 CarboLite 40/70 3 13372.5 3 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8044.5 200 CarboLite 16/20 1 8044.5 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 28.68 24.66 Attachment K: NDBI-006 Page 58 of 101 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 67885.6 249858.4 1880.01 47 Attachment K: NDBI-006 Page 59 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 9 MD: [16360, 16366] 5468.8 223.76 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4040.61 4264.37 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 9 MD: [16360, 16366] 542.3 180.33 0.59 Attachment K: NDBI-006 Page 60 of 101 Stage 10 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 10 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5256.3 psi Zoneset name: ZS-10 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4025.79 10 0.73 2958.62 1461000.3 0.22 1000 Shale 4035.79 15 0.7 2810.11 1762000.5 0.22 1000 Nanushuk 3 SS 4050.79 15.3 0.68 2751.66 1898000.5 0.22 1000 Top Nan CS 4066.11 19.5 0.64 2616.63 900400.2 0.27 1000 Nan SS 4085.6 2 0.69 2823.88 2665000.7 0.23 2500 Nan CS 4087.6 1.5 0.65 2673.77 1292000.4 0.26 1000 Nan CS 4089.11 4.5 0.62 2520.32 643500.2 0.28 1000 Nan DS 4093.6 3.5 0.69 2829.83 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 61 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4097.11 14.5 0.66 2712.93 1388000.3 0.26 1500 Nan CS 4111.61 1.5 0.66 2693.64 1145000.3 0.27 1000 Nan CS 4113.09 12.5 0.65 2661.15 882100.2 0.27 1000 Nan DS 4125.59 2 0.65 2678.12 1402000.4 0.26 1500 Nan CS 4127.59 9 0.61 2508.14 853600.2 0.27 1000 Nan DS 4136.61 7 0.67 2773.85 1397000.4 0.26 1500 Nan DS 4143.6 9 0.66 2725.26 1132000.3 0.27 1500 Nan DS 4152.59 3.5 0.66 2741.94 1688000.4 0.26 1500 Nan DS 4156.1 5 0.64 2653.18 757000.2 0.27 1000 Nan DS 4161.09 2 0.71 2946.73 1795000.5 0.25 1500 Nan CS 4163.09 10.5 0.63 2626.05 735600.2 0.27 1000 Nan CS 4173.59 3.5 0.64 2693.06 1098000.3 0.27 1000 Nan CS 4177.1 2 0.63 2632.14 670200.2 0.28 1000 Nan CS 4179.1 5.5 0.66 2755.86 1300000.3 0.26 1000 Nan DS 4184.61 3.5 0.71 2959.79 1531000.4 0.26 1500 Nan DS 4188.09 3.5 0.65 2719.17 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 62 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4191.6 5.5 0.7 2915.11 1416000.4 0.26 1500 Nan CS 4197.11 10.5 0.64 2681.17 1171000.3 0.27 1000 Nan DS 4207.61 1.5 0.66 2798.5 1376000.4 0.26 1500 Nan DS 4209.09 5 0.64 2691.18 1139000.3 0.27 1500 Nan DS 4214.11 2 0.67 2828.38 1560000.5 0.26 1500 Nan DS 4216.11 4 0.64 2708 896400.2 0.27 1500 Nan DS 4220.11 2 0.69 2895.68 1656000.4 0.26 1500 Nan DS 4222.11 10 0.63 2650.42 981000.2 0.27 1500 Nan DS 4232.09 4 0.65 2769.06 1633000.4 0.26 1500 Nan DS 4236.09 4 0.71 2996.33 1749000.4 0.26 1500 Nan DS 4240.09 9.5 0.65 2771.82 1327000.4 0.26 1500 Nan DS 4249.61 2 0.63 2669.42 781500.2 0.27 1000 Nan DS 4251.61 9.5 0.7 2996.48 1692000.4 0.26 1500 Nan DS 4261.09 2 0.66 2834.33 1365000.4 0.26 1500 Shale 4263.09 2 0.7 2989.08 2665000.7 0.23 2500 Nan DS 4265.09 2 0.64 2713.22 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 63 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4267.09 2 0.7 2991.98 2665000.7 0.23 2500 Nan DS 4269.09 4 0.66 2831.72 1287000.3 0.26 1500 Shale 4273.1 19.5 0.71 3036.51 2665000.7 0.23 2500 Nan DS 4292.59 2 0.65 2808.08 1356000.3 0.26 1500 Shale 4294.59 2 0.71 3045.5 2665000.7 0.23 2500 Nan DS 4296.59 8 0.66 2842.74 1373000.4 0.26 1500 Nan DS 4304.59 8 0.66 2860.87 1558000.4 0.26 1500 Shale 4312.6 20 0.71 3064.79 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 64 of 101 Name: Stage 10 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 10 PAD 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 7642.2 190 CarboLite 16/20 1 7642.2 4.75 3 3 PPA 40 YF126ST 7969 215 CarboLite 16/20 3 23907 5.37 4 5 PPA 40 YF126ST 8249.6 240 CarboLite 16/20 5 41248 6 5 7 PPA 40 YF126ST 7690.8 240 CarboLite 16/20 7 53835.6 6 6 9 PPA 40 YF126ST 6602.8 220 CarboLite 16/20 9 59425.2 5.5 7 10 PPA 40 YF126ST 5236.2 180 CarboLite 16/20 10 52362 4.5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.91 23.74 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 60190.6 238420 1685.01 42.13 Attachment K: NDBI-006 Page 65 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 10 MD: [15859, 15865] 5256.3 232.87 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4033.78 4266.65 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 10 MD: [15859, 15865] 657.57 196.82 0.36 Attachment K: NDBI-006 Page 66 of 101 Stage 11 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 11 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 5105.3 psi Zoneset name: ZS-11 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4020.8 10 0.73 2955 1461000.3 0.22 1000 Shale 4030.81 15 0.7 2806.63 1762000.5 0.22 1000 Nanushuk 3 SS 4045.8 15.3 0.68 2748.18 1898000.5 0.22 1000 Top Nan CS 4061.09 19.5 0.64 2613.43 900400.2 0.27 1000 Nan SS 4080.61 2 0.69 2820.4 2665000.7 0.23 2500 Nan CS 4082.61 1.5 0.65 2670.58 1292000.4 0.26 1000 Nan CS 4084.09 4.5 0.62 2517.13 643500.2 0.28 1000 Nan DS 4088.62 3.5 0.69 2826.5 1774000.4 0.26 1500 Attachment K: NDBI-006 Page 67 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4092.09 14.5 0.66 2709.6 1388000.3 0.26 1500 Nan CS 4106.59 1.5 0.66 2690.3 1145000.3 0.27 1000 Nan CS 4108.1 12.5 0.65 2657.82 882100.2 0.27 1000 Nan DS 4120.6 2 0.65 2674.93 1402000.4 0.26 1500 Nan CS 4122.6 9 0.61 2505.09 853600.2 0.27 1000 Nan DS 4131.59 7 0.67 2770.51 1397000.4 0.26 1500 Nan DS 4138.62 9 0.66 2722.07 1132000.3 0.27 1500 Nan DS 4147.6 3.5 0.66 2738.6 1688000.4 0.26 1500 Nan DS 4151.12 5 0.64 2649.98 757000.2 0.27 1000 Nan DS 4156.1 2 0.71 2943.25 1795000.5 0.25 1500 Nan CS 4158.1 10.5 0.63 2622.86 735600.2 0.27 1000 Nan CS 4168.6 3.5 0.64 2689.87 1098000.3 0.27 1000 Nan CS 4172.11 2 0.63 2629.1 670200.2 0.28 1000 Nan CS 4174.11 5.5 0.66 2752.53 1300000.3 0.26 1000 Nan DS 4179.59 3.5 0.71 2956.16 1531000.4 0.26 1500 Nan DS 4183.1 3.5 0.65 2715.98 1193000.3 0.27 1500 Attachment K: NDBI-006 Page 68 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4186.61 5.5 0.7 2911.63 1416000.4 0.26 1500 Nan CS 4192.09 10.5 0.64 2677.98 1171000.3 0.27 1000 Nan DS 4202.59 1.5 0.66 2795.17 1376000.4 0.26 1500 Nan DS 4204.1 5 0.64 2687.98 1139000.3 0.27 1500 Nan DS 4209.09 2 0.67 2824.9 1560000.5 0.26 1500 Nan DS 4211.09 4 0.64 2704.81 896400.2 0.27 1500 Nan DS 4215.09 2 0.69 2892.2 1656000.4 0.26 1500 Nan DS 4217.09 10 0.63 2647.23 981000.2 0.27 1500 Nan DS 4227.1 4 0.65 2765.87 1633000.4 0.26 1500 Nan DS 4231.1 4 0.71 2992.85 1749000.4 0.26 1500 Nan DS 4235.1 9.5 0.65 2768.63 1327000.4 0.26 1500 Nan DS 4244.59 2 0.63 2666.23 781500.2 0.27 1000 Nan DS 4246.59 9.5 0.7 2993 1692000.4 0.26 1500 Nan DS 4256.1 2 0.66 2830.99 1365000.4 0.26 1500 Shale 4258.1 2 0.7 2985.6 2665000.7 0.23 2500 Nan DS 4260.1 2 0.64 2710.03 1088000.3 0.27 1500 Attachment K: NDBI-006 Page 69 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 4262.11 2 0.7 2988.5 2665000.7 0.23 2500 Nan DS 4264.11 4 0.66 2828.38 1287000.3 0.26 1500 Shale 4268.11 19.5 0.71 3033.03 2665000.7 0.23 2500 Nan DS 4287.6 2 0.65 2804.74 1356000.3 0.26 1500 Shale 4289.6 2 0.71 3042.02 2665000.7 0.23 2500 Nan DS 4291.6 8 0.66 2839.4 1373000.4 0.26 1500 Nan DS 4299.61 8 0.66 2857.53 1558000.4 0.26 1500 Shale 4307.61 20 0.71 3061.17 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 70 of 101 Name: Stage 11 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 11 PAD 40 YF126ST 10500 250 6.25 2 1 PPA Scour 40 YF126ST 2414.8 60 CarboLite 40/70 1 2414.8 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120 CarboLite 40/70 3 13372.5 3 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8044.5 200 CarboLite 16/20 1 8044.5 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 28.68 24.66 Attachment K: NDBI-006 Page 71 of 101 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 67885.6 249858.4 1880.01 47 Attachment K: NDBI-006 Page 72 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 11 MD: [15358, 15364] 5105.3 267.02 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4016.73 4283.75 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 11 MD: [15358, 15364] 614.67 242.22 0.35 Attachment K: NDBI-006 Page 73 of 101 Stage 12 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 12 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 4461.1 psi Zoneset name: ZS-12 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 3998.2 10 0.71 2854.34 1461000.3 0.22 1000 Shale 4008.2 15 0.7 2790.96 1762000.5 0.22 1000 Siltstone 4023.2 15.3 0.68 2732.95 1898000.5 0.22 1000 Top Nan CS 4038.48 17.5 0.62 2525.54 818100.2 0.27 1000 Nan DS 4056 2 0.6 2434.17 784600.2 0.27 1000 Nan DS 4058.01 5.5 0.63 2554.26 1248000.4 0.26 1500 SHALE 4063.48 3.5 0.69 2813.15 2665000.7 0.23 2500 Nan DS 4066.99 1.5 0.64 2587.04 1102000.3 0.27 1500 Attachment K: NDBI-006 Page 74 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4068.5 2 0.64 2584.14 913900.3 0.27 1500 Nan CS 4070.51 1.5 0.61 2487.54 669900.2 0.28 1000 Nan CS 4072.01 2 0.64 2610.82 1249000.4 0.26 1000 Nan CS 4074.02 1.5 0.6 2444.9 771600.2 0.27 1000 SHALE 4075.49 2 0.69 2820.98 2665000.7 0.23 2500 Nan CS 4077.49 4.5 0.61 2484.5 873800.2 0.27 1000 Nan DS 4081.99 7 0.66 2675.95 1417000.3 0.26 1500 Nan DS 4089.01 2.5 0.61 2495.08 757700.2 0.27 1000 Nan DS 4091.5 2 0.68 2787.05 1692000.4 0.26 1500 Nan DS 4093.5 5 0.61 2506.69 997700.3 0.27 1500 Nan CS 4098.49 4.5 0.64 2640.85 1120000.3 0.27 1000 Nan CS 4102.99 9.5 0.61 2505.67 778000.2 0.27 1000 Nan DS 4112.5 2.5 0.64 2640.99 1685000.4 0.26 1500 Nan DS 4114.99 12 0.62 2563.25 964800.3 0.27 1500 Nan DS 4127 2.5 0.66 2708.14 1469000.4 0.26 1500 Nan DS 4129.49 9.5 0.63 2621.12 1297000.4 0.26 1500 Attachment K: NDBI-006 Page 75 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4139.01 2 0.65 2674.5 1444000.4 0.26 1500 Nan DS 4141.01 41 0.63 2609.23 1021000.3 0.27 1500 Nan DS 4181.99 1.5 0.62 2610.1 862400.2 0.27 1000 Nan CS 4183.5 6 0.62 2608.21 764700.2 0.28 1000 Nan DS 4189.5 6 0.67 2804.74 1242000.3 0.26 1500 Nan DS 4195.51 4 0.69 2896.26 1692000.4 0.26 1500 Nan DS 4199.51 2 0.64 2700.89 1009000.2 0.27 1500 Nan DS 4201.51 2 0.69 2887.12 1692000.4 0.26 1500 Nan DS 4203.51 2 0.63 2661.44 1134000.3 0.27 1500 Nan DS 4205.51 5.5 0.69 2899.45 1692000.4 0.26 1500 Nan DS 4210.99 4 0.62 2633.16 949900.2 0.27 1000 Nan DS 4214.99 2 0.68 2866.82 1692000.4 0.26 1500 Nan DS 4216.99 12 0.63 2656.22 919900.3 0.27 1000 Nan DS 4229 4 0.68 2898.29 1428000.4 0.26 1500 Nan DS 4233.01 4 0.64 2689.29 1474000.5 0.26 1500 SHALE 4237.01 2 0.68 2894.52 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 76 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4239.01 1.5 0.64 2721.92 1373000.4 0.26 1500 SHALE 4240.49 8 0.69 2924.4 2665000.7 0.23 2500 Nan DS 4248.49 8 0.62 2649.26 1127000.3 0.27 1500 Nan DS 4256.5 1.5 0.64 2703.36 1424000.3 0.26 1500 SHALE 4258.01 2 0.69 2934.4 2665000.7 0.23 2500 Nan DS 4260.01 4 0.64 2714.96 1282000.3 0.26 1500 SHALE 4264.01 2 0.68 2912.94 2665000.7 0.23 2500 Nan DS 4266.01 6 0.63 2680.88 1072000.3 0.27 1500 SHALE 4272.01 20 0.68 2924.54 2665000.7 0.23 2500 Zone Transmissibility Properties Zone Name Top TVD (ft) Zone Height (ft) Permeability (mD) Porosity (%) Reservoir Pressure (psi) Shale 3998.2 10 0 1 1913 Shale 4008.2 15 0 1 1918 Siltstone 4023.2 15.3 0 10 1925 Top Nan CS 4038.48 17.5 39.47 24.9 1932 Nan DS 4056 2 113.24 25.3 1940 Attachment K: NDBI-006 Page 77 of 101 Zone Transmissibility Properties Zone Name Top TVD (ft) Zone Height (ft) Permeability (mD) Porosity (%) Reservoir Pressure (psi) Nan DS 4058.01 5.5 22.02 19.7 1941 SHALE 4063.48 3.5 0 1 1944 Nan DS 4066.99 1.5 21.67 21.3 1945 Nan DS 4068.5 2 159.89 23.6 1946 Nan CS 4070.51 1.5 110.14 27 1947 Nan CS 4072.01 2 2.87 19.7 1948 Nan CS 4074.02 1.5 94.75 25.5 1949 SHALE 4075.49 2 0 1 1949 Nan CS 4077.49 4.5 44.13 24.1 1950 Nan DS 4081.99 7 4.28 17.9 1952 Nan DS 4089.01 2.5 91.63 25.7 1956 Nan DS 4091.5 2 0.02 15 1957 Nan DS 4093.5 5 31.6 22.6 1958 Nan CS 4098.49 4.5 3.11 21.1 1960 Nan CS 4102.99 9.5 131.71 25.4 1962 Nan DS 4112.5 2.5 1 15.1 1967 Attachment K: NDBI-006 Page 78 of 101 Zone Transmissibility Properties Zone Name Top TVD (ft) Zone Height (ft) Permeability (mD) Porosity (%) Reservoir Pressure (psi) Nan DS 4114.99 12 104.14 23 1968 Nan DS 4127 2.5 2.35 17.3 1974 Nan DS 4129.49 9.5 31.76 19.2 1975 Nan DS 4139.01 2 3.79 17.6 1979 Nan DS 4141.01 41 72.28 22.4 1980 Nan DS 4181.99 1.5 68.11 24.3 1999 Nan CS 4183.5 6 156.15 26.2 2000 Nan DS 4189.5 6 40.96 19.9 2003 Nan DS 4195.51 4 0.02 15 2006 Nan DS 4199.51 2 17.85 22.4 2008 Nan DS 4201.51 2 0.01 15 2009 Nan DS 4203.51 2 22.09 21 2010 Nan DS 4205.51 5.5 0.02 15 2011 Nan DS 4210.99 4 63.42 23.1 2013 Nan DS 4214.99 2 0.02 15 2015 Nan DS 4216.99 12 74.62 23.5 2016 Attachment K: NDBI-006 Page 79 of 101 Zone Transmissibility Properties Zone Name Top TVD (ft) Zone Height (ft) Permeability (mD) Porosity (%) Reservoir Pressure (psi) Nan DS 4229 4 11.77 17.8 2022 Nan DS 4233.01 4 2.49 17.3 2023 SHALE 4237.01 2 0 1 2025 Nan DS 4239.01 1.5 3.22 18.4 2026 SHALE 4240.49 8 0 1 2027 Nan DS 4248.49 8 65.69 21.2 2031 Nan DS 4256.5 1.5 4.8 17.8 2035 SHALE 4258.01 2 0 1 2035 Nan DS 4260.01 4 11.98 19.3 2036 SHALE 4264.01 2 0 1 2038 Nan DS 4266.01 6 60.61 22.1 2039 SHALE 4272.01 20 0 1 2042 Attachment K: NDBI-006 Page 80 of 101 Name: Stage 12 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 12 PAD 40 YF126ST 18900 450 11.25 2 1 PPA 40 YF126ST 7038.8 175 CarboLite 16/20 1 7038.8 4.38 3 2 PPA 40 YF126ST 7329.4 190 CarboLite 16/20 2 14658.8 4.75 4 3 PPA 40 YF126ST 7783.7 210 CarboLite 16/20 3 23351.1 5.25 5 4 PPA 40 YF126ST 7490.3 210 CarboLite 16/20 4 29961.2 5.25 6 5 PPA 40 YF126ST 7218.3 210 CarboLite 16/20 5 36091.5 5.25 7 6 PPA 40 YF126ST 6965.3 210 CarboLite 16/20 6 41791.8 5.25 8 7 PPA 40 YF126ST 5447.6 170 CarboLite 16/20 7 38133.2 4.25 9 8 PPA 40 YF126ST 4809 155 CarboLite 16/20 8 38472 3.88 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 25.9 22.73 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 72982.4 229498.4 1980 49.5 Attachment K: NDBI-006 Page 81 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 12 MD: [14750, 14756] 4461.1 235.91 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4010.79 4246.7 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 12 MD: [14750, 14756] 735.05 192.25 0.36 Attachment K: NDBI-006 Page 82 of 101 Stage 13 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 13 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 4637 psi Zoneset name: ZS-13 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 3997.21 10 0.71 2853.62 1461000.3 0.22 1000 Shale 4007.19 15 0.7 2790.24 1762000.5 0.22 1000 Siltstone 4022.21 15.3 0.68 2732.22 1898000.5 0.22 1000 Top Nan CS 4037.5 17.5 0.62 2524.82 818100.2 0.27 1000 Nan DS 4054.99 2 0.6 2433.59 784600.2 0.27 1000 Nan DS 4056.99 5.5 0.63 2553.53 1248000.4 0.26 1500 SHALE 4062.5 3.5 0.69 2812.43 2665000.7 0.23 2500 Nan DS 4066.01 1.5 0.64 2586.46 1102000.3 0.27 1500 Attachment K: NDBI-006 Page 83 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4067.49 2 0.64 2583.56 913900.3 0.27 1500 Nan CS 4069.49 1.5 0.61 2486.96 669900.2 0.28 1000 Nan CS 4071 2 0.64 2610.1 1249000.4 0.26 1000 Nan CS 4073 1.5 0.6 2444.32 771600.2 0.27 1000 SHALE 4074.51 2 0.69 2820.26 2665000.7 0.23 2500 Nan CS 4076.51 4.5 0.61 2483.92 873800.2 0.27 1000 Nan DS 4081 7 0.66 2675.37 1417000.3 0.26 1500 Nan DS 4087.99 2.5 0.61 2494.5 757700.2 0.27 1000 Nan DS 4090.49 2 0.68 2786.32 1692000.4 0.26 1500 Nan DS 4092.49 5 0.61 2506.11 997700.3 0.27 1500 Nan CS 4097.51 4.5 0.64 2640.27 1120000.3 0.27 1000 Nan CS 4102 9.5 0.61 2505.09 778000.2 0.27 1000 Nan DS 4111.52 2.5 0.64 2640.41 1685000.4 0.26 1500 Nan DS 4114.01 12 0.62 2562.67 964800.3 0.27 1500 Nan DS 4125.98 2.5 0.66 2707.42 1469000.4 0.26 1500 Nan DS 4128.51 9.5 0.63 2620.54 1297000.4 0.26 1500 Attachment K: NDBI-006 Page 84 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4137.99 2 0.65 2673.77 1444000.4 0.26 1500 Nan DS 4139.99 41 0.63 2608.65 1021000.3 0.27 1500 Nan DS 4181 1.5 0.62 2609.37 862400.2 0.27 1000 Nan CS 4182.51 6 0.62 2607.63 764700.2 0.28 1000 Nan DS 4188.48 6 0.67 2804.16 1242000.3 0.26 1500 Nan DS 4194.49 4 0.69 2895.53 1692000.4 0.26 1500 Nan DS 4198.49 2 0.64 2700.31 1009000.2 0.27 1500 Nan DS 4200.49 2 0.69 2886.4 1692000.4 0.26 1500 Nan DS 4202.49 2 0.63 2660.86 1134000.3 0.27 1500 Nan DS 4204.49 5.5 0.69 2898.72 1692000.4 0.26 1500 Nan DS 4210.01 4 0.62 2632.43 949900.2 0.27 1000 Nan DS 4214.01 2 0.68 2866.24 1692000.4 0.26 1500 Nan DS 4216.01 12 0.63 2655.64 919900.3 0.27 1000 Nan DS 4227.99 4 0.68 2897.56 1428000.4 0.26 1500 Nan DS 4231.99 4 0.64 2688.56 1474000.5 0.26 1500 SHALE 4235.99 2 0.68 2893.79 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 85 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4237.99 1.5 0.64 2721.34 1373000.4 0.26 1500 SHALE 4239.5 8 0.69 2923.82 2665000.7 0.23 2500 Nan DS 4247.51 8 0.62 2648.68 1127000.3 0.27 1500 Nan DS 4255.51 1.5 0.64 2702.78 1424000.3 0.26 1500 SHALE 4256.99 2 0.69 2933.82 2665000.7 0.23 2500 Nan DS 4258.99 4 0.64 2714.24 1282000.3 0.26 1500 SHALE 4262.99 2 0.68 2912.36 2665000.7 0.23 2500 Nan DS 4264.99 6 0.63 2680.3 1072000.3 0.27 1500 SHALE 4271 20 0.68 2923.96 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 86 of 101 Name: Stage 13 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 13 PAD 40 YF126ST 15750 375 9.38 2 1 PPA 40 YF126ST 7642.1 190 CarboLite 16/20 1 7642.1 4.75 3 3 PPA 40 YF126ST 7969 215 CarboLite 16/20 3 23907 5.37 4 5 PPA 40 YF126ST 8249.6 240 CarboLite 16/20 5 41248 6 5 7 PPA 40 YF126ST 7690.8 240 CarboLite 16/20 7 53835.6 6 6 9 PPA 40 YF126ST 6602.8 220 CarboLite 16/20 9 59425.2 5.5 7 10 PPA 40 YF126ST 5236.2 180 CarboLite 16/20 10 52362 4.5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.63 22.59 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 59140.5 238419.9 1660.01 41.5 Attachment K: NDBI-006 Page 87 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Bottomhole Pressure (psi) Max Height (ft) Stage 13 MD: [14098, 14104] 4637 243.76 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4005 4248.76 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 13 MD: [14098, 14104] 668.58 218.41 0.31 Attachment K: NDBI-006 Page 88 of 101 Stage 14 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 14 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 3903.3 psi Zoneset name: ZS-14 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 3994.19 10 0.71 2851.44 1461000.3 0.22 1000 Shale 4004.2 15 0.7 2788.06 1762000.5 0.22 1000 Siltstone 4019.19 15.3 0.68 2730.19 1898000.5 0.22 1000 Top Nan CS 4034.51 17.5 0.62 2522.93 818100.2 0.27 1000 Nan DS 4052 2 0.6 2431.85 784600.2 0.27 1000 Nan DS 4054 5.5 0.63 2551.65 1248000.4 0.26 1500 SHALE 4059.51 3.5 0.69 2810.4 2665000.7 0.23 2500 Nan DS 4062.99 1.5 0.64 2584.57 1102000.3 0.27 1500 Attachment K: NDBI-006 Page 89 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4064.5 2 0.64 2581.53 913900.3 0.27 1500 Nan CS 4066.5 1.5 0.61 2485.08 669900.2 0.28 1000 Nan CS 4068.01 2 0.64 2608.21 1249000.4 0.26 1000 Nan CS 4070.01 1.5 0.6 2442.44 771600.2 0.27 1000 SHALE 4071.49 2 0.69 2818.23 2665000.7 0.23 2500 Nan CS 4073.49 4.5 0.61 2482.18 873800.2 0.27 1000 Nan DS 4077.99 7 0.66 2673.34 1417000.3 0.26 1500 Nan DS 4085.01 2.5 0.61 2492.62 757700.2 0.27 1000 Nan DS 4087.5 2 0.68 2784.29 1692000.4 0.26 1500 Nan DS 4089.5 5 0.61 2504.37 997700.3 0.27 1500 Nan CS 4094.49 4.5 0.64 2638.24 1120000.3 0.27 1000 Nan CS 4099.02 9.5 0.61 2503.35 778000.2 0.27 1000 Nan DS 4108.5 2.5 0.64 2638.53 1685000.4 0.26 1500 Nan DS 4110.99 12 0.62 2560.79 964800.3 0.27 1500 Nan DS 4123 2.5 0.66 2705.53 1469000.4 0.26 1500 Nan DS 4125.49 9.5 0.63 2618.51 1297000.4 0.26 1500 Attachment K: NDBI-006 Page 90 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4135.01 2 0.65 2671.89 1444000.4 0.26 1500 Nan DS 4137.01 41 0.63 2606.76 1021000.3 0.27 1500 Nan DS 4177.99 1.5 0.62 2607.49 862400.2 0.27 1000 Nan CS 4179.49 6 0.62 2605.75 764700.2 0.28 1000 Nan DS 4185.5 6 0.67 2802.13 1242000.3 0.26 1500 Nan DS 4191.5 4 0.69 2893.5 1692000.4 0.26 1500 Nan DS 4195.51 2 0.64 2698.28 1009000.2 0.27 1500 Nan DS 4197.51 2 0.69 2884.37 1692000.4 0.26 1500 Nan DS 4199.51 2 0.63 2658.98 1134000.3 0.27 1500 Nan DS 4201.51 5.5 0.69 2896.69 1692000.4 0.26 1500 Nan DS 4206.99 4 0.62 2630.55 949900.2 0.27 1000 Nan DS 4210.99 2 0.68 2864.21 1692000.4 0.26 1500 Nan DS 4212.99 12 0.63 2653.76 919900.3 0.27 1000 Nan DS 4225 4 0.68 2895.53 1428000.4 0.26 1500 Nan DS 4229 4 0.64 2686.68 1474000.5 0.26 1500 SHALE 4233.01 2 0.68 2891.76 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 91 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4235.01 1.5 0.64 2719.31 1373000.4 0.26 1500 SHALE 4236.52 8 0.69 2921.64 2665000.7 0.23 2500 Nan DS 4244.49 8 0.62 2646.79 1127000.3 0.27 1500 Nan DS 4252.49 1.5 0.64 2700.75 1424000.3 0.26 1500 SHALE 4254 2 0.69 2931.65 2665000.7 0.23 2500 Nan DS 4256 4 0.64 2712.35 1282000.3 0.26 1500 SHALE 4260.01 2 0.68 2910.33 2665000.7 0.23 2500 Nan DS 4262.01 6 0.63 2678.41 1072000.3 0.27 1500 SHALE 4268.01 20 0.68 2921.93 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 92 of 101 Name: Stage 14 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 14 PAD 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 6033.2 150 CarboLite 16/20 1 6033.2 3.75 3 2 PPA 40 YF126ST 6750.8 175 CarboLite 16/20 2 13501.6 4.38 4 3 PPA 40 YF126ST 7413 200 CarboLite 16/20 3 22239 5 5 4 PPA 40 YF126ST 7133.6 200 CarboLite 16/20 4 28534.4 5 6 5 PPA 40 YF126ST 6874.5 200 CarboLite 16/20 5 34372.5 5 7 6 PPA 40 YF126ST 6633.6 200 CarboLite 16/20 6 39801.6 5 8 7 PPA 40 YF126ST 5447.6 170 CarboLite 16/20 7 38133.2 4.25 9 8 PPA 40 YF126ST 4184.4 135 CarboLite 16/20 8 33475.2 3.38 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 24.97 21.86 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 67270.7 216090.7 1830 45.75 Attachment K: NDBI-006 Page 93 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 14 MD: [12783, 12789] 3903.3 242.39 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4003 4245.39 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 14 MD: [12783, 12789] 684.97 211.34 0.28 Attachment K: NDBI-006 Page 94 of 101 Stage 15 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 15 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 18000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 4086.7 psi Zoneset name: ZS-15 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Shale 3993.7 10 0.71 2851.01 1461000.3 0.22 1000 Shale 4003.71 15 0.7 2787.77 1762000.5 0.22 1000 Siltstone 4018.7 15.3 0.68 2729.9 1898000.5 0.22 1000 Top Nan CS 4033.99 17.5 0.62 2522.64 818100.2 0.27 1000 Nan DS 4051.51 2 0.6 2431.56 784600.2 0.27 1000 Nan DS 4053.51 5.5 0.63 2551.36 1248000.4 0.26 1500 SHALE 4058.99 3.5 0.69 2810.11 2665000.7 0.23 2500 Nan DS 4062.5 1.5 0.64 2584.28 1102000.3 0.27 1500 Attachment K: NDBI-006 Page 95 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4064.01 2 0.64 2581.24 913900.3 0.27 1500 Nan CS 4066.01 1.5 0.61 2484.79 669900.2 0.28 1000 Nan CS 4067.49 2 0.64 2607.92 1249000.4 0.26 1000 Nan CS 4069.49 1.5 0.6 2442.15 771600.2 0.27 1000 SHALE 4071 2 0.69 2817.79 2665000.7 0.23 2500 Nan CS 4073 4.5 0.61 2481.89 873800.2 0.27 1000 Nan DS 4077.49 7 0.66 2673.05 1417000.3 0.26 1500 Nan DS 4084.51 2.5 0.61 2492.33 757700.2 0.27 1000 Nan DS 4087.01 2 0.68 2784 1692000.4 0.26 1500 Nan DS 4089.01 5 0.61 2503.93 997700.3 0.27 1500 Nan CS 4094 4.5 0.64 2637.95 1120000.3 0.27 1000 Nan CS 4098.49 9.5 0.61 2502.92 778000.2 0.27 1000 Nan DS 4108.01 2.5 0.64 2638.09 1685000.4 0.26 1500 Nan DS 4110.5 12 0.62 2560.5 964800.3 0.27 1500 Nan DS 4122.51 2.5 0.66 2705.24 1469000.4 0.26 1500 Nan DS 4125 9.5 0.63 2618.22 1297000.4 0.26 1500 Attachment K: NDBI-006 Page 96 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4134.51 2 0.65 2671.6 1444000.4 0.26 1500 Nan DS 4136.52 41 0.63 2606.47 1021000.3 0.27 1500 Nan DS 4177.49 1.5 0.62 2607.2 862400.2 0.27 1000 Nan CS 4179 6 0.62 2605.46 764700.2 0.28 1000 Nan DS 4185.01 6 0.67 2801.84 1242000.3 0.26 1500 Nan DS 4191.01 4 0.69 2893.21 1692000.4 0.26 1500 Nan DS 4195.01 2 0.64 2697.99 1009000.2 0.27 1500 Nan DS 4197.01 2 0.69 2884.08 1692000.4 0.26 1500 Nan DS 4199.02 2 0.63 2658.54 1134000.3 0.27 1500 Nan DS 4200.98 5.5 0.69 2896.4 1692000.4 0.26 1500 Nan DS 4206.5 4 0.62 2630.26 949900.2 0.27 1000 Nan DS 4210.5 2 0.68 2863.77 1692000.4 0.26 1500 Nan DS 4212.5 12 0.63 2653.47 919900.3 0.27 1000 Nan DS 4224.51 4 0.68 2895.1 1428000.4 0.26 1500 Nan DS 4228.51 4 0.64 2686.39 1474000.5 0.26 1500 SHALE 4232.51 2 0.68 2891.47 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 97 of 101 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4234.51 1.5 0.64 2719.02 1373000.4 0.26 1500 SHALE 4235.99 8 0.69 2921.35 2665000.7 0.23 2500 Nan DS 4244 8 0.62 2646.5 1127000.3 0.27 1500 Nan DS 4252 1.5 0.64 2700.46 1424000.3 0.26 1500 SHALE 4253.51 2 0.69 2931.36 2665000.7 0.23 2500 Nan DS 4255.51 4 0.64 2712.06 1282000.3 0.26 1500 SHALE 4259.51 2 0.68 2909.89 2665000.7 0.23 2500 Nan DS 4261.52 6 0.63 2678.12 1072000.3 0.27 1500 SHALE 4267.49 20 0.68 2921.5 2665000.7 0.23 2500 Attachment K: NDBI-006 Page 98 of 101 Name: Stage 15 Pumping Steps Step # Step Name Pump Rate (bbl/min) Fluid Name CFLD Vol (gal) Slurry Volume (bbl) Prop Name Prop Conc (PPA) Prop Mass (lbm) Pump Time (min) 1 Stage 15 PAD 40 YF126ST 8400 200 5 2 1 PPA Scour 40 YF126ST 2414.8 60 CarboLite 40/70 1 2414.8 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120 CarboLite 40/70 3 13372.5 3 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8044.2 200 CarboLite 16/20 1 8044.2 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.41 22.6 Attachment K: NDBI-006 Page 99 of 101 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 65785.3 249858.1 1830 45.75 Attachment K: NDBI-006 Page 100 of 101 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 15 MD: [12239, 12245] 4086.7 243.52 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4003 4246.52 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length (ft) Height (ft) Avg Wellbore Width (in) Stage 15 MD: [12239, 12245] 711.45 218.83 0.33 Attachment K: NDBI-006 Page 101 of 101 Material Totals Fluids Fluid Volume (BBL) Proppants Proppant Mass (lbm) YF126ST WF126 22510 1000 CarboLite 40/70 CarboLite 16/20 47370 3085506 Totals Total Fluid Volume (BBL) Total Proppant Mass (lbm) Total Pump Time (h) 23510 3132876 13.87 Variance Request NDBi-006 Well PTD 225-101 API 50-103-20926-00-00 Proposed Variance Request 20 AAC 25.283. Hydraulic fracturing. (l) Upon written request of the operator, the commission may modify a deadline in this section upon a showing of good cause, approve a variance from any other requirement of this section if the variance provides at least an equally effective means of complying with the requirement, or approve a waiver of a requirement of this section if the waiver will not promote waste, is based on sound engineering and geoscience principles, will not jeopardize the ultimate recovery of hydrocarbons, will not jeopardize correlative rights, and will not result in an increased risk to health, safety, or the environment, including freshwater. (a)(6)(B) an assessment of each casing and cementing operation performed to construct or repair the well; the assessment must include sufficient supporting information, including cement evaluation logs and other evaluation logs approved by the commission, to demonstrate that (A) casing is cemented (i) below the base of the lowermost freshwater aquifer; and (ii) in accordance with 20 AAC 25.030; and (B) each hydrocarbon zone penetrated by the well is isolated; Oil Search Alaska, LLC (OSA) hereby submits a request for a Variance to allow the fracture stimulation and operation of the Pikka development injector well NDBi-006. The 9-5/8 liner was run and cemented as per the sundry conditions outlined in Sundry 325-703. Losses were encountered while cementing the liner on all 3 stages of the cement job. For the first and second stage cement jobs (Nanushuk isolation), this resulted in the top of cement ~849 MD (~169 TVD) below the top of the Nanushuk pool, with hydrocarbon bearing formations exposed in the NT4-NT8. OSA presents the evidence below to demonstrate that the well can still be safely fracture stimulated, operated, and ultimately abandoned in compliance with AOGCC regulations. 1. Well Design and Geology: 9-5/8 Liner Top at 2,720 MD 13-3/8 Shoe at 2,883 MD TS790 at 5253, MD 1st CFLEX Stage Tool at 5,305 MD Top of Nanushuk at 10,334 MD Top of hydrocarbon in the Nanushuk in the NT8 based on relevant offsets 2nd CFLEX Stage Tool at 10,349 MD (Note 2nd CFLEX was run to give best possible chance for cement isolation given the losses associated with fault at 11,600) Fault crossing at 11,600 with significant losses 9-5/8 Shoe at 11,824 MD See Attachment 1 for schematic. 2. Cement Job Planning / Execution: 9-5/8 Intermediate Liner: 1st Stage 1st stage of the cement job planned with 15.3 ppg tail slurry at 30% excess, targeting TOC 10,950 MD (~25 MD above NT6). Due to losses encountered with a fault crossing at ~11,600 MD, the goal of this job was to attempt to cover the loss zone in preparation for the 2nd stage job. During execution of the 1st stage cement, nearly full losses were encountered throughout the job. An estimated 70 bbls (of 70 bbls cement pumped) was lost after cement exited the shoe. However, some lift pressure was observed, indicating the cement did move up the annulus toward the loss zone. Good/hard cement was encountered in the shoe track and rathole. After drilling out the 9- 5/8 shoe a LOT was conducted to 13.63 ppg. 2nd Stage 2nd Stage of cement job planned with CFLEX at 10,349 MD at the Top Nanushuk formation (~15 MD below Top Nan). Also planned with a full 15.3 ppg tail slurry at 30% excess, targeting TOC 200 TVD above the Top Nanushuk (~9335 MD), for a job volume of ~74 bbls. After opening the lower CFLEX, severe losses were still encountered, so the decision was made to pump all extra cement on location (total of 172 bbls 15.3ppg tail). During execution of the 2nd stage cement, minimal returns were noted, but some lift pressure was observed. An estimated 162 bbls (of 172 bbls cement pumped) was lost after cement exited the lower CFLEX tool. 3rd Stage 3rd Stage of cement job planned with CFLEX ~52 below the TS790. Also planned with a full 15.3 ppg tail slurry at 100% excess, targeting TOC at the 9-5/8 liner top. During execution of the 3rd stage cement, no losses were encountered during mud conditioning or pumping cement (288 bbls 15.3ppg tail). While displacing cement with OBM, complete losses were encountered after pumping 39 bbls of the 111bbls displacement. Lift pressure was observed prior to losing full returns. After the CFLEX was closed and the LTP set, fluids were circulated off the top of the liner,dumped ~160 bbls of spacer with trace cement and 452 bbls of contaminated interface. An estimated 72 bbls (of 288 bbls cement pumped) was lost after cement exited the upper CFLEX tool. 3. Observations / Conclusions: 9-5/8 Intermediate Liner: 1 st and 2nd stage cement jobs Baker TOC log indicated no cement from top Nanushuk (10,334 MD) to 11,225 MD. 11,225 11450 MD contained intervals of partial bond, and the log indicated top of good cement was at 11,490 MD. The Halliburton wireline CAST-M log indicates little cement from top Nanushuk (10,334 MD) to 11,183 MD. TOC from the CAST-M log is observed at 11,183 MD. From 11,183 MD to 11,798 MD the CAST-M showsfair to good cement bonding with a section from 11,458MD to 11,798MD with good cement bonding. Cement isolation was achieved across the 9-5/8 shoe and a LOT was of 13.63 ppg was achieved after drilling out the 9-5/8 casing. The upper Nanushuk formations across the hydrocarbon-bearing formations (NT5 through NT8) have not been fully covered by cement based on the measured TOC at 11,183 MD(15MD / 3 TVD below top of NT5). 9-5/8 Intermediate Liner: 3rd stage cement job Baker TOC log indicates cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation with many intervals of partial cement bond. Intervals of partial cement bond are above, across, and below the Tuluvak Hydrocarbon bearing formation. The Halliburton wireline CAST-M log shows improved results with fair to good bonding above the TS790 as well as a section of good bonding from 5,548-5,603 MD (295-350 MD below TS790). Based on the top of cement, assessed at 11,183 MD from thewireline CAST-M log, the 9-5/8 shoe isolates the NT3.2 reservoir from the formations above (641 MD / 133 TVD of cement). The logged top of cement is above the NT3 MFS shale which is considered the first and primary NT3 containment interval for frac stimulation of the NT3.2 reservoir. This is supported by fracture stimulation modelling and appraisal well logging of radioactive proppants used in frac stimulation. There are also no other wells within a quarter mile of the NDBi-006 well (refer attachment 4). There are no known permeable zones between the Nanushuk and the TS790 formations. Above the TS790, formations are isolated with the 3rd stage cement job and V0 rated 9-5/8 x 13-3/8 liner top packer. While it is acknowledged that due to losses associated with the fault crossing near TD the top of the Nanushuk pool has not been cemented as per the approved PTD and Sundry, our assessment is that we have adequate isolation to prevent crossflow of the Nanushuk to any shallower permeable formations, as well as adequate isolation across the 9-5/8 shoe for frac operations. Future P&A Considerations: During the final permanent abandonment of NDBi-006, the well will be P&Ad in accordance with AOGCC requirements in 20AAC 25.112 Well Plugging Requirements and OSAsTechnical Standards. The current well conditions retain the ability during the P&A to ensure that all hydrocarbons are confined to their respective strata and are prevented from migrating into other strata or to the surface. A full P&A can be achieved in various ways to comply with regulations. A potential P&A strategy is shown in the schematic that is included in Attachment 1 . 5. Attachments: Attached are the following documents in support of the variance application: 1. As-drilled Schematic 2. As-drilled well path 3. As-drilled formation tops 4. NDBi-006 location map and area of injection review 5. Baker LWD Sonic TOC Log 6. Baker LWD Sonic TOC Log Interpretation 7. Halliburton CAST-M Log 8. Halliburton CAST-M Log Interpretation 9. Intermediate Casing Cement Report 10. NT4-8 Correlation across NDB 11. NDB-011 Potential Plug & Abandonment Schematic Conclusions: Significant losses were observed when drilling across the fault at ~11,600 MD in the 12-1/4 hole. This fault had been penetrated in previous wells with no losses observed. The well design was modified to include a third stage cement job and the volume of cement for the second stage job was increased based on observed hole conditions. Top of cement was logged with wireline logs at 11,183 MD (15 MD / 3 TVD below top of NT5). Logs indicate sufficient cement around the 9-5/8 shoe for isolation duringfacture stimulation(641 MD / 133 TVD of cement). Top of cement is logged above NT3 MFS which is considered to the confining layer for fracture stimulation. The permanent P&A of the well will isolate and prevent hydrocarbon migration into other strata and be in accordance with the AOGCC requirements in 20 AAC 25.112 Well Plugging Requirements and OSAs Technical Standards. Considering the evidence presented above, OSA requests a Variance to allow fracture stimulation and operation of the Pikka development injection well NDBi-006. Attachment 1 As drilled Schematic Tuluvak Sand @ 3256' MD Top Nan 3.2 @11,785' MD NDBi-006 Well Schematic 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2720' MD 13-3/8" 68 ppf L-80 Surface Casing2883' MD 9-5/8", 47ppf L-80 Production Liner 11,824' MD 4-½, 12.6ppf P-110S Production Liner21,132' MD 4-½ Liner Hanger/ Top Packer11,652' MD GL RKB Bottom Flange 5th Dec. 2025 9-5/8" Tieback2720' MD 9-5/8" Cflex Stage Tool (50' MD below TS790) 5305' MD 8-½ Openhole TD21,149' MD Fault 20,532'/20612' MD Fault ~11,600' MD 9-5/8" Cflex Stage Tool (Placed @ Top Nan FM.)10349' MD 9-5/8" Primary TOC~11,183' MD Fault ~7,450' MD (no direct losses noted) Fault 14,790' MDFault 13370'/13440' MD Top of Nan 10,334' MD Attachment 3 As-drilled Formation Tops 22.83 69.83 FT NDBi-006 Formation Tops and Markers MD TVD RKB TVD SS Upper Schrader Bluff 1,060 1,047 -977 Base Permafrost Transition 1,436 1,403 -1,333 Middle Schrader Bluff 1,862 1,769 -1,699 MCU 2,390 2,139 -2,069 Tuluvak Shale 3,049 2,446 -2,376 Tuluvak Sand 3,256 2,507 -2,438 TS_790 5,253 2,823 -2,753 Seabee 7,962 3,263 -3,193 Nanushuk 10,334 3,740 -3,670 NT8 MFS 10,621 3,796 -3,727 NT7 MFS 10,808 3,834 -3,764 NT6 MFS 10,975 3,867 -3,797 NT5 MFS 11,168 3,906 -3,836 NT4 MFS 11,422 3,958 -3,888 NT3 MFS 11,664 4,009 -3,939 NT3.2 Top Reservoir 11,785 4,034 -3,964 Santos Landing Ring (GL): RKB: Units: As-drilled Tops Attachment 4 NDBi-006 location map and area of injection review ADL 392963ADL 392984ADL 393021 ADL 393019 ADL 393018 ADL 393020 ADL 393015 ADL 393017ADL 393016 ADL 393006 ADL 393007 ADL 393008 ADL 391322 ADL 391445 ADL 391453 ADL 391454 ADL 391455 ADL 393009 ADL 393011 ADL 393010 FIORD 3A FIORD 3 QUGRUK 301 QUGRUK 3A QUGRUK 7 DW-02 NDB-010 NDB-011 NDB-024 NDB-025 NDB-032 NDB-037 NDB-051 NDBi-014 NDBi-016 NDBi-018 NDBi-030 NDBi-043A NDBi-044 NDBi-049 OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD 0.25-MILE BUFFER 0.5-MILE BUFFER NDBI-006 SURFACE LOCATION NDBI-006 BOTTOM HOLE NDB DRILLED WELLS BOTTOM HOLES NDBI-006 TRAJECTORY OTHER DRILLED NDB WELLS EXPLORATION WELLS BOTTOM HOLES WELL TRAJECTORIES BY OTHERS SANTOS LEASES SECTIONS DATE: 9/19/2025. By: JB 0 0.1 0.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDBi06_buffers Map Frame: AP-DRL-GEN-M_NDBi-006-12_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 0.2 0.4 Kilometers PIKKA DEVELOPMENT NDBi-006 WELL Injector Area of Review Wells within ¼ mile of proposed injection well. Distance Annulus integrity Area of Review Information No wells are within a ¼ mile of the proposed injection zone within the reservoir. N/A N/A N/A Advanced Cement Evaluation Report Behind 9.625 Casing Company: Santos Well: NDBi-006 Field: Pikka Borough: North Slope State: Alaska API#: 50-103-20926-00 Geoscience & Production Center of Excellence, North America Analyst: Fanny Haroun Email: fanny.haroun@halliburton.com Phone: 907-342-5550 Logging Date: 12/02/2025 Report Date: 12/03/2025 HALLIBURTON DOES NOT GUARANTEE THE ACCURACY OF ANY INTERPRETATION OF THE LOG DATA,CONVERSION OF LOG DATA TO PHYSICAL ROCK PARAMETERS OR RECOMMENDATIONS WHICH MAY BE GIVEN BY HALLIBURTON PERSONNEL OF WHICH APPEAR ON THE LOG OR IN ANY OTHER FORM. ANY USER OF SUCH DATA,INTERPRETATIONS,CONVERSIONS OF RECOMMENDATIONS AGREES THAT HALLIBURTON IS NOT RESPONSIBLE EXCEPT WHERE DUE TO GROSS NEGLIGENCE OR WILLFUL MISCONDUCT,FOR ANY LOSS,DAMAGES,OR EXPENSES RESULTING FROM THE USE THEREOF Santos Advanced Cement Evaluation NDBi-006 Halliburton Energy Services 2 Executive Summary This report covers NDBi-006 that was logged by Halliburton on December 2, 2025. The well was logged with a CAST-M/CBL-M tool combination ran from 2646-6350 ft and 9450-11798 ft MD, in 9.625 47# liner. The logging was acquired in 2 passes. The wireline depth was zeroed on the rig floor. The CAST-M is an Ultrasonic tool that records a waveform for each shot around the pipe 360 degrees. The CAST-M waveforms were recorded at 60 shots/scan and 4 scans per foot. The CBL-M is a standard cement bond log recording of 3-foot and 5-foot omni-directional waveforms. The 3-foot amplitude and travel time are measured from the amplitude of the E1 peak of the 3-foot waveform. The Impedance and Pipe Amplitude maps indicate a possible eccentricity of the 9.625 casing, particularly in the deviated section of the wellbore. This suggests that one side of the pipe may be closer to the formation than the opposite side. Halliburton uses a program called Advanced Cement Evaluation (ACE) that was developed 1998. This program is explained in detail in the appendix. Cement bond classification tables are presented below. DEPTH (ft) BOND CLASSIFICATION COMMENTS 2916-3285 4125-4154 5548-5603 2732-2916 3285-4125 4154-5548 5603-5656 6051-6082 6167-6230 6273-6350 2646-2732 5656-6051 6082-6167 6230-6273 N/A Cement Bond Classification (2646-6350 ft) FREE PIPE Free pipe. Mud/ drilling fluid behind the pipe. GOOD Good bonding and coverage seen in these areas. Cement bond index is greater than 80% FAIR Fair bonding and coverage seen in these areas. Cement bond index is between 50% - 80% POOR Poor bonding and coverage seen in these areas. Cement bond index is Between 20% - 50% Santos Advanced Cement Evaluation NDBi-006 Halliburton Energy Services 3 DEPTH (ft) BOND CLASSIFICATION COMMENTS 11458-11798 11183-11458 9498-9522 9903-9939 10316-10778 10975-11020 11115-11183 9450-9498 9522-9903 9939-10316 10778-10975 11020-11115 Cement Bond Classification (9450-11798 ft) FREE PIPE Free pipe. Mud/ drilling fluid behind the pipe. GOOD Good bonding and coverage seen in these areas. Cement bond index is greater than 80% FAIR Fair bonding and coverage seen in these areas. Cement bond index is between 50% - 80% POOR Poor bonding and coverage seen in these areas. Cement bond index is Between 20% - 50% Santos Advanced Cement Evaluation NDBi-006 Halliburton Energy Services 4 Table of Contents Executive Summary.................................................................................................................................................... 2 Quality Control............................................................................................................................................................ 5 Well Schematic ........................................................................................................................................................... 6 Tool Diagram .............................................................................................................................................................. 7 ACE Analysis Result (Top Interval 2646-6350 ft) .................................................................................................... 8 2646-2732 ft: Poor Bond .............................................................................................................................................. 9 2732-2916 ft: Fair Bond ............................................................................................................................................. 10 2916-3285 ft: Good Bond ........................................................................................................................................... 11 3285-4125 ft: Fair Bond ............................................................................................................................................. 12 4125-4154 ft: Good Bond ........................................................................................................................................... 13 4154-5548 ft: Fair Bond ............................................................................................................................................. 14 5548-5603 ft: Good Bond ........................................................................................................................................... 15 5603-5656 ft: Fair Bond ............................................................................................................................................. 15 5656-6051 ft: Poor Bond ............................................................................................................................................ 16 6051-6082 ft: Fair Bond ............................................................................................................................................. 17 6082-6167 ft: Poor Bond ............................................................................................................................................ 17 6167-6230 ft: Fair Bond ............................................................................................................................................. 18 6230-6273 ft: Poor Bond ............................................................................................................................................ 18 6273-6350 ft: Fair Bond ............................................................................................................................................. 19 ACE Analysis Result (Bottom Interval 9450-11798 ft) .......................................................................................... 20 9450-9498 ft: Free Pipe ............................................................................................................................................. 21 9498-9522 ft: Poor Bond ............................................................................................................................................ 21 9522-9903 ft: Free Pipe ............................................................................................................................................. 22 9903-9939 ft: Poor Bond ............................................................................................................................................ 23 9939-10316 ft: Free Pipe ........................................................................................................................................... 24 10316-10778 ft: Poor Bond ........................................................................................................................................ 25 10778-10975 ft: Free Pipe ......................................................................................................................................... 26 10975-11020 ft: Poor Bond ........................................................................................................................................ 26 11020-11115 ft: Free Pipe ......................................................................................................................................... 27 11115-11183 ft: Poor Bond ........................................................................................................................................ 28 11183-11458 ft: Fair Bond ......................................................................................................................................... 29 11458-11798 ft: Good Bond ....................................................................................................................................... 30 Appendix ................................................................................................................................................................... 31 Overview ..................................................................................................................................................................... 31 Cement Interpretation Logging Tools.......................................................................................................................... 31 Advanced Cement Evaluation (ACE) .......................................................................................................................... 31 Data Requirements .................................................................................................................................................... 32 References ................................................................................................................................................................. 32 Advanced Cement Evaluation (ACE) ...................................................................................................................... 33 ACE for Cement Bond Log (CBL) Tools ..................................................................................................................... 33 Cement Evaluation in Casing Overlap ........................................................................................................................ 36 Segmented Presentation for Ultrasonic Tools ....................................................................................................... 38 Advanced Cement Evaluation for Ultrasonic Tools .............................................................................................. 40 Santos Advanced Cement Evaluation NDBi-006 Halliburton Energy Services 5 Quality Control Qualitative raw data notes: The wireline depth was zeroed on the rig floor. The well was logged with a CAST-M/CBL-M tool combination ran from 2646-6350 ft and 9450-11798 ft MD, in 9.625 47# liner. The logging was acquired in 2 passes. The Impedance and Pipe Amplitude maps indicate a possible eccentricity of the 9.625 casing, particularly in the deviated section of the wellbore. This suggests that one side of the pipe may be closer to the formation than the opposite side. Overall, the raw data quality looks good and within tolerance value. Curve Scales: GR: Gamma Ray, 0-100 gapi. ECC: Tool Eccentricity, 0-0.25 inch. OVAL: Borehole Ovality, 0-0.25 inch. ZAVG: Average Impedance, 10-0 Mrayl. DEVI: Well Deviation, 0-100 deg LSPD: Wireline Line Speed, 0-50 ft/min. AMP3F: 3FT Amplitude from CBL tool, 0-52 mV, 51.28 mV being the free pipe (0% cement bond). FCEMBI: Final Cement Bond Index Curve from the CEMT curve, 1-0. WVF5: 5 ft Waveform from CBL tool. WMSGD: Derivative of the 5 ft Waveform from CBL tool. This curve is useful to show chevron pattern for the collar. Distinctive Chevron pattern indicates free pipe. ZMap: Impedance Map, 0-8 MRayl, 2.7 Mrayls being the lowest cement impedance for the cement slurry. DZ: Impedance Derivative. 0-1.6. CEMT: Final Cement Curve. 0-1. If one of either ZP or DZ curve shows cement value, the CEMT will be calculated as cement. Santos Advanced Cement Evaluation NDBi-006 Halliburton Energy Services 6 Well Schematic Santos Advanced Cement Evaluation NDBi-006 Halliburton Energy Services 7 Tool Diagram Attachment 11 NDB-011 Potential Plug & Abandonment Schematic Top Nan 3.2 @11,785' MD Tuluvak Sand @ 3256' MD NDBi-006 Possible P&A Well Schematic 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2720' MD 13-3/8" 68 ppf L-80 Surface Casing2883' MD 9-5/8", 47ppf L-80 Production Liner 11,824' MD 4-½, 12.6ppf P-110S Production Liner21,132' MD 4-½ Liner Hanger/ Top Packer11,652' MD RKB Bottom Flange 4th Dec. 2025 9-5/8" Tieback2720' MD 9-5/8" Cflex Stage Tool (50' MD below TS790) 5305' MD 8-½ Openhole TD21,149' MD Fault 20,532'/20612' MD Fault ~11,600' MD 9-5/8" Cflex Stage Tool (Placed @ Top Nan FM.)10349' MD 9-5/8" Primary TOC~11,183' MD Fault ~7,450' MD (no direct losses noted) Fault 14,790' MDFault 13370'/13440' MD Top of Nan 10,334' MD Cement Plug #3 & 4: Cement Plugs in Accordance with AOGCC regulations to isolate Tuluvak hydrocarbon bearing formation and surface cement plug. Cement Plug #1: Down squeeze 4-1/2 liner and 9-5/8" casing volume to cement retainer depth. Cement Plug #2: isolate any hydrocarbons within Nanushuk in accordance with AOGCC regulation. 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-006 (PTD No. 225-101; Sundry No. 325-761) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 December 30, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. A.Dewhurst 23DEC25 (a)(2) Plat Provided with application. A.Dewhurst 23DEC25 (a)(2)(A) Well location Provided with application. A.Dewhurst 23DEC25 (a)(2)(B) Each water well within ½ mile None: There are no wells used for drinking water purposes known to lie within ½ mile of the surface location of Pikka NDBi-006. There are no subsurface water rights or temporary subsurface water rights within 14 miles of the surface location of Pikka NDBi-006. A.Dewhurst 23DEC25 (a)(2)(C) Identify all well types within ½ mile Provided with application. A.Dewhurst 23DEC25 (a)(3) Freshwater aquifers: geological name; measured and true vertical depth None. No freshwater aquifers are present within the Pikka Unit per salinity calculations provided by the operator on Aug. 21, 2023 as part of their Sundry Application to hydraulically fracture nearby well Pikka NDB-024 (see AOGCCs Well History File 223-076, p. 101-107 of Sundry Application 323-591). Pickett Plot well-log analyses were performed on three wells within the unit that have wireline log coverage from surface through the fracturing interval: Colville River 1, Till 1, and Pikka DW-02. Estimated salinity values for clean, porous 100% water-saturated sands beneath the base of the permafrost layer in these three wells are: Colville River 1 (PTD 192-153) ~20,000 mg/l between 1,400 and 2,000 MD (-1,354 to 1,954' TVDSS; base of permafrost 1,350 MD (-1,313 TVDSS)); Till 1 (PTD 193-004) 16,700 to ~23,000 mg/l between 1,400 and 1,500 MD (-1,463 to -1,363 TVDSS; base of permafrost 1,350 MD (-1,305 TVDSS)); and DW-02 (PTD 223-039) ~21,500 mg/l between 1,550 and 1,650 MD (-A.Dewhurst 23DEC25 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-006 (PTD No. 225-101; Sundry No. 325-761) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 December 30, 2025 1,408 to -1,486 TVDSS; base of permafrost ~1,170 MD (~-1,080 TVDSS)). (a)(4) Baseline water sampling plan None required. A.Dewhurst 23DEC25 (a)(5) Casing and cementing information Provided with application. Proposed schematic attached, as built not generated to date. CDW 12/18/2025 (a)(6) Casing and cementing operation assessment 13-3/8 surface casing cemented to surface with no losses and bbl cement circulated at surface. 9-5/8 CFLEX stage tool, 3 stage cement job, Shoe@ 11828 ft, 30% excess with plan top of 10950 ft. Losses resulted in 70 bbl of 70 bbl cement pumped at shoe. 2nd Stage 10349 ft plan at 30% excess. Target 9335 ft MD. Severe losses estimated as 162 bbl of 172 bbl cement lost 3rd stage@ 5305 ft target top of 9-5/8 liner top. No losses. until full losses displacing cement with OBM. Trace cement circulated off liner top. Estimated 72 bbl lost of 288 bbl cement pumped. Top Nanushuk 10330 ft MD. Baker and the Halliburton CBL logging showed no cement at top of Nanushuk, 10330-11225 ft, partial cement 11225-11450 ft, top of good cement 11490 ft. 4.5 production liner with packer set at 11677 ft. Variance for bad cement asked by Rob Williams to Bryan McLellan on 12/06/2025. Recommend approval of variance based on TOC logging, shoe drill out and test, and 4.5 liner packers should isolate the frac to approved zone. Drlg Eng CDW 12/18/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-006 (PTD No. 225-101; Sundry No. 325-761) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 December 30, 2025 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) A.Dewhurst 23DEC25 (a)(6)( B) Each hydrocarbon zone is isolated No, the Nanushuk is not completely isolated. TOC for the first and second stages of the 9-5/8 intermediate casing cement is within the NT3/4, leaving 1,156 MD (223 TVD) of the Nanushuk Oil Pool without cement isolation. However, this should not compromise the isolation of the NT3.2 fracturing interval which is adequately isolated; there may be additional remediation required at P&A, but granting the requested variance is recommended. The Tuluvak is adequately isolated by the third stage of the 9-5/8 intermediate casing cement. A.Dewhurst 23DEC25/ Drlg Eng (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 4300 psi MITIA planned, 5500 psi MITT plan. CDW 12/18/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi wellhead max. frac. Pressure 8800 psi. Pump knock out 6600-7600 and GORV 7000-8000 psi., lines test 9200 psi. CDW 12/18/2025 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper Confining Zones: About 476 true vertical thickness (TVT) of claystone, shale and volcanic tuff assigned to the Seabee Formation having an estimated fracture gradient of 13.7 ppg EMW (0.71 psi/ft). Fracturing Zone: Perforated zone lies within a subdivision of the Nanushuk Formation that is about 950 TVT in this area and has an estimated fracture gradient of 11.7 ppg EMW (0.61 psi/ft). A.Dewhurst 23DEC25 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-006 (PTD No. 225-101; Sundry No. 325-761) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 December 30, 2025 Lower Confining Zones: About 900 TVT of Lower Torok (Hue) shales and interbedded siltstones with an estimated fracture gradient of 13.3 ppg EMW (0.69 psi/ft). (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory It is highly unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids from this operation because of cement isolation and / or separation distance. Santos provided cement isolation details for NDB-010, the only well within the ½ mile radius. There is one well within ½ mile of Pikka NDBi-006 that penetrates the confining interval and it has been reviewed by the AOGCC. A.Dewhurst 23DEC25/ CDW 12/18/2025 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory The operator has identified 5 faults within a ½-mile radius of Pikka NDBi-006. It is unlikely that any faults will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. A.Dewhurst 23DEC25 (a)(12) Proposed program for fracturing operation Provided with application. CDW 12/18/2025 (a)(12)(A) Estimated volume Provided with application. 29K bbl total dirty vol. 3.135million lb total proppant CDW 12/18/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 12/18/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger, Tracerco, and Patina Energy disclosures provided. Proprietary chemicals on file at AOGCC. CDW 12/18/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 12/18/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-006 (PTD No. 225-101; Sundry No. 325-761) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 December 30, 2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure expected of 5544 psi. Max. 8800 psi allowable treating pressure. Max pressure is 6600-7000 psi or 7600-8000 psi to Pump shutdown. With 3800 psi back pressure IA (IA popoff set 4100 psi), max tubing differential should be 5000 psi. CDW 12/18/2025 (a)(12)(F) Fractures height, length, MD and TVD to top, description of fracturing model Provided with application. The maximum anticipated half-length of the induced fractures is 368 according to the Operators computer simulation. Computer simulation indicates the maximum anticipated height of the induced fractures will be 267, so it is unlikely that induced fractures will penetrate into the overlying confining zone. Detailed depths are provided in the application. A.Dewhurst 23DEC25 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified CDW 12/18/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3800 psi back pressure, plan to test to 4300 psi, popoff set as 4100 psi CDW 12/18/2025 (c) Fracturing string (c)(1) Packer >100 below TOC of production or intermediate casing 4.5 production liner with packer set at 11677 ft. Baker log and the Halliburton CBL logging showed no cement at top of Nanushuk, 10330-11225 ft, partial cement 11225-11450 ft, top of good cement 11490 ft. Variance for bad cement asked by Rob Williams to Bryan McLellan on 12/06/2025. Recommend approval of variance based on TOC logging, shoe drill out and test, and 4.5 liner packers should isolate the frac to approved zone. CDW 12/18/2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 5500 psi. Max pressure differential is estimated as 5000 psi (8800 with 3800 psi backpressure) so test of 5500 psi satisfies 110% CDW 12/18/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 9200 psi line pressure test, pump knock out 6600 psi with max. global kickout 7000 psi. IA PRV set as 4100 psi. CDW 12/18/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-006 (PTD No. 225-101; Sundry No. 325-761) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 December 30, 2025 Alternative trip schedule stated as 7600 psi trip and GORV 8000 psi. OK. (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 12/18/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 4100 psi. Surface annulus open. Frac pressures continuously monitored. CDW 12/18/2025 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than X00 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 12/18/2025 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). A.Dewhurst 23DEC25 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. A.Dewhurst 23DEC25 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. 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?Pikka / NDBi-006 Yes No 9. Property Designation (Lease Number): 10. Field: Pikka Nanushuk Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 11,828' 4,043' 1,465 Casing Collapse Structural Conductor Surface 2,260 Intermediate1 Intermediate2 Production 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: Yes Date: GAS WAG GSTOR SPLUG AOGCC Representative: Bryan McLellan GINJ Op Shutdown Abandoned Contact Name:Mark Staudinger Contact Email:mark.staudinger@santos.com Contact Phone: 520-273-6643 Authorized Title: Senior Drilling Engineer Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Perforation Depth MD (ft): 20"x34" 13-3/8" 128' 2,883' MD 5,020 128' 2,384' 128' 2,883' Length Size Proposed Pools: TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 393016, 393015, 391455, 393011, 391454 225-101 601 W 5th Avenue, Anchorage, AK 99501-6301 50-103-20926-00-00 Oil Search Alaska, LLC AOGCC USE ONLY 11/17/2025 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 11/17/2025 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 m ns 2 66 t _ c N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov g g p November 17, 205 325-703 By Grace Christianson at 4:15 pm, Nov 17, 2025 TS 11/18/25 BJM 11/18/25 10-407 Cement log must be run across Stage 1 & 2 cement jobs in 9-5/8" liner. All conditions of approval on the PTD still apply. DSR-11/19/25JLC 11/19/2025 11/20/25 Page 1 of 1 17 November 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Sundry for Changes to Permit to Drill Oil Search (Alaska), LLC, a subsidiary of Santos Limited NDBi-006 (PTD 225-101) Dear Sir/Madam, Oil Search (Alaska), LLC hereby applies for a Sundry for changes to approved Permit to Drill 225-101 for well NDBi-006. The 12-1/4 intermediate hole was drilled to a depth of 11,828 MD. While performing cleanup cycles after TD, the well began to go on losses at a bit depth of ~11,633 MD, which is near a pre-drill prognosed fault at 11,600 MD. Attempts were made to heal losses with LCM, but unsuccessfully. Currently, the BHA has been pulled to surface and the rig is preparing to run 9-5/8 liner. Due to the losses (likely near the prognosed fault), Oil Search has low confidence of a successful 1st stage cement job across the Upper Nanushuk, as per the original PTD. Oil Search is proposing a lower CFLEX stage tool to be placed at the top of the Nanushuk formation to allow re-establishing a seal above the Nanushuk Pool. Plan forward will be to run the 9-5/8 liner with 2 CFLEX tools, then perform a primary cement job targeting NT6 TOC. The 2nd stage job will then be performed to establish isolation from the Top Nanushuk to 200 TVD above the Nanushuk. The 3rd stage cement job will then be performed to isolate the Tuluvak formation (as per original PTD). The remainder of the drilling program will follow the original PTD. Additionally, when the sonic CBL is run to log 9-5/8 cement, both the 1st and 2nd stage cement jobs will be logged. If there are any questions and/or additional information desired, please contact me at (520) 273-6643 or mark.staudinger@santos.com. Respectfully, Mark Staudinger Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-403 Respectfully, Mark Staudinger Sundry to Permit to Drill NDBi-006 Well PTD 225-101 Changes to approved Permit to Drill (PTD 225-101) are in red text below 13. Proposed Drilling Program 20 AAC 25.005 (c) (13) A copy of the proposed drilling program; the drilling program must indicate if a well is proposed for hydraulic fracturing as defined in 20 AAC 25.283(m); to seek approval to perform hydraulic fracturing, a person must make a separate request by submitting an Application for Sundry Approvals (Form 10-403) with the information required under 20 AAC 25.280 and 20 AAC 25.283; The proposed drilling program to NDBi-006 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed NDBi-006 Drilling Program 1. Drill 20 conductor to ~128 MD/TVD. Cement to surface. Install Cellar and landing ring on conductor. 2. Move in / rig up Parker 272. 3. Nipple up spacer spools over the 20 conductor. 4. Pick up 5-7/8 drill pipe, fill pits with spud mud and prepare for surface hole drilling. Make up 16 motor BHA with MWD and LWD tools. 5. Spud well and drill surface hole section to TD. Perform wiper trips as required. Circulate and condition hole to run casing. POOH and lay down BHA. 6. Run 13-3/8 68# surface casing as per casing tally and land on pre-installed landing ring. Circulate and condition mud prior to commencing cement job. 7. Cement 13-3/8 casing as per cement program. Verify cement returns to surface. 8. NU casing head and spacer spool. NU BOPE with Rotating Control Device (RCD). BOP configured from top to bottom: annular preventor, 4-1/2 x 7 VBR, blind/shear, mud cross, 9-5/8 Fixed Rams. Test rams to 5000 psi high (initial test only 3600 psi for subsequent tests) and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 48 hrs notice for witnessing BOP test. 9. Close blind shear rams and pressure test casing to 2600 psi for 30 min. 10. Make up 12-1/4 RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment and displace well to MOBM. 11. Drill out shoe track and 20 - 50 of new formation. Perform FIT / LOT. 12. Directionally drill 12-1/4 intermediate hole section to TD. Perform wiper trips as required. Circulate and condition hole to run liner. POOH. 13. RU and run 9-5/8 intermediate liner as per casing tally then RIH on 5-7/8 DP / HWDP to TD. Circulate and condition mud prior to commencing cement job. 14. Set liner hanger and release running tool. Cement 9-5/8 liner with 1st stage cement job as per cement program. Monitor returns during displacement until plug bump. 15. Un-sting from liner hanger and POOH and LD liner running tools. 16. RIH with mechanical shifting tool and open 2 nd stage cement job tools. Pump secondary cement job and close 2 nd stage cementing tool. POOH. 17. RIH with mechanical shifting tool and open 3 rd stage cement job tools. Pump tertiary cement job, set liner top packer, and circulate cement to surface. POOH. 18. RIH with polish mill assembly for cleanout of the 9-5/8 liner top PBR. 19. Run 9-5/8 tieback string. Freeze protect the 13-3/8 x 9-5/8 annulus with diesel and land tieback. 20. Pressure test the 13-3/8 x 9-5/8 annulus to 2600 psi for 30 min. 21. Pressure test the 9-5/8 liner / tieback to 3500 psi for 30 min. 22. Make up 8-1/2 RSS BHA with MWD and LWD tools. RIH with 5 drillpipe. 23. Displace/condition MOBM to the required mud weight for MPD while drilling out the shoe track. 24. Circulate casing clean, install the MPD bearing assembly and test MPD surface equipment as required. 25. Drill 20 - 50 of new formation. Perform FIT / LOT. 26. Directionally drill 8-1/2 production hole section to TD using MPD. Back ream hole and perform wiper trips as required. Circulate and condition hole to run liner. 27. POOH. Log first stage cement with Sonic LWD. NOTE: See more details / justification in Attachment 6: Cement Summary. 28. Run cleanout/string mill assembly to dress the 9-5/8 CFLEX tool. 29. RU and run 4-1/2 production liner with liner hanger/top packer and downhole jewelry to TD. 30. Drop 1.125 ball, circulate in place, land ball in WIV collar. Close WIV collar and set open hole hydraulic set packers and liner hanger/top packer. 31. Set and pressure test the 9-5/8 x 7 x 4-1/2 IA to liner top packer to 3,500 psi for 10 min. Release the running tool. 32. Pull liner running tool above liner top. POOH and LD liner running tool. 33. RU and run 4-1/2 upper completion and downhole jewelry with TEC wires. 34. Circulate MOBM out of open hole with NaCl brine with biocide. 35. Space out and land PBR seals and tubing hanger. 36. Pressure test tubing to 3,500 psi for 30 mins. Pressure up on the annulus to 4,000 psi for 30 mins. Bleed pressure on tubing and shear upper gas lift valve. 37. Reverse circulate freeze protect and U-Tube. 38. Install TWC, pressure test to 2,500 psi for 10 mins. ND BOPE, NU frac tree. 39. Secure well and prepare for rig move. Attachment 6: Cement Summary Intermediate Liner Cement Casing Size 9-5/8 47# L-80 Hydril 563 Intermediate Liner Basis Tail Open hole volume + excess + 85 ft shoe track Tail TOC Stage 1: ~880 MD above the 9-5/8 shoe (above NT6) Stage 2: 200 TVD above the top Nanushuk formation Stage 3: Top of the 9-5/8 Liner (~150 liner lap) Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Tail Stage 1: 30% Open Hole Excess 15.3ppg Tail: 70 bbls, 392cuft, 316sks VersaCem Type I/II 1.24 cuft/sk Stage 1: 30% Open Hole Excess 15.3ppg Tail: 73.5 bbls, 413cuft, 333sks VersaCem Type I/II 1.24 cuft/sk Stage 3: 100% Open Hole Excess 15.3ppg Tail: 271.7 bbls, 1525cuft, 1230sks VersaCem Type I/II 1.24 cuft/sk Temp Stage 1 - BHST 105° F (2.25°/100 TVD below PermaFrost) Stage 2 BHST 89° F (2.25°/100 TVD below PermaFrost) Stage 3 - BHST 71° F (2.25°/100 TVD below PermaFrost) Notes Job will be mixed on the fly Verification Method - LWD Sonic will be used to log the 1st Stage and 2 nd Stage Cement Job only. -3rd Stage Cement Job will not be logged, assuming job parameters are as expected (no losses, good lift pressures, circulate cement off top of liner). Justification: - Stage tool allows for precise placement of base cement column at base Tuluvak hydrocarbon. - Bond log not required for 3rd Stage per Regulation 20 AAC 25.030(d)(5) -3rd Stage bond evaluation does not affect 1st or 2nd Stage bond evaluation and frac decision. - Logging of 1st and 2nd Stage cement will demonstrate isolation between Nanushuk and Tuluvak, ensuring no potential crossflow. -3rd Stage cement job will isolate Tuluvak with cement and a V0-rated LTP above it as a redundant means of isolation. - Well design allows for the OA annulus to be freeze protected by circulating in place (with Tieback) vs. bullheaded into place. With a sufficient initial LOT/FIT at the surface casing shoe, any potential Tuluvak pressures will be contained by the surface casing shoe and not cross flow into shallower formations. - Future hydraulic fracture operations will only be done in the Nanushuk formation. Log verification of the 1st and 2nd stage cement job will verify proper isolation has been achieved for frac operations. - Tuluvak isolation has been achieved on all historical Pikka development wells. - Seeking to simplify an already complicated operation, saving time/money. Cement calculations have been updated to reflect the above changes Attachment 8: Well Schematic From:McLellan, Bryan J (OGC) To:Staudinger, Mark (Mark) Cc:Williams, Rob (Rob); Tirpack, Robert (Robert); Davies, Stephen F (OGC); Starns, Ted C (OGC); Dewhurst, Andrew D (OGC) Subject:RE: NDBi-006 (PTD 225-101) Change in 9-5/8" Cementing Plan Date:Monday, November 17, 2025 11:44:00 AM Mark, A condition of approval is that Oil Search must run cement log across both the first and 2nd stage cement jobs. The third stage only needs to be logged if it doesn’t go per plan, don’t get good cement back to surface, significant losses, etc (same as already stated in condition 6 of the original permit to drill). Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Monday, November 17, 2025 11:32 AM To: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Williams, Rob (Rob) <Rob.Williams@santos.com>; Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: RE: NDBi-006 (PTD 225-101) Change in 9-5/8" Cementing Plan Mark Oil Search has approval to proceed with this plan. Please submit a sundry within 3 days for the change. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 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. Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Monday, November 17, 2025 10:48 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Williams, Rob (Rob) <Rob.Williams@santos.com>; Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: NDBi-006 (PTD 225-101) Change in 9-5/8" Cementing Plan Bryan, As discussed yesterday, we encountered losses after drilling to TD on NDBi-006. Well information is below. We attempted an LCM pill, but it didn’t seem to help with the losses. Since the losses appear to be in the Upper Nanushuk, we would like to propose a modified cement plan to help ensure isolation at the 9-5/8” shoe, as well as re-establish the seal above the Nanushuk pool. Current Status Currently getting ready to run the 9-5/8” liner. Well Information TD at 11,828’ MD Suspected loss zone ~11,600’ MD (in the NT4) Top Nanushuk at 10,330’ MD TS790 at 5,253’ MD 13-3/8” shoe at 2,883’ MD Plan Forward Due to the losses and concerns with isolation on the 1st stage cement job, the plan is to perform a 3-stage cement job via 2 Archer CFLEX tools. Run 9-5/8” Liner as per current program, placing the 1st CFLEX tool at the Top Nanushuk and the 2nd CFLEX tool ~50’ MD below the TS790 (for Tuluvak coverage). First Stage Cement Job: Pump 878’ MD cement job (70 bbls 15.3ppg cement) to provide shoe strength and cover loss zone. TOC with 30% excess is at 10,950’ MD. If for some reason we achieve full returns, the TOC will be ~26’ MD above the NT6. We are aiming to balance Upper Nan coverage with ensuring that cement doesn’t reach the lower CFLEX stage tool. Second Stage Cement Job: RIH with CFLEX cementing tool down to the lower CFLEX at ~10,349’ MD. Open CFLEX and Pump 2nd stage cement job, targeting 200’ TVD (9,335’ MD) above Top Nanushuk, with ~72 bbls cement. Close CFLEX and permanently lock tool. POOH with CFLEX cementing tool. Third Stage Cement Job: RIH and perform the 3rd stage cement job as per the original plan. I will prepare and submit a Sundry today or tomorrow, but would request your approval to proceed with our plan. Let me know if you have any questions. Thanks, Mark Mark Staudinger Senior Drilling Engineer m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may beconfidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use,distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 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:McLellan, Bryan J (OGC) To:Staudinger, Mark (Mark); Starns, Ted C (OGC); Dewhurst, Andrew D (OGC) Cc:Williams, Rob (Rob); Tirpack, Robert (Robert) Subject:RE: NDBi-006 (PTD 225-101) Change in 9-5/8" Cementing Plan Date:Monday, November 17, 2025 11:31:00 AM Mark Oil Search has approval to proceed with this plan. Please submit a sundry within 3 days for the change. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Mark (Mark) <Mark.Staudinger@santos.com> Sent: Monday, November 17, 2025 10:48 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Williams, Rob (Rob) <Rob.Williams@santos.com>; Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: NDBi-006 (PTD 225-101) Change in 9-5/8" Cementing Plan Bryan, As discussed yesterday, we encountered losses after drilling to TD on NDBi-006. Well information is below. We attempted an LCM pill, but it didn’t seem to help with the losses. Since the losses appear to be in the Upper Nanushuk, we would like to propose a modified cement plan to help ensure isolation at the 9-5/8” shoe, as well as re-establish the seal above the Nanushuk pool. Current Status Currently getting ready to run the 9-5/8” liner. Well Information TD at 11,828’ MD Suspected loss zone ~11,600’ MD (in the NT4) Top Nanushuk at 10,330’ MD TS790 at 5,253’ MD 13-3/8” shoe at 2,883’ MD Plan Forward Due to the losses and concerns with isolation on the 1st stage cement job, the plan is to perform a 3-stage cement job via 2 Archer CFLEX tools. Run 9-5/8” Liner as per current program, placing the 1st CFLEX tool at the Top Nanushuk and the 2nd CFLEX tool ~50’ MD below the TS790 (for Tuluvak coverage). First Stage Cement Job: Pump 878’ MD cement job (70 bbls 15.3ppg cement) to provide shoe strength and cover loss zone. TOC with 30% excess is at 10,950’ MD. If for some reason we achieve full returns, the TOC will be ~26’ MD above the NT6. We are aiming to balance Upper Nan coverage with ensuring that cement doesn’t reach the lower CFLEX stage tool. Second Stage Cement Job: RIH with CFLEX cementing tool down to the lower CFLEX at ~10,349’ MD. Open CFLEX and Pump 2nd stage cement job, targeting 200’ TVD (9,335’ MD) above Top Nanushuk, with ~72 bbls cement. Close CFLEX and permanently lock tool. POOH with CFLEX cementing tool. Third Stage Cement Job: RIH and perform the 3rd stage cement job as per the original plan. I will prepare and submit a Sundry today or tomorrow, but would request your approval to proceed with our plan. Let me know if you have any questions. Thanks, Mark Mark Staudinger Senior Drilling Engineer m: +1 (520) 273-6643 | e: Mark.Staudinger@santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos Ltd A.B.N. 80 007 550 923Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDBi-006 JBR 01/02/2026 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Tested with 5-7/8" and 9-5/8" test joints. Solid test and the rig was clean and in order. Test Results TEST DATA Rig Rep:Nigel WherleyOperator:Oil Search (Alaska), LLC Operator Rep:Brian Buzby Rig Owner/Rig No.:Nabors 272 PTD#:2251010 DATE:11/12/2025 Type Operation:DRILL Annular: 250/3600Type Test:INIT Valves: 250/5000 Rams: 250/5000 Test Pressures:Inspection No:bopJDH251114135736 Inspector Josh Hunt Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6 MASP: 1465 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 2 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 4-1/2" X 7" V P #2 Rams 1 Blind Shears P #3 Rams 1 9-5/8" SBR P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/8"P Kill Line Valves 2 3-1/8" 2-1/16 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3050 Pressure After Closure P2050 200 PSI Attained P10 Full Pressure Attained P67 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P14@2140 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P30 #1 Rams P6 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2        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 Rob Williams Senior Drilling Engineer Oil Search Alaska, LLC 601 W 5th Avenue Anchorage, AK, 99501 Re: Pikka Field, Nanushuk Oil Pool, NDBi-006 Oil Search Alaska, LLC Permit to Drill Number: 225-101 Surface Location: 2,507 FSL, 2,628 FEL, Sec 4, T11N, R6E, UM Bottomhole Location: 278 FSL, 751 FWL, Sec 17, T12N, R6E, UM Dear Mr. Williams: 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. Proposed dry ditch sample interval from Attachment 9 accepted with modification of Ivishak (not to exceed 30'). This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 2 th day of October 2025. 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 22,357' TVD: 4,045' 4a. Location of Well (Governmental Section): 7. Property Designation: ADL 392984, Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1st Nov. 2025 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 5,545' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 69.80' 15. Distance to Nearest Well Open Surface: x- 423,383.61 y- 5,972,909.31 Zone- 4 22.80' to Same Pool: 1,800' 16. Deviated wells: Kickoff depth: 347 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 96 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20"x34" 215# X-52 Welded 80' Surface Surface 128' 128' 16" 13-3/8" 68# L-80 TXP BTC 2,884' Surface Surface 2,884' 2,382' 12-1/4" 9-5/8" 47# L-80 HYD563 9,085' 2,734' 2,318' 11,819' 4,039' Tie Back 9-5/8" 47# L-80 HYD563 2,734' Surface Surface 2,734' 2,318' 8-1/2" 4-1/2" 12.6# P-110S HYD563 10,671' 11,669' 4,007' 22,357' 4,045' Tubing 4-1/2" 12.6# P-110S HYD563 11,669' Surface Surface 11,669' 4,007' 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: Rob Williams Rob Williams Contact Email:rob.williams@santos.com Senior Drilling Engineer Contact Phone:907 343 9737 Date: Permit to Drill API Number: Permit Approval Number: Date: Conditions of approval: If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: Conductor/Structural LengthCasing Cement Volume MDSize Plugs (measured): (including stage data) Grouted to surface See attachment 6 See attachment 6 Effect. Depth MD (ft): Effect. Depth TVD (ft): Uncemented 3840 18. Casing Program: Top - Setting Depth - BottomSpecifications 1,877 GL / BF Elevation above MSL (ft): Total Depth MD (ft): Total Depth TVD (ft): IS000361277U STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 See attachment 6 1,465 2251 FSL, 517 FWL, Sec 28, T12N, R6E, UM 278 FSL, 751 FWL, Sec 17, T12N, R6E, UM LONS 19-003 601 W Fifth Avenue, Anchorage, AK 99501-6301 Oil Search Alaska, LLC 2,507 FSL, 2,628 FEL, Sec 4, T11N, R6E, UM 393016, 393015, 391455, 393011, 391454 Pikka NDBi-006 Pikka/Nanushuk Oil Pool N/A Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. s N ype of W l 1 Class: os N s No s N o DhD h h 277U o well is G S S 20 AA SS S s No s No S G y s No essss Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 225-101 By Grace Christianson at 7:57 am, Sep 30, 2025 5,972,886 50-103-20926-00-00 TS 10/14/25 422,617 DSR-10/15/25 See attached conditions of approval. BJM 10/16/25 10/20/25 10/20/25 NDBi-006 (PTD 225-101) Approval 1. - 2.6 . All a - -25- 4. 5. . 6. . Cement 7. . 8.- : a. - - - - - liner 10.- are met: a. a - it will - d. Supplement to Application for Permit to Drill: NDBi-006 Well Attachment 15: Injector Area of Review Wells within ¼ mile of proposed injection well. Distance Annulus integrity Area of Review Information No wells are within a ¼ mile of the proposed injection zone within the reservoir. N/A N/A N/A Page 1 of 1 29 September 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Permit to Drill Oil Search (Alaska), LLC, a subsidiary of Santos Limited NDB-010 Dear Sir/Madam, Oil Search (Alaska), LLC hereby applies for a Permit to Drill an onshore development well from the NDB drilling pad on the North Slope of Alaska. NDBi-006 is planned to be a horizontal injection well targeting the Nanushuk 3. The approximate spud date is anticipated to be November 1st, 2025. Parker Rig 272 will be used to drill this well. The 16 Surface Hole will TD above the Tuluvak sand and then 13-3/8 casing will be set and cemented. The 12-1/4 intermediate hole will be drilled to above the top of the Nanushuk 3 formation at an inclination of ~78-81 degrees. A 9-5/8 liner will be set and cemented from TD to secure the shoe and cover the Tuluvak sand. A 9-5/8 tieback will be run to the top of the 9-5/8 liner. The 8-1/2 production hole will be geo-steered in the Nanushuk 3 sand and the lateral will be drilled to TD. The well will be completed as a stimulated 4-1/2 liner with frac sleeves and isolation packers. The lower completion liner will be tied back to surface with a 4-1/2 tubing upper completion string. Please find enclosed for your review Form 10-401 Permit to Drill with a supporting Application for Permit to Drill containing information as required by 20 AAC 25.005. If there are any questions and/or additional information desired, please contact me at (907) 343 9737 or rob.williams@santos.com. Respectfully, Rob Williams Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Application for Permit to Drill NDBi-006 Well Table of Contents 1. Well Name...................................................................................................................................... 3 2. Location Summary.......................................................................................................................... 3 3. Blowout Prevention Equipment Information................................................................................. 4 4. Drilling Hazards Information........................................................................................................... 5 5. Procedure for Conducting Formation Integrity Tests..................................................................... 6 6. Casing and Cementing Program..................................................................................................... 6 7. Diverter System Information.......................................................................................................... 6 8. Drilling Fluid Program..................................................................................................................... 7 9. Abnormally Pressured Formation Information.............................................................................. 8 10. Seismic Analysis............................................................................................................................ 8 11. Seabed Condition Analysis............................................................................................................ 8 12. Evidence of Bonding..................................................................................................................... 8 13. Proposed Drilling Program ........................................................................................................... 9 14. Discussion of Mud and Cuttings Disposal and Annular Disposal................................................11 15. Proposed Variance Requests......................................................................................................11 Attachments.................................................................................................................... ..............................15 Attachment 1: Location Maps..........................................................................................................16 Attachment 2: Directional Plan......................................................................................................18 Attachment 3: BOPE Equipment ...................................................................................................... Attachment 4: Drilling Hazards......................................................................................................... Attachment 5A: Leak Off Test Procedure (Conventional)................................................................ Attachment 5B: Leak Off Test Procedure (With MPD)..................................................................... Attachment 6: Cement Summary..................................................................................................... Attachment 7: Prognosed Formation Tops...................................................................................... Attachment 8: Well Schematic......................................................................................................... Attachment 9: Formation Evaluation Program................................................................................ Attachment 10: Wellhead & Tree Diagram...................................................................................... Attachment 11: Diverter Variance Request NDB Surface Hole Map View....................................... Attachment 12: Oil Search Alaska 21-day BOPE Test Schedule Waiver Approval Letter................. Attachment 13: Managed Pressure Drilling..................................................................................... Attachment 14: As Built Survey NDB Well 10 Conductor Final........................................................ An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application. 1. Well Name 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this application for a Permit to Drill is submitted is designated as NDBi-006. This will be a development injection well. 2. Location Summary 20 AAC 25.005 (c) (2) A plat identifying the property and the property's owners and showing: (A) the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines; (B) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth Location at Surface Reference to Government Section Lines 2,507 FSL, 2,628 FEL, Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,885.86 E 422,617.52 Rig KB Elevation 47 above GL Ground Level 22.83 above MSL Location at Top of Productive Interval Reference to Government Section Lines 2251 FSL, 517 FWL, Sec 28, T12N, R6E, UM NAD 27 Coordinate System N 5,983,212 E 420,563 Measured Depth, Rig KB (MD) 12,383 Total Vertical Depth, Rig KB (TVD) 4,120 Total vertical Depth, Subsea (TVDSS) 4,050 Location at Bottom of Productive Interval Reference to Government Section Lines 278 FSL, 751 FWL, Sec 17, T12N, R6E, UM NAD 27 Coordinate System N 5,991,852 E 415,585 Measured Depth, Rig KB (MD) 22,357 Total Vertical Depth, Rig KB (TVD) 4,045 Total vertical Depth, Subsea (TVDSS) 3,975 (D) other information required by 20 AAC 25.050(b); 20 AAC 25.050 (b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must: (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; and Please refer to Attachment 2: Directional Plan for further details. (2) for all wells within 200 feet of the proposed wellbore: (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The applicant is the only affected owner. 3. Blowout Prevention Equipment Information 20 AAC 25.005 (c) (3) A diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; A 21-day BOPE test schedule is planned per the waiver acceptance letter and conditional requirements outlined in Docket Number OTH-25-010 from the AOGCC to Oil Search Alaska for Parker 272 operating at NDB (see Attachment 12). Parker 272 BOP Equipment: BOP Equipment NOV Shaffer Spherical annular BOP, 13-5/8 x 5000 psi NOV T3 6012 double gate, 13-5/8 x 5000 psi Mud cross, 13-5/8 x 5000 psi with 2 ea. 3-1/8" x 5000 psi side outlets Choke Line, 3-1/8 x 5000 psi with 3-1/8 manual and HCR valve Kill Line, 2-1/16 x 5000 psi with 3-1/8 manual and HCR valve NOV T3 6012 single gate, 13-5/8 x 5000 psi Choke Manifold 3-1/8 x 5000 psi working pressure with Axon Type S remote controlled chokes and NRG mud/gas separator BOP Closing Unit NOV SARA Koomey Control System, 316 gallon, 299 gallon reservoir. Twenty-Four 15 gallon bottles. Equipped with 1 electric and 3 air pumps with emergency power. Please refer to Attachment 3: BOPE Equipment for further details. 4. Drilling Hazards Information 20 AAC 25.005 (c) (4) Information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure; 12-1/4 Intermediate Hole Pressure Data Maximum anticipated BHP 1,836 psi in the Nanushuk 3 MFS at 4,017 TVD (8.8ppg EMW in the Nanushuk 3 formation to section TD) Maximum surface pressure 1,434 psi from the Nanushuk 3 MFS (0.10 psi/ft gas gradient to surface, 4,017 TVD) Planned BOP test pressure Rams test to 5,000 psi / 250 psi (Initial) Rams test to 3,600 psi / 250 psi (Subsequent) Annular test to 3,000 psi / 250 psi (Test pressure driven by annular pressure during frac job) Integrity Test 12-1/4 hole FIT after drilling 20-50 of new hole to 14.0 ppg. (12.9 ppg LOT required for kick tolerance with 11.5ppg MW) 13-3/8 Casing Test 2,600 psi surface pressure (Test pressure driven by 50% of Casing Burst) 8-1/2 Production Hole Pressure Data Maximum anticipated BHP 1,877 psi in the Nanushuk 3.2 at 4,120 TVD (8.8ppg EMW top NT3.2 to heel target) Maximum surface pressure 1,465 psi from the NT3.2 (0.10 psi/ft gas gradient to surface, 4,120 TVD) Planned BOP test pressure Rams test to 3,600 psi / 250 psi Annular test to 3,000 psi / 250 psi (Test pressure driven by annular pressure during frac job) Integrity Test 8-1/2 hole FIT after drilling 20-50 of new hole to 14.0 ppg. (10.5ppg required for kick tolerance with 10.0ppg MW) 9-5/8 Liner Test 4,000 psi surface pressure (MIT-IA after upper completion run, test pressure driven by annular pressure during frac job) (B) data on potential gas zones; and The Tuluvak formation is expected in this area and has a high potential for gas as based on offset Exploration and Appraisal well data. The Tuluvak is expected to be over-pressured at 10.1ppg pore pressure. The well plan is designed to safely manage pressures consistent with offset wells in the same manner that hydrocarbons are handled in the reservoir zone. BOPE will be installed before entering any hydrocarbon zones and appropriate mud weights will be utilized to provide sufficient overbalance. The Tuluvak is expected to be over-pressured at 10.1ppg (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please refer to Attachment 4: Drilling Hazards 5. Procedure for Conducting Formation Integrity Tests 20 AAC 25.005 (c) (5) A description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please refer to Attachment 5: Leak Off Test Procedure 6. Casing and Cementing Program 20 AAC 25.005 (c) (6) A complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Casing/Tubing Program Hole Size Liner / Tbg O.D.Wt/Ft Grade Conn Length Top MD Bottom MD / TVD 42 20x34 215# X-52 Welded 80 Surface 128 / 128 16 13-3/8 68# L-80 TXP BTC 2,884 Surface 2,884 / 2,382 12-1/4 9-5/8 47# L-80 HYD 563 9,085 2,734 11,819 / 4,039 Tie Back 9-5/8 47# L-80 HYD 563 2,734 Surface 2,734 / 2,318 8-1/2 4-1/2 12.6# P-110S HYD 563 10,671 11,669 22,357 / 4,045 Tubing 4-1/2 12.6# P-110S HYD 563 11,669 Surface 11,669 / 4007 Please refer to Attachment 6: Cement Summary for further details. 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Parker 272 Diverter Equipment: Hydril MSP annular BOP, 21 1/4 x 2000 psi, flanged Diverter Spool 21 1/4 x 2000 psi with 16-3/4 flanged sidearm connection. Interlocked knife/gate valves. 16 Diverter Line. The above diverter equipment is not planned to be used for NDBi-006 as per the diverter waiver requested as part of this application. Please refer to Section 15 for further details. 8. Drilling Fluid Program 20 AAC 25.005 (c) (8) A drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling Fluid Program Summary 16 Surface Hole 12-1/4 Int #1 Hole 8-1/2 Prod Hole Mud Type Spud Mud (WBM)MOBM MOBM Mud Properties: Mud Weight Funnel Vis PV YP API Fluid Loss HPHT Fluid Loss pH MBT 9.0 - 10 ppg 100 - 300 sec ALAP 30 - 80 < 10 ml/30min n/a 8.6-10.5 <35 11.0 - 12.0 ppg 50 - 80 sec ALAP 15 - 30 n/a < 5 ml/30min n/a n/a 9.0 - 10.0 ppg 50 - 80 sec ALAP 10 - 20 n/a < 5 ml/30min n/a n/a A diagram of drilling fluid system on Parker 272 is on file with AOGCC. 9. Abnormally Pressured Formation Information 20 AAC 25.005 (c) (9) For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); N/A Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis 20 AAC 25.005 (c) (10) For an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); N/A Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis 20 AAC 25.005 (c) (11) For a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); The NDBi-006 well is to be drilled from an onshore location. 12. Evidence of Bonding 20 AAC 25.005 (c) (12) Evidence showing that the requirements of 20 AAC 25.025 have been met; Evidence of bonding for Oil Search Alaska is on file with the Commission. 13. Proposed Drilling Program 20 AAC 25.005 (c) (13) A copy of the proposed drilling program; the drilling program must indicate if a well is proposed for hydraulic fracturing as defined in 20 AAC 25.283(m); to seek approval to perform hydraulic fracturing, a person must make a separate request by submitting an Application for Sundry Approvals (Form 10-403) with the information required under 20 AAC 25.280 and 20 AAC 25.283; The proposed drilling program to NDBi-006 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed NDBi-006 Drilling Program 1. Drill 20 conductor to ~128 MD/TVD. Cement to surface. Install Cellar and landing ring on conductor. 2. Move in / rig up Parker 272. 3. Nipple up spacer spools over the 20 conductor. 4. Pick up 5-7/8 drill pipe, fill pits with spud mud and prepare for surface hole drilling. Make up 16 motor BHA with MWD and LWD tools. 5. Spud well and drill surface hole section to TD. Perform wiper trips as required. Circulate and condition hole to run casing. POOH and lay down BHA. 6. Run 13-3/8 68# surface casing as per casing tally and land on pre-installed landing ring. Circulate and condition mud prior to commencing cement job. 7. Cement 13-3/8 casing as per cement program. Verify cement returns to surface. 8. NU casing head and spacer spool. NU BOPE with Rotating Control Device (RCD). BOP configured from top to bottom: annular preventor, 4-1/2 x 7 VBR, blind/shear, mud cross, 9-5/8 Fixed Rams. Test rams to 5000 psi high (initial test only 3600 psi for subsequent tests) and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 48 hrs notice for witnessing BOP test. 9. Close blind shear rams and pressure test casing to 2600 psi for 30 min. 10. Make up 12-1/4 RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment and displace well to MOBM. 11. Drill out shoe track and 20 - 50 of new formation. Perform FIT / LOT. 12. Directionally drill 12-1/4 intermediate hole section to TD. Perform wiper trips as required. Circulate and condition hole to run liner. POOH. 13. RU and run 9-5/8 intermediate liner as per casing tally then RIH on 5-7/8 DP / HWDP to TD. Circulate and condition mud prior to commencing cement job. 14. Set liner hanger and release running tool. Cement 9-5/8 liner with 1st stage cement job as per cement program. Monitor returns during displacement until plug bump. 15. Un-sting from liner hanger and POOH and LD liner running tools. 16. RIH with mechanical shifting tool and open 2 nd stage cement job tools. Pump secondary cement job, set liner top packer, and circulate cement to surface. POOH. 17. RIH with polish mill assembly for cleanout of the 9-5/8 liner top PBR. 18. Run 9-5/8 tieback string. Freeze protect the 13-3/8 x 9-5/8 annulus with diesel and land tieback. 19. Pressure test the 13-3/8 x 9-5/8 annulus to 2600 psi for 30 min. 20. Pressure test the 9-5/8 liner / tieback to 3500 psi for 30 min. 21. Make up 8-1/2 RSS BHA with MWD and LWD tools. RIH with 5 drillpipe. 22. Displace/condition MOBM to the required mud weight for MPD while drilling out the shoe track. 23. Circulate casing clean, install the MPD bearing assembly and test MPD surface equipment as required. 24. Drill 20 - 50 of new formation. Perform FIT / LOT. 25. Directionally drill 8-1/2 production hole section to TD using MPD. Back ream hole and perform wiper trips as required. Circulate and condition hole to run liner. 26. POOH. Log first stage cement with Sonic LWD. NOTE: See more details / justification in Attachment 6: Cement Summary. 27. Run cleanout/string mill assembly to dress the 9-5/8 CFLEX tool. 28. RU and run 4-1/2 production liner with liner hanger/top packer and downhole jewelry to TD. 29. Drop 1.125 ball, circulate in place, land ball in WIV collar. Close WIV collar and set open hole hydraulic set packers and liner hanger/top packer. 30. Set and pressure test the 9-5/8 x 7 x 4-1/2 IA to liner top packer to 3,500 psi for 10 min. Release the running tool. 31. Pull liner running tool above liner top. POOH and LD liner running tool. 32. RU and run 4-1/2 upper completion and downhole jewelry with TEC wires. 33. Circulate MOBM out of open hole with NaCl brine with biocide. 34. Space out and land PBR seals and tubing hanger. 35. Pressure test tubing to 3,500 psi for 30 mins. Pressure up on the annulus to 4,000 psi for 30 mins. Bleed pressure on tubing and shear upper gas lift valve. 36. Reverse circulate freeze protect and U-Tube. 37. Install TWC, pressure test to 2,500 psi for 10 mins. ND BOPE, NU frac tree. 38. Secure well and prepare for rig move. 14. Discussion of Mud and Cuttings Disposal and Annular Disposal 20 AAC 25.005 (c) (14) A general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. The Oil Search Alaska NGI (Nanushuk Grind & Inject) facility is now operational, and cuttings will be hauled via truck as generated, processed at NGI, and disposed of into the DW-02 Class 1 disposal well. The NGI facility is located on NDB. In the event that NGI is not operational, water-based and oil-based drilling muds and cuttings will typically be hauled directly offsite via truck as it is generated. Contractual arrangements have been made with other operators on the North Slope to utilize their waste injection/disposal facilities (Class 1 and Class 2) at Prudhoe Bay, Kuparuk and Milne Point. If waste cannot be hauled directly offsite, it may be stored temporarily in drilling waste cuttings bins or a bermed cuttings storage cell in accordance with a drilling waste temporary storage plan approved by Alaska Department of Conservation (ADEC) Solid Waste Program until it can be transported for proper disposal. There is no intention to request authorization under 20 AAC 25.080 for any annular disposal operation in the well. 15. Proposed Variance Requests 20 AAC 25.035. Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements. (h)(2) from the diverter system requirements in (c) of this section if the variance provides at least equally effective means of diverting flow away from the drill rig or if drilling experience in the near vicinity indicates that a diverter is not necessary A diverter variance is requested for the NDBi-006 surface hole section. Oil Search Alaska, LLC (OSA) has conducted internal risk assessments and determined that the risk of needing to use a diverter is negligible and operationally could pose an increase in HSE risks. NDBi-006 surface hole is surrounded by more than 20 other existing surface holes at the NDB pad location. Additionally, there are three previously drilled wells (NDB-010, NDBi-016 and NDBi-018) within 800 of the proposed NDBi-006 surface hole TD location (see attachment 11). More than 35 wells have been drilled in the NDB pad and Pikka area over the last 54 years with no signs or indications of shallow free gas above the Tuluvak. There are 16 Exploration and Appraisal wells and more than 20 NDB Pad wells totaling more than 70,000 of drilled interval. In addition, OSA has acquired eight openhole logs across the surface hole intervals in the area consisting of four E-line Density Neutron logs and four LWD Sonic logs. All logs definitively show no free gas accumulations. During this time period, there have been zero well control events above the Tuluvak. OSA has built highly detailed geological models which predict the Top of the Tuluvak with very high accuracy. There is very low structural uncertainty and a high confidence marker with the MCU given the number of wells already drilled in the area. The area around NDB is covered by 3D seismic data that was acquired in 2010 and reprocessed in 2023. The data is of adequate quality A diverter variance is requested for the NDBi-006 surface hole section Recommend granting requested diverter variance on the condition that the surface hole will not be drilled more than 250' TVD below the MCU marker. TS 10/13/25 without gaps and obvious noise trains or shallow velocity anomalies. The smallest detectable and mapped faults in the surrounding area is estimated to be 20-30. There are no observed faults in the vicinity of this hole section for the NDBi-006 well. NDBi-006 surface casing will target a maximum setting depth of 250 TVD below the MCU marker to maintain a 100 TVD standoff from the gas-bearing Tuluvak sand formation. OSA will implement drilling practices to effectively manage any hydrates encountered while drilling surface hole as follows: (1) Mitigate breakout potential: keep mud temperature cool, no extended circulation at any point in the well, optimized drilling and tripping strategies, utilization of GWD to minimize stationary time. (2) Identify hydrates (i.e. bubbles in the flow both with no signs of pit gain or flow from the well). (3) Handle hydrates at surface (i.e. utilization of degasser and isolation of gas-cut mud in the pits). (4) Drilling practices (i.e. controlling pump rates and maximizing ROP to get through a hydrate zone). Parker Rig 272's current elevated diverter rig-up introduces health, safety, and environmental (HSE) risks due to the complexities of installation at height. With the ongoing facility commissioning at NDB pad, the diverter line will need to be moved to ground level in the near future to be routed beneath the flowlines and pipe racks, passing through support pilings. This change will increase operational challenges and HSE risks, as the 75-foot diverter line will require multiple bends to navigate around existing equipment and infrastructure. With the multiple well penetrations at the NDB Pad and Pikka area, no free gas above the Tuluvak, the strong geologic understanding, and low structural uncertainty, combined with the increased HSE risks and challenges of running a diverter line, it is requested that a diverter variance for NDBi-006 be granted. 20 AAC 25.035. Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements. (e)(10)(A) when installed, repaired, or changed on a development or service well and at time intervals not to exceed each 14 days thereafter, BOPE, including kelly valves, emergency valves, and choke manifolds, must be function pressure-tested to the required working pressure specified in the approved Permit to Drill, using a non-compressible fluid, except that an annular type preventer need not be tested to more than 50 percent of its rated working pressure; however, the commission will require that the BOPE be function pressure-tested weekly, if the commission determines that a weekly BOPE pressure test interval is indicated by a particular drilling rig's BOPE performance A 21-day BOPE test schedule is planned as per the waiver acceptance letter and conditional requirements outlined in Docket Number OTH-25-010 from the AOGCC to Oil Search Alaska for Parker 272 operating at NDB (see attachment 12). 20 AAC 25.030. Casing and cementing (d)(5) intermediate and production casing must be cemented with sufficient cement to fill the annular space from the casing shoe to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above all significant hydrocarbon zones and abnormally geo- pressured strata or, if zonal coverage is not required under (a) of this section, from the casing shoe to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above the casing shoe A variance is requested to the above regulation 20 AAC 25.030 (d)(5) for the following: 1. 9-5/8 Primary Stage 1 Cement Job: The 9-5/8 primary stage 1 cement job will target a top of cement 200 feet TVD above the top of the Nanushuk formation. Due to ERD nature of this section (inclination 70-82°), additional TVD height of the cement top will significantly increase cement volumes and the subsequent risk of losses due to ECDs exceeding the formation fracture gradient. Additionally, the 200 feet TVD above the top of the Nanushuk is targeted to: a) Provide additional cement coverage above the topmost hydrocarbon zone in the NT8. The planned TOC is ~228 feet TVD (~1020 feet MD) above the top of the NT8. Logs within the Pikka NDB project area have consistently shown that there are no significant hydrocarbon zones between the top NT8 and the top Nanushuk formation. b) Allow the use of a single heavier tail slurry to provide the improved cement integrity and isolation across the top of the Nanushuk. Note, improved cement bond log quality has generally been observed with heavier weight tail slurries. Additional cement volume / excess may be pumped to help ensure the targeted top of cement is achieved based on detailed cement modelling or operational conditions (i.e. lost circulation, low fracture gradient or excessive washout) observed prior to execution of the cement job. 2. 9-5/8 Primary Stage 2 Cement Job: A variance is requested to the above regulation 20 AAC 25.030 (d)(5) to not place cement across the entire annular space from the casing shoe to above the shallowest significant hydrocarbon zone. A two-stage cement job will be performed to isolate the significant hydrocarbon zone in the Nanushuk formation (primary job), and the second stage cement job will isolate the significant hydrocarbon zone in the Tuluvak formation. The first stage primary cement job will target a top of cement 200 TVD, above the top of the Nanushuk. Due to the ERD nature and high angle of the Pikka NDB development wells, a single stage cement job on the intermediate liner is not achievable without exceeding the fracture gradient and compromising cement placement and zonal isolation. The two-stage cement job will achieve all casing and cementing objectives outlined in AOGCC regulation 20 AAC 25.030.(a), stating that a well casing and cementing program must be designed to: a) provide suitable and safe operating conditions for the total measured depth proposed; b) confine fluids to the wellbore; c) prevent migration of fluids from one stratum to another; d) ensure control of well pressures encountered; e) protect against thaw subsidence and freezeback effects within permafrost; f) prevent contamination of freshwater; g) protect significant hydrocarbon zones; and h) provide well control until the next casing is set, considering all factors relevant to well control including formation fracture gradients, formation pressures, casing setting depths, and proposed total depth. The formation interval between the top of stage one and the bottom of stage two includes the Seabee and lower Tuluvak formation. These formations are interbedded silts and shales with very low permeability and contain no significant hydrocarbons. Based on offset well logs, cuttings, mudlogging analysis, and the latest petrophysical interpretation, the base of the significant hydrocarbon zone in the Tuluvak formation is contained only within the upper portion of TS 880 clinoform of the Upper Tuluvak in the NDB area. Within the TS 880 clinoform, the base of significant hydrocarbon is at or above 2,813 TVD. The Tuluvak formation below 2,813 TVD is not a significant hydrocarbon zone. A stage collar placement is proposed 50 MD below the TS 790 formation marker (Upper Tuluvak). This stage collar depth will isolate any potential gas based on offset well data. The TS 875 and TS 870 clinoform is between the TS 880 clinoform and TS 790 top. The TS 875 and TS 870 clinoforms are shale dominated, very low net to gross, has no vertical permeability, and represents a seal to the hydrocarbon bearing TS 880. Moving the cementing stage tool to be placed at 50 MD below the TS 790 formation marker allows placement of higher quality cement that provides better isolation across the significant hydrocarbon zone in the Tuluvak. Attempting to place cement across the entire Tuluvak will add risk to the primary objective of cement isolation across the significant hydrocarbon zone which is only located in the upper portion of the Tuluvak (TS 880). The increased risk is due to: a) Cementing the entire Tuluvak would require large cement jobs that jeopardize cement isolation across the upper Tuluvak. b) Large cement jobs likely require the use of lighter weight cement across the significant hydrocarbon zone. Recommend approving variance for two stage cement job. TS 10/13/24 Attachments Attachment 1: Location Maps ADL 392963ADL 392984ADL 393021 ADL 393019 ADL 393018 ADL 393020 ADL 393015 ADL 393017ADL 393016 ADL 393006 ADL 393007 ADL 393008 ADL 391322 ADL 391445 ADL 391453 ADL 391454 ADL 391455 ADL 393009 ADL 393011 ADL 393010 FIORD 3A FIORD 3 QUGRUK 301 QUGRUK 3A QUGRUK 7 DW-02 NDB-010 NDB-011 NDB-024 NDB-025 NDB-032 NDB-037 NDB-051 NDBi-014 NDBi-016 NDBi-018 NDBi-030 NDBi-043A NDBi-044 NDBi-049 OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD 0.25-MILE BUFFER 0.5-MILE BUFFER NDBI-006 SURFACE LOCATION NDBI-006 BOTTOM HOLE NDB DRILLED WELLS BOTTOM HOLES NDBI-006 TRAJECTORY OTHER DRILLED NDB WELLS EXPLORATION WELLS BOTTOM HOLES WELL TRAJECTORIES BY OTHERS SANTOS LEASES SECTIONS DATE: 9/19/2025. By: JB 0 0.1 0.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDBi06_buffers Map Frame: AP-DRL-GEN-M_NDBi-006-12_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 0.2 0.4 Kilometers PIKKA DEVELOPMENT NDBi-006 WELL Attachment 2: Directional Plan SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 47.0 0.00 0.00 47.0 0.0 0.0 0.00 0.00 0.0 2 347.0 0.00 354.00 347.0 0.0 0.0 0.00 354.00 0.0 Start Build 2.50 3 998.7 16.29 354.00 990.0 91.5 -9.6 2.50 354.00 88.9 Start 160.0 hold at 998.7 MD 4 1158.7 16.29 354.00 1143.6 136.2 -14.3 0.00 0.00 132.3 Start Build 3.00 5 2782.3 65.00 354.00 2338.7 1156.6 -121.6 3.00 0.00 1123.7 6 2882.3 65.00 354.00 2380.9 1246.7 -131.0 0.00 0.00 1211.2 7 3476.6 81.27 346.35 2553.0 1804.5 -229.3 3.00 -25.44 1767.3 8 7239.1 81.27 346.35 3123.8 5418.5 -1106.7 0.00 0.00 5456.2 Target 1: Shallow Fault Avoidance Rev 0.0 9 7541.9 78.44 351.79 3177.2 5711.0 -1163.2 2.00 118.37 5749.6 10 11132.5 78.44 351.79 3896.8 9192.7 -1665.4 0.00 0.00 9180.9 11 11858.3 78.00 329.55 4046.8 9858.6 -1898.9 3.00 -93.44 9886.3 12 12037.4 78.00 329.55 4084.1 10009.6 -1987.7 0.00 0.00 10059.0 13 12382.8 90.09 329.55 4119.8 10305.2 -2161.5 3.50 0.00 10397.2 NDBi-012 Heel Rev 6.0 14 20561.0 90.09 329.55 4106.8 17355.3 -6306.2 0.00 0.00 18462.9 NDBi-06 Inc Change Rev 2.0 15 20860.3 96.02 328.71 4090.9 17611.7 -6459.5 2.00 -8.06 18757.2 16 21479.5 90.66 329.15 4054.8 18141.0 -6778.4 0.87 175.26 19365.4 Fault Block Rev 2.0 17 22357.2 90.65 329.14 4044.8 18894.5 -7228.5 0.00 -143.63 20230.0 NDBi-012 Toe Rev 6.0 47 310 310 510 510 760 760 1010 1010 1260 1260 1510 1510 1760 1760 2010 2010 2510 2510 3010 3010 3510 3510 4510 4510 5510 5510 6510 6510 7510 7510 8510 8510 9510 9510 11010 11010 12010 12010 13010 13010 14010 14010 15010 15010 16010 16010 17010 17010 18010 Plan: NDBi-06 Rev L.0 Plan Summary 0 3 0 3500 7000 10500 14000 17500 21000 Measured Depth 16" Conductor Casing13-3/8" Surface Casing 9-5/8" Intermediate Liner 4-1/2" Production Liner 45 45 90 90 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in] 7075100125150175200225250275300325350375400425450476501526551 Plan: NDB-01 Rev A.07075100125150175200225250275300325350 375400425450475501526551576601626651676701725 Plan: NDB-02 Rev A.04750751001251501752002252502753003253503754004254504755005265515766016266516767017277527778028278528789039289539781004102810531078110311281153117812031228Plan: NDB-05 to 3 Rev B.0 7075100125150175200225250275300325350375400425450475500525550576601626651676701726751776801827852877902927952978100310281053107811021127115211771202122812531279130413301355138114061432Plan: NDBi-07 to 4 Rev A.0 475075100125150175200225250275300325350375400425450475500525550575600625650675700725750775800826851876901926951976100110261051107611011126115111761201122712521277130213281353137814031429145414791505153015561581160616321657168317081734175917851810183618611887191219381963198920142040206520912117214221682193221922452270229623222347237323992424245024762501Plan: NDB-04&9 to 5 Rev B.0 7075100125150175200225250275300325350375400425450474499524549574598623648672697721745769793817841865889912936959982Plan: NDB-03 to 7 Slot Saver 475075100125150175200225250275300325350375400425449474499524549573598623647672696720745769793817841864888911935958981NDB-08 Slot Saver 7075100125150175200225250275300325350375400424449474499524549574599624649674698723748773798823848873898923948973998102310481073109811231147117211971223124812731298132413491374140014251451Plan: NDB-09 Rev A.0 475075100125150175200225250275300325350375 400425450474499524549574599623648673698722747772797821846871895920945969994101910441069109411191144116811931217NDB-010 475075100125150175200225250275300325350375 400425450475499524549574599624648673698723747772797821846871896920945970994101910441069109411191144116911931217Plan: NDB-010 Rev G.0 475075100125150175200225250275300325350375400424449474498523547572NDB-011 475075100125150175200225250275300325350375400424449474498523547Plan: NDB-011 Rev F.2 0 2250 0 3000 6000 9000 12000 15000 18000 21000 Vertical Section at 339.06° 16" Conductor Casing 13-3/8" Surface Casing 9-5/8" Intermediate Liner 4-1/2" Production Liner 0 28 55 0 275 550 825 1100 1375 1650 1925 Measured Depth Equivalent Magnetic Distance DDI 7.380 SURVEY PROGRAM Date: 2021-02-16T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 47.0 1000.0 Plan: NDBi-06 Rev L.0 (NDBi-06) SDI_URSA+SAG 1000.0 2884.0 Plan: NDBi-06 Rev L.0 (NDBi-06) 3_MWD+IFR2+MS+Sag 2884.0 11819.0 Plan: NDBi-06 Rev L.0 (NDBi-06) 3_MWD+IFR2+MS+Sag 11819.0 22357.2 Plan: NDBi-06 Rev L.0 (NDBi-06) 3_MWD+IFR2+MS+Sag Surface Location North / 5972633.87 East / 1562650.31 Elevation / 22.8 CASING DETAILS TVD MD Name 128.0 128.0 16" Conductor Casing 2381.6 2884.013-3/8" Surface Casing 4038.7 11819.09-5/8" Intermediate Liner 4044.8 22357.24-1/2" Production Liner Mag Model & Date: BGGM2025 31-Dec-25 Magnetic North is 13.41° East of True North (Magnetic De Mag Dip & Field Strength: 80.52°57092.61335 FORMATION TOP DETAILS TVDPathFormation 1048.9 Upper SB 1143.7Base Ice Bearing Permafrost 1391.4 BP Transition1744.0 Middle SB 2131.7 MCU 2460.3 Tuluvak Shale 2526.5 Tuluvak Sand 2812.8 TS_790 3158.2 Seabee 3793.8 Nanushuk 3814.7 NT8 MFS 3850.1 NT7 MFS 3907.0 NT6 MFS 3934.7Upper Bound SM_NDB_018 Fault 3958.7 NT5 MFS 4013.9 NT4 MFS 4016.6 NT3 MFS 4038.7Lower Bound SM_NDB_018 Fault 4054.2NT3.2 Top Reservoir 4088.0Lower Bound SM_NDB_021 Fault 4107.1Upper Bound SM_NDB_021 Fault By signing this I acknowledge that I have been informed of all risks, checked that the data is correct, ensured it's completeness, and all surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance. Prepared by Checked by BHI DE Accepted by BHI PSD Approved by Santos DE Parker 272 @ 69.8usft Standard Planning Report - Geographic 29 September, 2025 Plan: Plan: NDBi-06 Rev L.0 Santos NAD27 Conversion Pikka NDB B-06 NDBi-06 Santos Ltd Planning Report - Geographic Well B-06Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-06Well: NDBi-06Wellbore: Plan: NDBi-06 Rev L.0Design: Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Pikka, North Slope Alaska, United States Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: NDB Map Slot Radius:0.9 usft usft usft " 5,972,909.31 423,383.61 36 70° 20' 10.134 N 150° 37' 17.794 W Well Well Position Longitude: Latitude: Easting: Northing: +E/-W +N/-S Position Uncertainty Ground Level: B-06 Wellhead Elevation:0.5 0.0 0.0 5,972,885.86 422,617.52 70° 20' 9.826 N 150° 37' 40.161 W 22.8 usft usft usft usft usft usft usft °-0.59Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NDBi-06 Model NameMagnetics BGGM2025 31/12/2025 13.41 80.52 57,092.61328437 Phase:Version: Audit Notes: Design Plan: NDBi-06 Rev L.0 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:47.0 339.060.00.047.0 Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Date 29/09/2025 Depth To (usft) Depth From (usft) SDI_URSA+SAG SDI URSA gyroMWD + SAG Plan: NDBi-06 Rev L.0 (NDBi-06147.0 1,000.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-06 Rev L.0 (NDBi-0621,000.0 2,884.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-06 Rev L.0 (NDBi-0632,884.0 11,819.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-06 Rev L.0 (NDBi-06411,819.0 22,357.2 29/09/2025 15:15:54 COMPASS 5000.17 Build Page 2 Santos Ltd Planning Report - Geographic Well B-06Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-06Well: NDBi-06Wellbore: Plan: NDBi-06 Rev L.0Design: Inclination (°) Azimuth (°) +E/-W (usft) TFO (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections Target 0.000.000.000.000.00.047.00.000.0047.0 354.000.000.000.000.00.0347.0354.000.00347.0 354.000.002.502.50-9.691.5990.0354.0016.29998.7 0.000.000.000.00-14.3136.21,143.6354.0016.291,158.7 0.000.003.003.00-121.61,156.62,338.7354.0065.002,782.3 0.000.000.000.00-131.01,246.72,380.9354.0065.002,882.3 -25.44-1.292.743.00-229.31,804.52,553.0346.3581.273,476.6 0.000.000.000.00-1,106.75,418.53,123.8346.3581.277,239.1 118.371.80-0.942.00-1,163.25,711.03,177.2351.7978.447,541.9 0.000.000.000.00-1,665.49,192.73,896.8351.7978.4411,132.5 -93.44-3.06-0.063.00-1,898.99,858.64,046.8329.5578.0011,858.3 0.000.000.000.00-1,987.710,009.64,084.1329.5578.0012,037.4 0.000.000.003.50-2,161.510,305.24,119.8329.5590.0912,382.8 0.000.000.000.00-6,306.217,355.34,106.8329.5590.0920,561.0 -8.06-0.281.982.00-6,459.517,611.74,090.9328.7196.0220,860.3 175.260.07-0.870.87-6,778.418,141.04,054.8329.1590.6621,479.5 -143.630.000.000.00-7,228.518,894.54,044.8329.1490.6522,357.2 29/09/2025 15:15:54 COMPASS 5000.17 Build Page 3 Santos Ltd Planning Report - Geographic Well B-06Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-06Well: NDBi-06Wellbore: Plan: NDBi-06 Rev L.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 47.0 0.00 47.0 0.0 0.00.00 422,617.525,972,885.86 70° 20' 9.826 N 150° 37' 40.161 W 100.0 0.00 100.0 0.0 0.00.00 422,617.525,972,885.86 70° 20' 9.826 N 150° 37' 40.161 W 128.0 0.00 128.0 0.0 0.00.00 422,617.525,972,885.86 70° 20' 9.826 N 150° 37' 40.161 W 16" Conductor Casing 200.0 0.00 200.0 0.0 0.00.00 422,617.525,972,885.86 70° 20' 9.826 N 150° 37' 40.161 W 300.0 0.00 300.0 0.0 0.00.00 422,617.525,972,885.86 70° 20' 9.826 N 150° 37' 40.161 W 347.0 0.00 347.0 0.0 0.0354.00 422,617.525,972,885.86 70° 20' 9.826 N 150° 37' 40.161 W 347.2 0.00 347.2 0.0 0.0354.00 422,617.525,972,885.86 70° 20' 9.826 N 150° 37' 40.161 W Start Build 2.50 400.0 1.33 400.0 0.6 -0.1354.00 422,617.465,972,886.47 70° 20' 9.832 N 150° 37' 40.163 W 500.0 3.83 499.9 5.1 -0.5354.00 422,617.045,972,890.95 70° 20' 9.876 N 150° 37' 40.177 W 600.0 6.33 599.5 13.9 -1.5354.00 422,616.205,972,899.75 70° 20' 9.962 N 150° 37' 40.204 W 700.0 8.83 698.6 27.0 -2.8354.00 422,614.965,972,912.87 70° 20' 10.091 N 150° 37' 40.244 W 800.0 11.33 797.1 44.4 -4.7354.00 422,613.315,972,930.29 70° 20' 10.262 N 150° 37' 40.298 W 900.0 13.83 894.6 66.0 -6.9354.00 422,611.265,972,951.96 70° 20' 10.475 N 150° 37' 40.364 W 998.7 16.29 990.0 91.5 -9.6354.00 422,608.845,972,977.50 70° 20' 10.726 N 150° 37' 40.442 W 999.0 16.29 990.2 91.6 -9.6354.00 422,608.845,972,977.56 70° 20' 10.727 N 150° 37' 40.443 W Start 160.0 hold at 998.7 MD 1,000.0 16.29 991.2 91.9 -9.7354.00 422,608.815,972,977.85 70° 20' 10.730 N 150° 37' 40.443 W 1,060.2 16.29 1,048.9 108.7 -11.4354.00 422,607.225,972,994.65 70° 20' 10.895 N 150° 37' 40.495 W Upper Schrader Bluff 1,100.0 16.29 1,087.2 119.8 -12.6354.00 422,606.175,973,005.78 70° 20' 11.004 N 150° 37' 40.529 W 1,158.7 16.29 1,143.6 136.2 -14.3354.00 422,604.615,973,022.18 70° 20' 11.165 N 150° 37' 40.579 W 1,158.9 16.29 1,143.7 136.2 -14.3354.00 422,604.615,973,022.23 70° 20' 11.166 N 150° 37' 40.580 W Start Build 3.00 - Base Ice Bearing Permafrost 1,200.0 17.53 1,183.0 148.1 -15.6354.00 422,603.485,973,034.13 70° 20' 11.283 N 150° 37' 40.616 W 1,300.0 20.53 1,277.6 180.6 -19.0354.00 422,600.415,973,066.59 70° 20' 11.602 N 150° 37' 40.716 W 1,400.0 23.53 1,370.2 217.9 -22.9354.00 422,596.875,973,103.92 70° 20' 11.969 N 150° 37' 40.830 W 1,423.2 24.23 1,391.4 227.2 -23.9354.00 422,595.995,973,113.26 70° 20' 12.060 N 150° 37' 40.859 W Base Permafrost Transition 1,500.0 26.53 1,460.8 259.9 -27.3354.00 422,592.895,973,146.04 70° 20' 12.382 N 150° 37' 40.959 W 1,600.0 29.53 1,549.1 306.7 -32.2354.00 422,588.465,973,192.81 70° 20' 12.842 N 150° 37' 41.103 W 1,700.0 32.53 1,634.8 357.9 -37.6354.00 422,583.605,973,244.13 70° 20' 13.346 N 150° 37' 41.260 W 1,800.0 35.53 1,717.6 413.6 -43.5354.00 422,578.325,973,299.83 70° 20' 13.894 N 150° 37' 41.431 W 1,832.5 36.51 1,744.0 432.6 -45.5354.00 422,576.525,973,318.87 70° 20' 14.081 N 150° 37' 41.489 W Middle Schrader Bluff 1,900.0 38.53 1,797.5 473.5 -49.8354.00 422,572.655,973,359.77 70° 20' 14.483 N 150° 37' 41.615 W 2,000.0 41.53 1,874.0 537.4 -56.5354.00 422,566.595,973,423.80 70° 20' 15.112 N 150° 37' 41.811 W 2,100.0 44.53 1,947.1 605.3 -63.6354.00 422,560.165,973,491.72 70° 20' 15.779 N 150° 37' 42.019 W 2,200.0 47.53 2,016.5 676.9 -71.1354.00 422,553.375,973,563.35 70° 20' 16.483 N 150° 37' 42.239 W 2,300.0 50.53 2,082.1 751.9 -79.0354.00 422,546.265,973,638.51 70° 20' 17.221 N 150° 37' 42.470 W 2,380.2 52.94 2,131.7 814.5 -85.6354.00 422,540.325,973,701.16 70° 20' 17.837 N 150° 37' 42.662 W MCU 2,400.0 53.53 2,143.6 830.3 -87.3354.00 422,538.835,973,716.98 70° 20' 17.992 N 150° 37' 42.710 W 2,500.0 56.53 2,200.9 911.8 -95.8354.00 422,531.105,973,798.54 70° 20' 18.794 N 150° 37' 42.961 W 2,600.0 59.53 2,253.9 996.2 -104.7354.00 422,523.115,973,882.98 70° 20' 19.623 N 150° 37' 43.220 W 2,700.0 62.53 2,302.3 1,083.2 -113.8354.00 422,514.865,973,970.06 70° 20' 20.479 N 150° 37' 43.487 W 2,749.2 64.01 2,324.4 1,126.9 -118.4354.00 422,510.735,974,013.77 70° 20' 20.908 N 150° 37' 43.621 W Start 100.0 hold at 2749.0 MD 2,782.3 65.00 2,338.7 1,156.6 -121.6354.00 422,507.915,974,043.53 70° 20' 21.201 N 150° 37' 43.712 W 2,800.0 65.00 2,346.1 1,172.5 -123.2354.00 422,506.405,974,059.51 70° 20' 21.358 N 150° 37' 43.761 W 2,849.2 65.00 2,366.9 1,216.9 -127.9354.00 422,502.205,974,103.87 70° 20' 21.794 N 150° 37' 43.897 W Start DLS 3.00 TFO 3.27 2,882.3 65.00 2,380.9 1,246.7 -131.0354.00 422,499.375,974,133.75 70° 20' 22.087 N 150° 37' 43.989 W 2,884.0 65.05 2,381.6 1,248.3 -131.2353.98 422,499.225,974,135.30 70° 20' 22.103 N 150° 37' 43.994 W 13-3/8" Surface Casing 2,900.0 65.48 2,388.3 1,262.7 -132.8353.75 422,497.825,974,149.76 70° 20' 22.245 N 150° 37' 44.039 W 3,000.0 68.20 2,427.7 1,354.0 -143.9352.37 422,487.645,974,241.11 70° 20' 23.142 N 150° 37' 44.364 W 29/09/2025 15:15:54 COMPASS 5000.17 Build Page 4 Santos Ltd Planning Report - Geographic Well B-06Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-06Well: NDBi-06Wellbore: Plan: NDBi-06 Rev L.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 3,093.1 70.74 2,460.3 1,440.2 -156.4351.13 422,476.015,974,327.49 70° 20' 23.990 N 150° 37' 44.730 W Tuluvak Shale 3,100.0 70.93 2,462.6 1,446.7 -157.4351.04 422,475.065,974,333.95 70° 20' 24.054 N 150° 37' 44.759 W 3,200.0 73.66 2,493.0 1,540.6 -173.3349.75 422,460.135,974,428.02 70° 20' 24.978 N 150° 37' 45.224 W 3,300.0 76.41 2,518.8 1,635.5 -191.5348.50 422,442.885,974,523.05 70° 20' 25.910 N 150° 37' 45.757 W 3,334.0 77.35 2,526.5 1,667.9 -198.3348.08 422,436.495,974,555.56 70° 20' 26.230 N 150° 37' 45.953 W Tuluvak Sand 3,400.0 79.16 2,540.0 1,731.0 -212.1347.28 422,423.355,974,618.80 70° 20' 26.850 N 150° 37' 46.356 W 3,476.6 81.27 2,553.0 1,804.5 -229.3346.35 422,406.905,974,692.46 70° 20' 27.573 N 150° 37' 46.859 W 3,478.9 81.27 2,553.3 1,806.7 -229.8346.35 422,406.395,974,694.63 70° 20' 27.594 N 150° 37' 46.874 W Start 12067.7 hold at 3478.7 MD 3,500.0 81.27 2,556.5 1,827.0 -234.7346.35 422,401.675,974,714.99 70° 20' 27.794 N 150° 37' 47.018 W 3,600.0 81.27 2,571.7 1,923.0 -258.1346.35 422,379.355,974,811.26 70° 20' 28.739 N 150° 37' 47.700 W 3,700.0 81.27 2,586.9 2,019.1 -281.4346.35 422,357.025,974,907.54 70° 20' 29.683 N 150° 37' 48.381 W 3,800.0 81.27 2,602.0 2,115.1 -304.7346.35 422,334.705,975,003.82 70° 20' 30.628 N 150° 37' 49.062 W 3,900.0 81.27 2,617.2 2,211.2 -328.0346.35 422,312.375,975,100.10 70° 20' 31.573 N 150° 37' 49.743 W 4,000.0 81.27 2,632.4 2,307.2 -351.3346.35 422,290.055,975,196.38 70° 20' 32.517 N 150° 37' 50.425 W 4,100.0 81.27 2,647.6 2,403.3 -374.6346.35 422,267.725,975,292.66 70° 20' 33.462 N 150° 37' 51.106 W 4,200.0 81.27 2,662.7 2,499.3 -398.0346.35 422,245.405,975,388.94 70° 20' 34.407 N 150° 37' 51.788 W 4,300.0 81.27 2,677.9 2,595.4 -421.3346.35 422,223.075,975,485.21 70° 20' 35.351 N 150° 37' 52.469 W 4,400.0 81.27 2,693.1 2,691.4 -444.6346.35 422,200.755,975,581.49 70° 20' 36.296 N 150° 37' 53.150 W 4,500.0 81.27 2,708.2 2,787.5 -467.9346.35 422,178.435,975,677.77 70° 20' 37.241 N 150° 37' 53.832 W 4,600.0 81.27 2,723.4 2,883.5 -491.2346.35 422,156.105,975,774.05 70° 20' 38.185 N 150° 37' 54.513 W 4,700.0 81.27 2,738.6 2,979.6 -514.6346.35 422,133.785,975,870.33 70° 20' 39.130 N 150° 37' 55.195 W 4,800.0 81.27 2,753.8 3,075.6 -537.9346.35 422,111.455,975,966.61 70° 20' 40.074 N 150° 37' 55.876 W 4,900.0 81.27 2,768.9 3,171.7 -561.2346.35 422,089.135,976,062.89 70° 20' 41.019 N 150° 37' 56.558 W 5,000.0 81.27 2,784.1 3,267.7 -584.5346.35 422,066.805,976,159.17 70° 20' 41.964 N 150° 37' 57.239 W 5,100.0 81.27 2,799.3 3,363.8 -607.8346.35 422,044.485,976,255.44 70° 20' 42.908 N 150° 37' 57.921 W 5,189.2 81.27 2,812.8 3,449.5 -628.6346.35 422,024.565,976,341.36 70° 20' 43.751 N 150° 37' 58.529 W TS_790 5,200.0 81.27 2,814.5 3,459.9 -631.2346.35 422,022.155,976,351.72 70° 20' 43.853 N 150° 37' 58.602 W 5,300.0 81.27 2,829.6 3,555.9 -654.5346.35 421,999.835,976,448.00 70° 20' 44.798 N 150° 37' 59.284 W 5,400.0 81.27 2,844.8 3,652.0 -677.8346.35 421,977.505,976,544.28 70° 20' 45.742 N 150° 37' 59.966 W 5,500.0 81.27 2,860.0 3,748.0 -701.1346.35 421,955.185,976,640.56 70° 20' 46.687 N 150° 38' 0.647 W 5,600.0 81.27 2,875.1 3,844.1 -724.4346.35 421,932.855,976,736.84 70° 20' 47.632 N 150° 38' 1.329 W 5,700.0 81.27 2,890.3 3,940.1 -747.8346.35 421,910.535,976,833.12 70° 20' 48.576 N 150° 38' 2.010 W 5,800.0 81.27 2,905.5 4,036.2 -771.1346.35 421,888.205,976,929.40 70° 20' 49.521 N 150° 38' 2.692 W 5,900.0 81.27 2,920.7 4,132.2 -794.4346.35 421,865.885,977,025.67 70° 20' 50.466 N 150° 38' 3.374 W 6,000.0 81.27 2,935.8 4,228.3 -817.7346.35 421,843.555,977,121.95 70° 20' 51.410 N 150° 38' 4.056 W 6,100.0 81.27 2,951.0 4,324.3 -841.0346.35 421,821.235,977,218.23 70° 20' 52.355 N 150° 38' 4.737 W 6,200.0 81.27 2,966.2 4,420.4 -864.3346.35 421,798.915,977,314.51 70° 20' 53.299 N 150° 38' 5.419 W 6,300.0 81.27 2,981.3 4,516.4 -887.7346.35 421,776.585,977,410.79 70° 20' 54.244 N 150° 38' 6.101 W 6,400.0 81.27 2,996.5 4,612.5 -911.0346.35 421,754.265,977,507.07 70° 20' 55.189 N 150° 38' 6.783 W 6,500.0 81.27 3,011.7 4,708.5 -934.3346.35 421,731.935,977,603.35 70° 20' 56.133 N 150° 38' 7.464 W 6,600.0 81.27 3,026.9 4,804.6 -957.6346.35 421,709.615,977,699.63 70° 20' 57.078 N 150° 38' 8.146 W 6,700.0 81.27 3,042.0 4,900.6 -980.9346.35 421,687.285,977,795.90 70° 20' 58.023 N 150° 38' 8.828 W 6,800.0 81.27 3,057.2 4,996.7 -1,004.3346.35 421,664.965,977,892.18 70° 20' 58.967 N 150° 38' 9.510 W 6,900.0 81.27 3,072.4 5,092.7 -1,027.6346.35 421,642.635,977,988.46 70° 20' 59.912 N 150° 38' 10.192 W 7,000.0 81.27 3,087.6 5,188.8 -1,050.9346.35 421,620.315,978,084.74 70° 21' 0.857 N 150° 38' 10.874 W 7,100.0 81.27 3,102.7 5,284.8 -1,074.2346.35 421,597.985,978,181.02 70° 21' 1.801 N 150° 38' 11.555 W 7,200.0 81.27 3,117.9 5,380.9 -1,097.5346.35 421,575.665,978,277.30 70° 21' 2.746 N 150° 38' 12.237 W 7,239.1 81.27 3,123.8 5,418.5 -1,106.7346.35 421,566.935,978,314.94 70° 21' 3.115 N 150° 38' 12.504 W 7,300.0 80.70 3,133.4 5,477.0 -1,120.3347.44 421,553.905,978,373.65 70° 21' 3.691 N 150° 38' 12.903 W 7,400.0 79.76 3,150.4 5,573.5 -1,140.2349.23 421,534.975,978,470.35 70° 21' 4.640 N 150° 38' 13.486 W 7,443.2 79.35 3,158.2 5,615.4 -1,147.9350.01 421,527.755,978,512.25 70° 21' 5.052 N 150° 38' 13.710 W Seabee 7,500.0 78.83 3,168.9 5,670.3 -1,157.1351.03 421,519.135,978,567.31 70° 21' 5.592 N 150° 38' 13.978 W 7,541.9 78.44 3,177.2 5,711.0 -1,163.2351.79 421,513.425,978,608.01 70° 21' 5.992 N 150° 38' 14.158 W 7,600.0 78.44 3,188.8 5,767.3 -1,171.3351.79 421,505.885,978,664.40 70° 21' 6.546 N 150° 38' 14.395 W 29/09/2025 15:15:54 COMPASS 5000.17 Build Page 5 Santos Ltd Planning Report - Geographic Well B-06Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-06Well: NDBi-06Wellbore: Plan: NDBi-06 Rev L.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 7,700.0 78.44 3,208.9 5,864.3 -1,185.3351.79 421,492.895,978,761.50 70° 21' 7.499 N 150° 38' 14.805 W 7,800.0 78.44 3,228.9 5,961.2 -1,199.3351.79 421,479.905,978,858.59 70° 21' 8.453 N 150° 38' 15.214 W 7,900.0 78.44 3,249.0 6,058.2 -1,213.3351.79 421,466.925,978,955.69 70° 21' 9.407 N 150° 38' 15.623 W 8,000.0 78.44 3,269.0 6,155.2 -1,227.3351.79 421,453.935,979,052.79 70° 21' 10.360 N 150° 38' 16.033 W 8,100.0 78.44 3,289.1 6,252.1 -1,241.3351.79 421,440.955,979,149.89 70° 21' 11.314 N 150° 38' 16.442 W 8,200.0 78.44 3,309.1 6,349.1 -1,255.2351.79 421,427.965,979,246.98 70° 21' 12.268 N 150° 38' 16.851 W 8,300.0 78.44 3,329.1 6,446.1 -1,269.2351.79 421,414.985,979,344.08 70° 21' 13.221 N 150° 38' 17.260 W 8,400.0 78.44 3,349.2 6,543.0 -1,283.2351.79 421,401.995,979,441.18 70° 21' 14.175 N 150° 38' 17.670 W 8,500.0 78.44 3,369.2 6,640.0 -1,297.2351.79 421,389.015,979,538.28 70° 21' 15.129 N 150° 38' 18.079 W 8,600.0 78.44 3,389.3 6,737.0 -1,311.2351.79 421,376.025,979,635.37 70° 21' 16.082 N 150° 38' 18.489 W 8,700.0 78.44 3,409.3 6,833.9 -1,325.2351.79 421,363.045,979,732.47 70° 21' 17.036 N 150° 38' 18.898 W 8,800.0 78.44 3,429.3 6,930.9 -1,339.2351.79 421,350.055,979,829.57 70° 21' 17.990 N 150° 38' 19.307 W 8,900.0 78.44 3,449.4 7,027.9 -1,353.2351.79 421,337.075,979,926.67 70° 21' 18.943 N 150° 38' 19.717 W 9,000.0 78.44 3,469.4 7,124.8 -1,367.1351.79 421,324.085,980,023.76 70° 21' 19.897 N 150° 38' 20.126 W 9,100.0 78.44 3,489.5 7,221.8 -1,381.1351.79 421,311.105,980,120.86 70° 21' 20.850 N 150° 38' 20.535 W 9,200.0 78.44 3,509.5 7,318.8 -1,395.1351.79 421,298.115,980,217.96 70° 21' 21.804 N 150° 38' 20.945 W 9,300.0 78.44 3,529.6 7,415.7 -1,409.1351.79 421,285.135,980,315.06 70° 21' 22.758 N 150° 38' 21.354 W 9,400.0 78.44 3,549.6 7,512.7 -1,423.1351.79 421,272.145,980,412.15 70° 21' 23.711 N 150° 38' 21.764 W 9,500.0 78.44 3,569.6 7,609.7 -1,437.1351.79 421,259.165,980,509.25 70° 21' 24.665 N 150° 38' 22.173 W 9,600.0 78.44 3,589.7 7,706.6 -1,451.1351.79 421,246.175,980,606.35 70° 21' 25.619 N 150° 38' 22.583 W 9,700.0 78.44 3,609.7 7,803.6 -1,465.1351.79 421,233.195,980,703.44 70° 21' 26.572 N 150° 38' 22.992 W 9,800.0 78.44 3,629.8 7,900.6 -1,479.1351.79 421,220.205,980,800.54 70° 21' 27.526 N 150° 38' 23.402 W 9,900.0 78.44 3,649.8 7,997.5 -1,493.0351.79 421,207.225,980,897.64 70° 21' 28.479 N 150° 38' 23.811 W 10,000.0 78.44 3,669.9 8,094.5 -1,507.0351.79 421,194.235,980,994.74 70° 21' 29.433 N 150° 38' 24.221 W 10,100.0 78.44 3,689.9 8,191.5 -1,521.0351.79 421,181.255,981,091.83 70° 21' 30.387 N 150° 38' 24.630 W 10,200.0 78.44 3,709.9 8,288.4 -1,535.0351.79 421,168.265,981,188.93 70° 21' 31.340 N 150° 38' 25.040 W 10,300.0 78.44 3,730.0 8,385.4 -1,549.0351.79 421,155.285,981,286.03 70° 21' 32.294 N 150° 38' 25.449 W 10,400.0 78.44 3,750.0 8,482.4 -1,563.0351.79 421,142.295,981,383.13 70° 21' 33.248 N 150° 38' 25.859 W 10,500.0 78.44 3,770.1 8,579.3 -1,577.0351.79 421,129.305,981,480.22 70° 21' 34.201 N 150° 38' 26.268 W 10,600.0 78.44 3,790.1 8,676.3 -1,591.0351.79 421,116.325,981,577.32 70° 21' 35.155 N 150° 38' 26.678 W 10,618.3 78.44 3,793.8 8,694.0 -1,593.5351.79 421,113.955,981,595.05 70° 21' 35.329 N 150° 38' 26.753 W Nanushuk 10,700.0 78.44 3,810.2 8,773.3 -1,604.9351.79 421,103.335,981,674.42 70° 21' 36.109 N 150° 38' 27.088 W 10,722.7 78.44 3,814.7 8,795.3 -1,608.1351.79 421,100.385,981,696.49 70° 21' 36.325 N 150° 38' 27.181 W NT8 MFS 10,800.0 78.44 3,830.2 8,870.2 -1,618.9351.79 421,090.355,981,771.52 70° 21' 37.062 N 150° 38' 27.497 W 10,899.5 78.44 3,850.1 8,966.7 -1,632.8351.79 421,077.435,981,868.14 70° 21' 38.011 N 150° 38' 27.905 W NT7 MFS 10,900.0 78.44 3,850.2 8,967.2 -1,632.9351.79 421,077.365,981,868.61 70° 21' 38.016 N 150° 38' 27.907 W 11,000.0 78.44 3,870.3 9,064.2 -1,646.9351.79 421,064.385,981,965.71 70° 21' 38.969 N 150° 38' 28.316 W 11,100.0 78.44 3,890.3 9,161.1 -1,660.9351.79 421,051.395,982,062.81 70° 21' 39.923 N 150° 38' 28.726 W 11,132.5 78.44 3,896.8 9,192.7 -1,665.4351.79 421,047.175,982,094.40 70° 21' 40.233 N 150° 38' 28.859 W 11,182.9 78.35 3,907.0 9,241.4 -1,673.1350.25 421,039.975,982,143.22 70° 21' 40.713 N 150° 38' 29.085 W NT6 MFS 11,200.0 78.32 3,910.4 9,257.9 -1,676.1349.73 421,037.235,982,159.72 70° 21' 40.875 N 150° 38' 29.170 W 11,300.0 78.18 3,930.8 9,353.7 -1,696.1346.67 421,018.205,982,255.74 70° 21' 41.817 N 150° 38' 29.756 W 11,319.0 78.16 3,934.7 9,371.8 -1,700.5346.09 421,014.015,982,273.85 70° 21' 41.995 N 150° 38' 29.884 W Upper Bound SM_NDB_018 Fault 11,400.0 78.07 3,951.4 9,448.3 -1,721.2343.60 420,994.085,982,350.56 70° 21' 42.747 N 150° 38' 30.491 W 11,435.4 78.04 3,958.7 9,481.5 -1,731.3342.52 420,984.345,982,383.79 70° 21' 43.073 N 150° 38' 30.786 W NT5 MFS 11,500.0 78.00 3,972.1 9,541.4 -1,751.3340.54 420,964.945,982,443.92 70° 21' 43.662 N 150° 38' 31.372 W 11,600.0 77.95 3,992.9 9,632.7 -1,786.3337.47 420,930.855,982,535.57 70° 21' 44.560 N 150° 38' 32.397 W 11,700.0 77.95 4,013.8 9,722.0 -1,826.2334.40 420,891.905,982,625.25 70° 21' 45.438 N 150° 38' 33.563 W 11,700.3 77.95 4,013.9 9,722.2 -1,826.3334.40 420,891.805,982,625.48 70° 21' 45.440 N 150° 38' 33.567 W NT4 MFS 11,713.3 77.95 4,016.6 9,733.7 -1,831.8334.00 420,886.375,982,637.00 70° 21' 45.553 N 150° 38' 33.729 W NT3 MFS 11,800.0 77.97 4,034.7 9,809.0 -1,870.8331.34 420,848.225,982,712.73 70° 21' 46.294 N 150° 38' 34.868 W 29/09/2025 15:15:54 COMPASS 5000.17 Build Page 6 Santos Ltd Planning Report - Geographic Well B-06Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-06Well: NDBi-06Wellbore: Plan: NDBi-06 Rev L.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 11,819.0 77.98 4,038.7 9,825.3 -1,879.8330.75 420,839.395,982,729.08 70° 21' 46.454 N 150° 38' 35.131 W Lower Bound SM_NDB_018 Fault - 9-5/8" Intermediate Liner 11,858.3 78.00 4,046.8 9,858.6 -1,898.9329.55 420,820.615,982,762.60 70° 21' 46.782 N 150° 38' 35.691 W 11,893.7 78.00 4,054.2 9,888.5 -1,916.5329.55 420,803.355,982,792.67 70° 21' 47.076 N 150° 38' 36.205 W NT3.2 Top Reservoir 11,900.0 78.00 4,055.5 9,893.8 -1,919.6329.55 420,800.305,982,797.98 70° 21' 47.128 N 150° 38' 36.296 W 12,000.0 78.00 4,076.3 9,978.1 -1,969.2329.55 420,751.605,982,882.80 70° 21' 47.957 N 150° 38' 37.746 W 12,037.4 78.00 4,084.1 10,009.6 -1,987.7329.55 420,733.415,982,914.49 70° 21' 48.267 N 150° 38' 38.288 W 12,100.0 80.19 4,095.9 10,062.6 -2,018.8329.55 420,702.795,982,967.83 70° 21' 48.788 N 150° 38' 39.200 W 12,200.0 83.69 4,109.9 10,147.9 -2,069.0329.55 420,653.515,983,053.67 70° 21' 49.627 N 150° 38' 40.668 W 12,300.0 87.19 4,117.9 10,233.9 -2,119.5329.55 420,603.895,983,140.10 70° 21' 50.472 N 150° 38' 42.146 W 12,382.8 90.09 4,119.8 10,305.2 -2,161.5329.55 420,562.685,983,211.89 70° 21' 51.174 N 150° 38' 43.373 W 12,400.0 90.09 4,119.8 10,320.0 -2,170.2329.55 420,554.125,983,226.79 70° 21' 51.319 N 150° 38' 43.628 W 12,500.0 90.09 4,119.6 10,406.3 -2,220.9329.55 420,504.345,983,313.51 70° 21' 52.167 N 150° 38' 45.111 W 12,600.0 90.09 4,119.5 10,492.5 -2,271.6329.55 420,454.565,983,400.22 70° 21' 53.015 N 150° 38' 46.594 W 12,700.0 90.09 4,119.3 10,578.7 -2,322.2329.55 420,404.775,983,486.94 70° 21' 53.862 N 150° 38' 48.077 W 12,800.0 90.09 4,119.2 10,664.9 -2,372.9329.55 420,354.995,983,573.66 70° 21' 54.710 N 150° 38' 49.560 W 12,900.0 90.09 4,119.0 10,751.1 -2,423.6329.55 420,305.215,983,660.37 70° 21' 55.558 N 150° 38' 51.043 W 13,000.0 90.09 4,118.8 10,837.3 -2,474.3329.55 420,255.425,983,747.09 70° 21' 56.405 N 150° 38' 52.526 W 13,100.0 90.09 4,118.7 10,923.5 -2,525.0329.55 420,205.645,983,833.81 70° 21' 57.253 N 150° 38' 54.009 W 13,200.0 90.09 4,118.5 11,009.7 -2,575.6329.55 420,155.865,983,920.52 70° 21' 58.101 N 150° 38' 55.492 W 13,300.0 90.09 4,118.4 11,095.9 -2,626.3329.55 420,106.075,984,007.24 70° 21' 58.948 N 150° 38' 56.975 W 13,400.0 90.09 4,118.2 11,182.1 -2,677.0329.55 420,056.295,984,093.96 70° 21' 59.796 N 150° 38' 58.458 W 13,500.0 90.09 4,118.1 11,268.3 -2,727.7329.55 420,006.515,984,180.67 70° 22' 0.644 N 150° 38' 59.941 W 13,600.0 90.09 4,117.9 11,354.5 -2,778.4329.55 419,956.725,984,267.39 70° 22' 1.491 N 150° 39' 1.425 W 13,700.0 90.09 4,117.7 11,440.7 -2,829.0329.55 419,906.945,984,354.11 70° 22' 2.339 N 150° 39' 2.908 W 13,800.0 90.09 4,117.6 11,526.9 -2,879.7329.55 419,857.165,984,440.82 70° 22' 3.187 N 150° 39' 4.391 W 13,900.0 90.09 4,117.4 11,613.1 -2,930.4329.55 419,807.375,984,527.54 70° 22' 4.034 N 150° 39' 5.875 W 14,000.0 90.09 4,117.3 11,699.3 -2,981.1329.55 419,757.595,984,614.25 70° 22' 4.882 N 150° 39' 7.358 W 14,100.0 90.09 4,117.1 11,785.6 -3,031.8329.55 419,707.815,984,700.97 70° 22' 5.729 N 150° 39' 8.841 W 14,200.0 90.09 4,116.9 11,871.8 -3,082.4329.55 419,658.025,984,787.69 70° 22' 6.577 N 150° 39' 10.325 W 14,300.0 90.09 4,116.8 11,958.0 -3,133.1329.55 419,608.245,984,874.40 70° 22' 7.425 N 150° 39' 11.808 W 14,400.0 90.09 4,116.6 12,044.2 -3,183.8329.55 419,558.465,984,961.12 70° 22' 8.272 N 150° 39' 13.292 W 14,500.0 90.09 4,116.5 12,130.4 -3,234.5329.55 419,508.675,985,047.84 70° 22' 9.120 N 150° 39' 14.775 W 14,600.0 90.09 4,116.3 12,216.6 -3,285.2329.55 419,458.895,985,134.55 70° 22' 9.968 N 150° 39' 16.259 W 14,700.0 90.09 4,116.1 12,302.8 -3,335.8329.55 419,409.115,985,221.27 70° 22' 10.815 N 150° 39' 17.742 W 14,800.0 90.09 4,116.0 12,389.0 -3,386.5329.55 419,359.325,985,307.99 70° 22' 11.663 N 150° 39' 19.226 W 14,900.0 90.09 4,115.8 12,475.2 -3,437.2329.55 419,309.545,985,394.70 70° 22' 12.510 N 150° 39' 20.710 W 15,000.0 90.09 4,115.7 12,561.4 -3,487.9329.55 419,259.765,985,481.42 70° 22' 13.358 N 150° 39' 22.194 W 15,100.0 90.09 4,115.5 12,647.6 -3,538.6329.55 419,209.985,985,568.14 70° 22' 14.206 N 150° 39' 23.677 W 15,200.0 90.09 4,115.4 12,733.8 -3,589.2329.55 419,160.195,985,654.85 70° 22' 15.053 N 150° 39' 25.161 W 15,300.0 90.09 4,115.2 12,820.0 -3,639.9329.55 419,110.415,985,741.57 70° 22' 15.901 N 150° 39' 26.645 W 15,400.0 90.09 4,115.0 12,906.2 -3,690.6329.55 419,060.635,985,828.29 70° 22' 16.748 N 150° 39' 28.129 W 15,500.0 90.09 4,114.9 12,992.4 -3,741.3329.55 419,010.845,985,915.00 70° 22' 17.596 N 150° 39' 29.613 W 15,546.6 90.09 4,114.8 13,032.6 -3,764.9329.55 418,987.645,985,955.42 70° 22' 17.991 N 150° 39' 30.304 W Start DLS 4.00 TFO -129.40 15,600.0 90.09 4,114.7 13,078.6 -3,792.0329.55 418,961.065,986,001.72 70° 22' 18.443 N 150° 39' 31.097 W 15,700.0 90.09 4,114.6 13,164.9 -3,842.6329.55 418,911.285,986,088.43 70° 22' 19.291 N 150° 39' 32.581 W 15,800.0 90.09 4,114.4 13,251.1 -3,893.3329.55 418,861.495,986,175.15 70° 22' 20.139 N 150° 39' 34.065 W 15,862.1 90.09 4,114.3 13,304.6 -3,924.8329.55 418,830.595,986,228.98 70° 22' 20.665 N 150° 39' 34.986 W Start 50.0 hold at 15861.9 MD 15,900.0 90.09 4,114.2 13,337.3 -3,944.0329.55 418,811.715,986,261.87 70° 22' 20.986 N 150° 39' 35.549 W 15,912.1 90.09 4,114.2 13,347.7 -3,950.1329.55 418,805.705,986,272.34 70° 22' 21.089 N 150° 39' 35.728 W Start DLS 4.00 TFO -96.99 16,000.0 90.09 4,114.1 13,423.5 -3,994.7329.55 418,761.935,986,348.58 70° 22' 21.834 N 150° 39' 37.033 W 16,024.4 90.09 4,114.0 13,444.5 -4,007.1329.55 418,749.765,986,369.78 70° 22' 22.041 N 150° 39' 37.395 W Start DLS 3.95 TFO -0.02 16,100.0 90.09 4,113.9 13,509.7 -4,045.4329.55 418,712.145,986,435.30 70° 22' 22.681 N 150° 39' 38.517 W 16,200.0 90.09 4,113.8 13,595.9 -4,096.0329.55 418,662.365,986,522.02 70° 22' 23.529 N 150° 39' 40.001 W 29/09/2025 15:15:54 COMPASS 5000.17 Build Page 7 Santos Ltd Planning Report - Geographic Well B-06Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-06Well: NDBi-06Wellbore: Plan: NDBi-06 Rev L.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 16,300.0 90.09 4,113.6 13,682.1 -4,146.7329.55 418,612.585,986,608.73 70° 22' 24.376 N 150° 39' 41.485 W 16,400.0 90.09 4,113.4 13,768.3 -4,197.4329.55 418,562.795,986,695.45 70° 22' 25.224 N 150° 39' 42.969 W 16,445.7 90.09 4,113.4 13,807.7 -4,220.5329.55 418,540.065,986,735.05 70° 22' 25.611 N 150° 39' 43.647 W Start DLS 0.00 TFO 100.03 16,500.0 90.09 4,113.3 13,854.5 -4,248.1329.55 418,513.015,986,782.17 70° 22' 26.071 N 150° 39' 44.453 W 16,600.0 90.09 4,113.1 13,940.7 -4,298.8329.55 418,463.235,986,868.88 70° 22' 26.919 N 150° 39' 45.938 W 16,700.0 90.09 4,113.0 14,026.9 -4,349.4329.55 418,413.445,986,955.60 70° 22' 27.767 N 150° 39' 47.422 W 16,800.0 90.09 4,112.8 14,113.1 -4,400.1329.55 418,363.665,987,042.32 70° 22' 28.614 N 150° 39' 48.906 W 16,900.0 90.09 4,112.7 14,199.3 -4,450.8329.55 418,313.885,987,129.03 70° 22' 29.462 N 150° 39' 50.391 W 17,000.0 90.09 4,112.5 14,285.5 -4,501.5329.55 418,264.095,987,215.75 70° 22' 30.309 N 150° 39' 51.875 W 17,100.0 90.09 4,112.3 14,371.7 -4,552.2329.55 418,214.315,987,302.47 70° 22' 31.157 N 150° 39' 53.360 W 17,200.0 90.09 4,112.2 14,457.9 -4,602.8329.55 418,164.535,987,389.18 70° 22' 32.004 N 150° 39' 54.844 W 17,300.0 90.09 4,112.0 14,544.2 -4,653.5329.55 418,114.745,987,475.90 70° 22' 32.852 N 150° 39' 56.329 W 17,400.0 90.09 4,111.9 14,630.4 -4,704.2329.55 418,064.965,987,562.61 70° 22' 33.699 N 150° 39' 57.813 W 17,500.0 90.09 4,111.7 14,716.6 -4,754.9329.55 418,015.185,987,649.33 70° 22' 34.547 N 150° 39' 59.298 W 17,600.0 90.09 4,111.5 14,802.8 -4,805.6329.55 417,965.405,987,736.05 70° 22' 35.394 N 150° 40' 0.782 W 17,700.0 90.09 4,111.4 14,889.0 -4,856.2329.55 417,915.615,987,822.76 70° 22' 36.242 N 150° 40' 2.267 W 17,800.0 90.09 4,111.2 14,975.2 -4,906.9329.55 417,865.835,987,909.48 70° 22' 37.089 N 150° 40' 3.752 W 17,900.0 90.09 4,111.1 15,061.4 -4,957.6329.55 417,816.055,987,996.20 70° 22' 37.937 N 150° 40' 5.236 W 18,000.0 90.09 4,110.9 15,147.6 -5,008.3329.55 417,766.265,988,082.91 70° 22' 38.784 N 150° 40' 6.721 W 18,100.0 90.09 4,110.7 15,233.8 -5,059.0329.55 417,716.485,988,169.63 70° 22' 39.632 N 150° 40' 8.206 W 18,200.0 90.09 4,110.6 15,320.0 -5,109.6329.55 417,666.705,988,256.35 70° 22' 40.479 N 150° 40' 9.691 W 18,300.0 90.09 4,110.4 15,406.2 -5,160.3329.55 417,616.915,988,343.06 70° 22' 41.327 N 150° 40' 11.176 W 18,400.0 90.09 4,110.3 15,492.4 -5,211.0329.55 417,567.135,988,429.78 70° 22' 42.174 N 150° 40' 12.660 W 18,500.0 90.09 4,110.1 15,578.6 -5,261.7329.55 417,517.355,988,516.50 70° 22' 43.022 N 150° 40' 14.145 W 18,600.0 90.09 4,110.0 15,664.8 -5,312.4329.55 417,467.565,988,603.21 70° 22' 43.869 N 150° 40' 15.630 W 18,700.0 90.09 4,109.8 15,751.0 -5,363.0329.55 417,417.785,988,689.93 70° 22' 44.717 N 150° 40' 17.115 W 18,800.0 90.09 4,109.6 15,837.2 -5,413.7329.55 417,368.005,988,776.64 70° 22' 45.564 N 150° 40' 18.600 W 18,900.0 90.09 4,109.5 15,923.4 -5,464.4329.55 417,318.215,988,863.36 70° 22' 46.411 N 150° 40' 20.085 W 19,000.0 90.09 4,109.3 16,009.7 -5,515.1329.55 417,268.435,988,950.08 70° 22' 47.259 N 150° 40' 21.570 W 19,100.0 90.09 4,109.2 16,095.9 -5,565.8329.55 417,218.655,989,036.79 70° 22' 48.106 N 150° 40' 23.056 W 19,200.0 90.09 4,109.0 16,182.1 -5,616.4329.55 417,168.865,989,123.51 70° 22' 48.954 N 150° 40' 24.541 W 19,300.0 90.09 4,108.8 16,268.3 -5,667.1329.55 417,119.085,989,210.23 70° 22' 49.801 N 150° 40' 26.026 W 19,400.0 90.09 4,108.7 16,354.5 -5,717.8329.55 417,069.305,989,296.94 70° 22' 50.649 N 150° 40' 27.511 W 19,500.0 90.09 4,108.5 16,440.7 -5,768.5329.55 417,019.515,989,383.66 70° 22' 51.496 N 150° 40' 28.996 W 19,600.0 90.09 4,108.4 16,526.9 -5,819.2329.55 416,969.735,989,470.38 70° 22' 52.344 N 150° 40' 30.482 W 19,700.0 90.09 4,108.2 16,613.1 -5,869.8329.55 416,919.955,989,557.09 70° 22' 53.191 N 150° 40' 31.967 W 19,800.0 90.09 4,108.0 16,699.3 -5,920.5329.55 416,870.165,989,643.81 70° 22' 54.038 N 150° 40' 33.452 W 19,900.0 90.09 4,107.9 16,785.5 -5,971.2329.55 416,820.385,989,730.53 70° 22' 54.886 N 150° 40' 34.938 W 20,000.0 90.09 4,107.7 16,871.7 -6,021.9329.55 416,770.605,989,817.24 70° 22' 55.733 N 150° 40' 36.423 W 20,100.0 90.09 4,107.6 16,957.9 -6,072.6329.55 416,720.825,989,903.96 70° 22' 56.581 N 150° 40' 37.909 W 20,200.0 90.09 4,107.4 17,044.1 -6,123.2329.55 416,671.035,989,990.68 70° 22' 57.428 N 150° 40' 39.394 W 20,300.0 90.09 4,107.3 17,130.3 -6,173.9329.55 416,621.255,990,077.39 70° 22' 58.276 N 150° 40' 40.880 W 20,388.0 90.09 4,107.1 17,206.2 -6,218.5329.55 416,577.445,990,153.70 70° 22' 59.021 N 150° 40' 42.187 W Upper Bound SM_NDB_021 Fault 20,400.0 90.09 4,107.1 17,216.5 -6,224.6329.55 416,571.475,990,164.11 70° 22' 59.123 N 150° 40' 42.365 W 20,500.0 90.09 4,106.9 17,302.7 -6,275.3329.55 416,521.685,990,250.82 70° 22' 59.970 N 150° 40' 43.851 W 20,561.0 90.09 4,106.8 17,355.3 -6,306.2329.55 416,491.315,990,303.68 70° 23' 0.487 N 150° 40' 44.757 W 20,600.0 90.86 4,106.5 17,388.9 -6,326.0329.44 416,471.855,990,337.51 70° 23' 0.817 N 150° 40' 45.338 W 20,700.0 92.84 4,103.3 17,474.9 -6,377.0329.16 416,421.725,990,423.96 70° 23' 1.662 N 150° 40' 46.834 W 20,800.0 94.82 4,096.6 17,560.4 -6,428.4328.88 416,371.255,990,510.01 70° 23' 2.503 N 150° 40' 48.339 W 20,860.3 96.02 4,090.9 17,611.7 -6,459.5328.71 416,340.675,990,561.68 70° 23' 3.008 N 150° 40' 49.251 W 20,888.0 95.78 4,088.0 17,635.3 -6,473.8328.73 416,326.625,990,585.36 70° 23' 3.239 N 150° 40' 49.671 W Lower Bound SM_NDB_021 Fault 20,900.0 95.68 4,086.8 17,645.5 -6,480.0328.74 416,320.525,990,595.63 70° 23' 3.339 N 150° 40' 49.852 W 21,000.0 94.81 4,077.7 17,730.6 -6,531.6328.81 416,269.785,990,681.30 70° 23' 4.176 N 150° 40' 51.366 W 21,100.0 93.94 4,070.1 17,816.0 -6,583.2328.88 416,219.085,990,767.15 70° 23' 5.015 N 150° 40' 52.878 W 21,200.0 93.08 4,063.9 17,901.4 -6,634.8328.95 416,168.445,990,853.14 70° 23' 5.855 N 150° 40' 54.389 W 21,300.0 92.21 4,059.3 17,987.1 -6,686.2329.02 416,117.865,990,939.27 70° 23' 6.697 N 150° 40' 55.898 W 29/09/2025 15:15:54 COMPASS 5000.17 Build Page 8 Santos Ltd Planning Report - Geographic Well B-06Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-06Well: NDBi-06Wellbore: Plan: NDBi-06 Rev L.0Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 21,400.0 91.35 4,056.2 18,072.8 -6,737.6329.09 416,067.365,991,025.52 70° 23' 7.540 N 150° 40' 57.405 W 21,479.5 90.66 4,054.8 18,141.0 -6,778.4329.15 416,027.275,991,094.15 70° 23' 8.210 N 150° 40' 58.601 W 21,500.0 90.66 4,054.6 18,158.6 -6,788.9329.15 416,016.955,991,111.85 70° 23' 8.383 N 150° 40' 58.909 W 21,600.0 90.66 4,053.4 18,244.4 -6,840.2329.15 415,966.565,991,198.21 70° 23' 9.227 N 150° 41' 0.412 W 21,700.0 90.66 4,052.3 18,330.3 -6,891.5329.15 415,916.185,991,284.57 70° 23' 10.071 N 150° 41' 1.916 W 21,800.0 90.65 4,051.2 18,416.1 -6,942.8329.15 415,865.795,991,370.93 70° 23' 10.915 N 150° 41' 3.419 W 21,900.0 90.65 4,050.0 18,502.0 -6,994.0329.14 415,815.405,991,457.29 70° 23' 11.758 N 150° 41' 4.923 W 22,000.0 90.65 4,048.9 18,587.8 -7,045.3329.14 415,765.015,991,543.65 70° 23' 12.602 N 150° 41' 6.427 W 22,100.0 90.65 4,047.7 18,673.7 -7,096.6329.14 415,714.625,991,630.01 70° 23' 13.446 N 150° 41' 7.931 W 22,200.0 90.65 4,046.6 18,759.5 -7,147.9329.14 415,664.225,991,716.36 70° 23' 14.289 N 150° 41' 9.435 W 22,300.0 90.65 4,045.5 18,845.3 -7,199.2329.14 415,613.825,991,802.71 70° 23' 15.133 N 150° 41' 10.939 W 22,357.2 90.65 4,044.8 18,894.4 -7,228.5329.14 415,585.005,991,852.11 70° 23' 15.616 N 150° 41' 11.799 W 4-1/2" Production Liner Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 16" Conductor Casing128.0128.0 16 20 13-3/8" Surface Casing2,381.62,884.0 13-3/8 16 9-5/8" Intermediate Liner4,038.711,819.0 9-5/8 12-1/4 4-1/2" Production Liner4,044.822,357.2 4-1/2 8-1/2 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 1,060.2 Upper Schrader Bluff 0.001,048.9 1,158.9 Base Ice Bearing Permafrost1,143.7 1,423.2 Base Permafrost Transition1,391.4 1,832.5 Middle Schrader Bluff1,744.0 2,380.2 MCU2,131.7 3,093.1 Tuluvak Shale2,460.3 3,334.0 Tuluvak Sand2,526.5 5,189.2 TS_7902,812.8 7,443.2 Seabee3,158.2 10,618.3 Nanushuk3,793.8 10,722.7 NT8 MFS3,814.7 10,899.5 NT7 MFS3,850.1 11,182.9 NT6 MFS3,907.0 11,319.0 Upper Bound SM_NDB_018 Fault 0.003,934.7 11,435.4 NT5 MFS 0.003,958.7 11,700.3 NT4 MFS 0.004,013.9 11,713.3 NT3 MFS 0.004,016.6 11,819.0 Lower Bound SM_NDB_018 Fault 0.004,038.7 11,893.7 NT3.2 Top Reservoir 0.004,054.2 20,888.0 Lower Bound SM_NDB_021 Fault 0.004,088.0 20,388.0 Upper Bound SM_NDB_021 Fault 0.004,107.1 29/09/2025 15:15:54 COMPASS 5000.17 Build Page 9 Santos Ltd Planning Report - Geographic Well B-06Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-06Well: NDBi-06Wellbore: Plan: NDBi-06 Rev L.0Design: Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 347.2 347.2 0.0 0.0 Start Build 2.50 999.0 990.2 91.6 -9.6 Start 160.0 hold at 998.7 MD 1,159.0 1,143.8 136.3 -14.3 Start Build 3.00 2,749.2 2,324.4 1,126.9 -118.4 Start 100.0 hold at 2749.0 MD 2,849.2 2,366.9 1,216.9 -127.9 Start DLS 3.00 TFO 3.27 3,478.9 2,553.3 1,806.7 -229.8 Start 12067.7 hold at 3478.7 MD 15,546.6 4,114.8 13,032.6 -3,764.9 Start DLS 4.00 TFO -129.40 15,862.1 4,114.3 13,304.6 -3,924.8 Start 50.0 hold at 15861.9 MD 15,912.1 4,114.2 13,347.7 -3,950.1 Start DLS 4.00 TFO -96.99 16,024.4 4,114.0 13,444.5 -4,007.1 Start DLS 3.95 TFO -0.02 16,445.7 4,113.4 13,807.7 -4,220.5 Start DLS 0.00 TFO 100.03 22,590.5 TD at 22590.3 29/09/2025 15:15:54 COMPASS 5000.17 Build Page 10 -15000150030004500True Vertical Depth0 3000 6000 9000 12000 15000 18000 21000Vertical Section at 339.06°16" Conductor Casing13-3/8" Surface Casing9-5/8" Intermediate Liner4-1/2" Production Liner400050006000700080009000100001100012000130 00 14000 15000 160 00 170 00 18000 19000 20000 2 1 0 00 2200022357 0°81°78°90°90° Plan: NDBi-06 Rev L.0 Upper Schrader BluffBase Ice Bearing PermafrostBase Permafrost TransitionMiddle Schrader BluffMCUTuluvak ShaleTuluvak SandTS_790SeabeeNanushukNT8 MFSNT7 MFSNT6 MFSUP SM_NDB_018 FaultNT5 MFSNT4 MFSNT3 MFSLB_SM_NDB_018 FaultNT3.2 Top ReservoirUB SM_NDB_021 FaultLB SM_NDB_021 FaultPlan: NDBi-06 Rev L.014:21, September 29 2025 035007000105001400017500South(-)/North(+)-17500 -14000 -10500 -7000 -3500 0 3500 7000 10500West(-)/East(+)NDBi-06 Inc Change Rev 2.0NDBi-012 Heel Rev 6.094%Fault Block Rev 2.0NDBi-012 Toe Rev 6.0Target 1: Shallow Fault Avoidance Rev 0.016" Conductor Casing13-3/8" Surface Casing9-5/8" Intermediate Liner4-1/2" Production LinerPlan: NDBi-06 Rev L.014:19, September 29 2025 29 September, 2025 Anticollision Summary Report Santos Pikka NDB B-06 NDBi-06 Plan: NDBi-06 Rev L.0 Santos Ltd Anticollision Summary Report Well B-06 - Slot B-06Local Co-ordinate Reference:SantosCompany: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-06Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-06 Database:EDM Offset DatumReference Design:Plan: NDBi-06 Rev L.0 Offset TVD Reference: Interpolation Method: Depth Range: Reference Error Model: Scan Method: Error Surface: Filter type: ISCWSA Closest Approach 3D Combined Pedal Curve GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of refere MD Interval 25.0usft Unlimited Maximum centre distance of 2,431.0usft Plan: NDBi-06 Rev L.0 Results Limited by: SigmaWarning Levels Evaluated at:2.79 ISCWSA TESTCasing Method: From (usft) Survey Tool Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 29/09/2025 SDI_URSA+SAG SDI URSA gyroMWD + SAG47.0 1,000.0 Plan: NDBi-06 Rev L.0 (NDBi-06) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag1,000.0 2,884.0 Plan: NDBi-06 Rev L.0 (NDBi-06) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,884.0 11,819.0 Plan: NDBi-06 Rev L.0 (NDBi-06) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag11,819.0 22,357.2 Plan: NDBi-06 Rev L.0 (NDBi-06) Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB CCB-01 - NDBi-01 - Plan: NDBi-01 Rev A.0 346.7 346.9 99.9 90.0 17.693 ESB-01 - NDBi-01 - Plan: NDBi-01 Rev A.0 350.0 350.1 99.9 90.0 17.668 SFB-01 - NDBi-01 - Plan: NDBi-01 Rev A.0 525.0 517.1 105.8 95.1 16.799 CCB-02 - NDB-02 - Plan: NDB-02 Rev A.0 347.8 348.0 79.8 69.9 14.004 ESB-02 - NDB-02 - Plan: NDB-02 Rev A.0 350.0 350.1 79.8 69.9 13.992 SFB-02 - NDB-02 - Plan: NDB-02 Rev A.0 500.0 495.0 83.8 73.2 13.411 CCB-03 - NDB-03 - Plan: NDB-05 to 3 Rev B.0 348.0 348.2 59.8 49.5 9.732 ESB-03 - NDB-03 - Plan: NDB-05 to 3 Rev B.0 375.0 374.9 59.9 49.5 9.645 SFB-03 - NDB-03 - Plan: NDB-05 to 3 Rev B.0 775.0 770.1 69.1 56.3 8.440 CCB-04 - NDB-04 - Plan: NDBi-07 to 4 Rev A.0 347.9 348.1 39.8 29.7 6.377 ESB-04 - NDB-04 - Plan: NDBi-07 to 4 Rev A.0 375.0 375.0 39.8 29.6 6.321 SFB-04 - NDB-04 - Plan: NDBi-07 to 4 Rev A.0 700.0 697.7 44.9 32.7 5.668 CCB-05 - NDB-05 - Plan: NDB-04&9 to 5 Rev B.0 349.8 350.0 19.8 9.5 2.952 ESB-05 - NDB-05 - Plan: NDB-04&9 to 5 Rev B.0 700.0 699.6 20.4 8.2 2.433 SFB-05 - NDB-05 - Plan: NDB-04&9 to 5 Rev B.0 900.0 899.0 22.1 8.5 2.320 CCB-07 - NDBi-07 - Plan: NDB-03 to 7 Slot Saver 325.0 325.2 20.2 9.9 3.038 ESB-07 - NDBi-07 - Plan: NDB-03 to 7 Slot Saver 400.0 400.2 20.4 9.7 2.928 SFB-07 - NDBi-07 - Plan: NDB-03 to 7 Slot Saver 450.0 450.2 20.8 9.8 2.885 CCB-08 - NDB-08 - NDB-08 Slot Saver 325.0 325.2 40.3 30.7 7.111 ESB-08 - NDB-08 - NDB-08 Slot Saver 375.0 375.2 40.3 30.6 7.012 SFB-08 - NDB-08 - NDB-08 Slot Saver 525.0 525.0 42.0 31.7 6.726 CCB-09 - NDB-09 - Plan: NDB-09 Slot Saver 325.0 325.2 60.3 50.5 10.578 ESB-09 - NDB-09 - Plan: NDB-09 Slot Saver 375.0 375.2 60.3 50.4 10.352 SFB-09 - NDB-09 - Plan: NDB-09 Slot Saver 625.0 624.5 65.3 53.9 9.352 CC, ESB-10 - NDB-010 - NDB-010 47.0 46.9 80.0 70.9 16.755 SFB-10 - NDB-010 - NDB-010 19,800.0 19,510.0 1,767.5 1,200.0 3.904 CC, ESB-10 - NDB-010 - Plan: NDB-010 Rev G.0 47.0 46.7 80.0 70.9 16.755 SFB-10 - NDB-010 - Plan: NDB-010 Rev G.0 20,100.0 19,749.4 1,778.2 1,117.8 3.373 CCB-11 - NDB-011 - NDB-011 322.1 322.1 99.6 90.0 18.220 ESB-11 - NDB-011 - NDB-011 350.0 349.9 99.6 90.0 18.085 SFB-11 - NDB-011 - NDB-011 550.0 546.5 103.7 93.3 16.997 CCB-12 - NDBi-012 - Plan: NDBi-012 Slot Saver 325.0 325.0 120.1 110.5 21.970 ESB-12 - NDBi-012 - Plan: NDBi-012 Slot Saver 375.0 375.0 120.1 110.4 21.655 SFB-12 - NDBi-012 - Plan: NDBi-012 Slot Saver 800.0 797.1 134.8 123.2 18.877 CCB-13 - NDB-013 - Plan: NDBi-013 Slot Saver 325.0 325.0 140.1 130.5 25.713 ESB-13 - NDB-013 - Plan: NDBi-013 Slot Saver 375.0 375.0 140.1 130.4 25.344 SFB-13 - NDB-013 - Plan: NDBi-013 Slot Saver 875.0 870.3 161.6 149.5 21.644 CCB-14 - NDBi-014 - NDBi-014 183.5 183.4 160.1 150.9 31.572 ESB-14 - NDBi-014 - NDBi-014 300.0 299.6 160.2 150.6 29.439 29/09/2025 14:47:02 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 2 Santos Ltd Anticollision Summary Report Well B-06 - Slot B-06Local Co-ordinate Reference:SantosCompany: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-06Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-06 Database:EDM Offset DatumReference Design:Plan: NDBi-06 Rev L.0 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB SFB-14 - NDBi-014 - NDBi-014 650.0 642.1 172.0 161.1 26.454 CCB-15 - NDB-015 - Plan: NDB-015 Rev A.0 325.0 325.2 180.5 170.7 32.696 ESB-15 - NDB-015 - Plan: NDB-015 Rev A.0 350.0 350.2 180.5 170.7 32.360 SFB-15 - NDB-015 - Plan: NDB-015 Rev A.0 22,357.2 21,522.1 1,790.4 1,129.4 3.393 CCB-16 - NDBi-016 - NDBi-016 52.0 51.7 200.1 191.0 42.637 ESB-16 - NDBi-016 - NDBi-016 300.0 299.1 200.6 191.0 37.240 SFB-16 - NDBi-016 - NDBi-016 8,400.0 8,079.7 2,417.3 2,177.0 12.695 CCB-17 - NDB-017 - NDB-017 Slot Saver 325.0 325.2 220.6 211.0 40.986 ESB-17 - NDB-017 - NDB-017 Slot Saver 375.0 375.2 220.6 211.0 40.401 SFB-17 - NDB-017 - NDB-017 Slot Saver 1,025.0 1,000.0 257.2 244.3 31.802 CCB-18 - NDBi-018 - NDBi-018 52.0 51.6 240.2 231.0 51.277 ESB-18 - NDBi-018 - NDBi-018 350.0 349.4 240.5 230.8 44.106 SFB-18 - NDBi-018 - NDBi-018 8,000.0 7,700.3 2,417.5 2,212.3 14.896 CCDW-02 - DW-02 - DW-02 1,822.1 2,096.4 284.6 261.0 16.898 ESDW-02 - DW-02 - DW-02 1,825.0 2,098.5 284.6 260.9 16.814 SFDW-02 - DW-02 - DW-02 2,025.0 2,245.2 325.4 294.6 14.397 29/09/2025 14:47:02 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 3 Santos Ltd Anticollision Summary Report Well B-06 - Slot B-06Local Co-ordinate Reference:SantosCompany: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-06Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-06 Database:EDM Offset DatumReference Design:Plan: NDBi-06 Rev L.0 Offset TVD Reference: 0 600 1200 1800 2400 0 4000 8000 12000 16000 20000 24000 Measured Depth Ladder Plot B-01, NDBi-01, Plan: NDBi-01 Rev A.0 V0 B-02, NDB-02, Plan: NDB-02 Rev A.0 V0 B-03, NDB-03, Plan: NDB-05 to 3 Rev B.0 V0 B-04, NDB-04, Plan: NDBi-07 to 4 Rev A.0 V0 B-05, NDB-05, Plan: NDB-04&9 to 5 Rev B.0 V0 B-07, NDBi-07, Plan: NDB-03 to 7 Slot Saver V0 B-08, NDB-08, NDB-08 Slot Saver V0 B-09, NDB-09, Plan: NDB-09 Slot Saver V0 B-10, NDB-010, NDB-010 V0 B-10, NDB-010, Plan: NDB-010 Rev G.0 V0 B-11, NDB-011, NDB-011 V0 B-12, NDBi-012, Plan: NDBi-012 Slot Saver V0 B-13, NDB-013, Plan: NDBi-013 Slot Saver V0 B-14, NDBi-014, NDBi-014 V0 B-15, NDB-015, Plan: NDB-015 Rev A.0 V0 B-16, NDBi-016, NDBi-016 V0 B-17, NDB-017, NDB-017 Slot Saver V0 B-18, NDBi-018, NDBi-018 V0 DW-02, DW-02, DW-02 V0 L E G E N D Coordinates are relative to: B-06 - Slot B-06 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.59°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to Parker 272 @ 69.8usft 29/09/2025 14:47:02 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 4 Santos Ltd Anticollision Summary Report Well B-06 - Slot B-06Local Co-ordinate Reference:SantosCompany: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-06Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-06 Database:EDM Offset DatumReference Design:Plan: NDBi-06 Rev L.0 Offset TVD Reference: 0.00 3.00 6.00 9.00 0 4000 8000 12000 16000 20000 Measured Depth Stop Drilling Caution - Monitor Closely Normal Operations Separation Factor Plot B-01, NDBi-01, Plan: NDBi-01 Rev A.0 V0 B-02, NDB-02, Plan: NDB-02 Rev A.0 V0 B-03, NDB-03, Plan: NDB-05 to 3 Rev B.0 V0 B-04, NDB-04, Plan: NDBi-07 to 4 Rev A.0 V0 B-05, NDB-05, Plan: NDB-04&9 to 5 Rev B.0 V0 B-07, NDBi-07, Plan: NDB-03 to 7 Slot Saver V0 B-08, NDB-08, NDB-08 Slot Saver V0 B-09, NDB-09, Plan: NDB-09 Slot Saver V0 B-10, NDB-010, NDB-010 V0 B-10, NDB-010, Plan: NDB-010 Rev G.0 V0 B-11, NDB-011, NDB-011 V0 B-12, NDBi-012, Plan: NDBi-012 Slot Saver V0 B-13, NDB-013, Plan: NDBi-013 Slot Saver V0 B-14, NDBi-014, NDBi-014 V0 B-15, NDB-015, Plan: NDB-015 Rev A.0 V0 B-16, NDBi-016, NDBi-016 V0 B-17, NDB-017, NDB-017 Slot Saver V0 B-18, NDBi-018, NDBi-018 V0 DW-02, DW-02, DW-02 V0 L E G E N D Coordinates are relative to: B-06 - Slot B-06 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.59°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to Parker 272 @ 69.8usft 29/09/2025 14:47:02 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 5 0 30 60 0 450 900 1350 1800 2250 Partial Measured Depth Equivalent Magnetic Distance Plan: NDBi-06 Rev L.0 Ladder View 0 150 300 0 3500 7000 10500 14000 17500 21000 Measured Depth Equivalent Magnetic Distance SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 47.0 1000.0 Plan: NDBi-06 Rev L.0 (NDBi-06) SDI_URSA+SAG 1000.0 2884.0 Plan: NDBi-06 Rev L.0 (NDBi-06) 3_MWD+IFR2+MS+Sag 2884.0 11819.0 Plan: NDBi-06 Rev L.0 (NDBi-06) 3_MWD+IFR2+MS+Sag 11819.0 22357.2 Plan: NDBi-06 Rev L.0 (NDBi-06) 3_MWD+IFR2+MS+Sag 14:48, September 29 2025 CASING DETAILS TVD MD Name 128.0 128.016" Conductor Casing 2381.6 2884.013-3/8" Surface Casing 4038.7 11819.09-5/8" Intermediate Liner 4044.8 22357.24-1/2" Production Liner Northing (5000 usft/in)Easting (5000 usft/in)Northing (5000 usft/in)Easting (5000 usft/in)Plan: NDBi-01 Rev A.0Plan: NDB-02 Rev A.0Plan: NDB-05 to 3 Rev B.0Plan: NDBi-07 to 4 Rev A.0Plan: NDB-04&9 to 5 Rev B.0Plan: NDB-03 to 7 Slot SaverNDB-08 Slot SaverPlan: NDB-09 Slot SaverNDB-010NDB-011Plan: NDBi-012 Slot SaverPlan: NDBi-013 Slot SaverNDBi-014Plan: NDB-015 Rev A.0NDBi-016NDB-017 Slot SaverNDBi-018DW-02Plan: NDBi-06 Rev L.0NDANDBNPF14:42, September 29 2025 Plan: NDBi-06 Rev L.0AC FlipbookSURVEY PROGRAMDepth From Depth To Tool47.0 1000.0 SDI_URSA+SAG1000.0 2884.0 3_MWD+IFR2+MS+Sag2884.0 11819.0 3_MWD+IFR2+MS+Sag11819.0 22357.2 3_MWD+IFR2+MS+SagCASING DETAILSTVD MD Name128.0 128.0 16" Conductor Casing2381.6 2884.013-3/8" Surface Casing4038.7 11819.09-5/8" Intermediate Liner4044.8 22357.24-1/2" Production Liner20204040606080801001001201200901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [40 usft/in]475075100125150175200225250275300325350375400425451476501526551576601626651676701725750775Plan: NDBi-01 Rev A.0475075100125150175200225250275300325350375400425450475501526551576601626651676701725750775800825849874898Plan: NDB-02 Rev A.04750751001251501752002252502753003253503754004254504755005265515766016266516767017277527778028278528789039289539781004102810531078110311281153117812031228125412791305133013561381140714331459Plan: NDB-05 to 3 Rev B.0707510012515017520022525027530032535037540042545047550052555057660162665167670172675177680182785287790292795297810031028105310781102112711521177120212281253127913041330135513811406143214581484151015351561158716131639Plan: NDBi-07 to 4 Rev A.047507510012515017520022525027530032535037540042545047550052555057560062565067570072575077580082685187690192695197610011026105110761101112611511176120112271252127713021328135313781403142914541479150515301556158116061632165716831708173417591785181018361861188719121938196319892014204020652091211721422168219322192245227022962322234723732399242424502476250125272553257826042630265626812707273327582784280928342859Plan: NDB-04&9 to 5 Rev B.07075100125150175200225250275300325350375400425450474499524549574598623648672697721745769793817841865889912936959982Plan: NDB-03 to 7 Slot Saver475075100125150175200225250275300325350375400425449474499524549573598623647672696720745769793817841864888911935958981NDB-08 Slot Saver47507510012515017520022525027530032535037540042444947449952454857359862264767169672074476879281684086488791193495798010031025Plan: NDB-09 Slot Saver47507510012515017520022525027530032535037540042545047449952454957459962364867369872274777279782184687189592094596999410191044106910941119114411681193121712411266129013141339136313871411143614601484150815331557158116051630NDB-01047507510012515017520022525027530032535037540042545047549952454957459962464867369872374777279782184687189692094597099410191044106910941119114411691193121712421266129013151339136313871412143614601484150915331557158116061630Plan: NDB-010 Rev G.0475075100125150175200225250275300325350375400424449474498523547572596620644667691714737760NDB-011475075100125150175200225250275300325350375400424449474498523548572597621646670694718743767790814838Plan: NDBi-012 Slot Saver47 310310 510510 760760 10101010 12601260 15101510 17601760 20102010 25102510 30103010 35103510 45104510 55105510 65106510 75107510 85108510 95109510 1101011010 1201012010 1301013010 1401014010 1501015010 1601016010 1701017010 18010From Colour To MD47.0 To 22357.2MD Azi TFace47.0 0.00 0.00347.0 354.00 354.00998.7 354.00 354.001158.7 354.00 0.002782.3 354.00 0.002882.3 354.00 0.003476.6 346.35 -25.447239.1 346.35 0.007541.9 351.79 118.3711132.5 351.79 0.0011858.3 329.55 -93.4412037.4 329.55 0.0012382.8 329.55 0.0020561.0 329.55 0.0020860.3 328.71 -8.0621479.5 329.15 175.2622357.2 329.14-143.63 Attachment 3: BOPE Equipment 21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000# 21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000#21-1/4" X 2,000# 13-5/8" X 5,000#13-5/8" X 5,000#30"13-5/8" X 5,000#186"13-5/8" X 5,000# Choke Linefrom BOPPressure Gauge1502 Pressure SensorPressure TransducerBill of MaterialItemDescriptionTo Panic LineItemDescriptionA 31/8 5,000psi W.P.Remote HydraulicOperated ChokeB 31/85,000 psi W.P.Adjustable ManualChoke1 14 31/8 5,000psi W.P.Manual Gate Valve1521/165 000 i WP1521/165,000psiW.P.Manual Gate ValveTo Mud GasLegendBlind SpareTo Tiger TankSeparatorValve Normally OpenValve Normally Closed Attachment 4: Drilling Hazards 16 Surface Hole Section Hazard Mitigations Conductor Broach Monitor conductor for any indications of broaching. Monitor pit volumes for any losses. Gas Hydrates Keep mud cool, optimize pump rates, minimize any excess circulation. Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends. Anti-Collision Closely monitor real-time surveys and run GWD in BHA 12-1/4 Intermediate Hole Sections Hazard Mitigations Lost Returns Optimal drillpipe sizing. Monitor ECD with MWD tools. Pump LCM as required (consult prepared lost returns decisions tree). Slow pump rates, reduce ROP / trip speed when necessary. ECD modelling for cement jobs. Challenging liner runs The Intermediate liner runs requires relatively low OH friction factor to run to TD (hole cleaning and lubricants). Ability to rotate while RIH to overcome drag. Washouts/Hole Enlargement Drill with oil-based mud, maintain mud in specifications, use sufficient mud weight / back-pressure to hold back formations. Tight Hole/Stuck Pipe Hole cleaning and tripping practices, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight / back- pressure to hold back formations. High Angle Hole Cleaning Conduct T&D and hydraulics modeling, control ROP limits based on cuttings returns and comparison to the models. Pack Off During Cementing Proper wellbore cleanup procedure prior to running in hole. Stage circulation rates up while running in hole with liner. Circulate bottoms up at multiple depths to condition mud the way in the hole. Circulate at TD to planned cementing rates and ensure hole is clean. Wireline Inaccessibility The sail angle on this section is too high for wireline to be run conventionally. If wireline logs are required for operations a tractor will be required. Operational complexity with Mechanical two stage cement equipment (9-5/8 Liner) The 2 nd stage of the cement job will be conducted through a mechanically shifted sleeve. This will require the LTP to not be set until the 2nd stage is pumped giving a higher complexity leading to complications with setting the LTP. 8-1/2 Production Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Wellbore Instability Maintain adequate mud weight for wellbore stability. Monitor cuttings returns, LWD logs, and drilling parameters for signs of washout. * Note that no H2S has been encountered on nearby offset wells, and H2S is not anticipated in this well.H2S is not anticipated in this well Attachment 5A: Leak Off Test Procedure (Conventional) 1. Drill out shoe track, cement plus minimum of 20 of new formation. Circulate bottoms up and confirm cuttings are observed at surface. 2. Circulate and condition the mud: a. While circulating the hole clean of cuttings, circulate/ treat the mud to achieve desired mud properties. Consider pulling the bit into the casing shoe to prevent wash out. b. Accurately measure the mud weight with a recently calibrated pressurized mud balance; c. Confirm that mud weight-in is equal to mud weight-out; d. Do not change the mud weight until after the test. 3. Pull the bit back into the casing shoe. 4. Rig up high pressure lines as required to pump down the drill string. Pressure test lines to above expected test pressure. a. Record pressure at surface with calibrated chart recorder. 5. Break circulation down the string. 6. Verify the hole is filled up and close the BOP (annular or upper pipe ram). 7. Perform the LOT or FIT pumping at a constant rate of 0.50bbl/min (or as low as possible). Record pump pressures at 0.25bbl increments (~2 stokes). 8. Record and plot the volume pumped against pressure until leak-off is observed, or until the predetermined limit pressure/EMW has been reached for a FIT. a. Leak-off is defined as the first point on the volume/pressure plot where either the initial static pressure or the final static pressure deviates from the trend observed in the previous observations. b. If the pump pressure suddenly drops, stop pumping but keep the well closed in. This indicates a leak in the system, cement failure or formation breakdown. Record the pressures every minute until they stabilize. If the drop in pressure is related to formation breakdown, this data can be used to derive the minimum in-situ stress. c. If FIT skip step 9. 9. Once a leak off is observed pump an additional 0.75bbls to confirm the leak off. 10. Stop pumping, shut in and record pressures. Monitor shut-in pressure for 10 min. Record initial shut-in pressure 10 seconds after shutting in. Then record pressures at thirty second increments for the first five minutes and then every one minute for the remainder of the shut in period. 11. If the pressure does not stabilize, this may be an indication of a system leak or a poor cement bond. 12. Bleed off pressure (through annulus if a float is in the string) and record the volume returned to establish the volume of mud lost to the formation. Top up and close the annulus valve between the casing and the previous casing string. 13. Open the BOP. Attachment 5B: Leak Off Test Procedure (With MPD) 1. Drill out shoe track and cement. Install MPD Bearing Assembly and drill a minimum of 20 of new formation, holding required EMW using the MPD choke manifold. Circulate bottoms up and confirm cuttings are observed at surface. 2. Circulate and condition the mud: a. While circulating the hole clean of cuttings, circulate/ treat the mud to achieve desired mud properties. Consider pulling the bit into the casing shoe to prevent wash out. b. Accurately measure the mud weight with a recently calibrated pressurized mud balance; c. Confirm that mud weight-in is equal to mud weight-out; d. Do not change the mud weight until after the test. 3. Pull the bit back into the casing shoe, continuing to hold required EMW using the MPD choke. 4. Rig up high pressure lines as required to pump down the drill string. Pressure test lines to above expected test pressure. a. Record pressure at surface with calibrated chart recorder. 5. Break circulation down the string with the MPD chokes closed (i.e. well shut-in). 6. Starting at the MPD set-point pressure (back pressure needed for required baseline EMW), perform the LOT or FIT pumping at a constant rate of 0.50bbl/min (or as low as possible). Record pump pressures at 0.25bbl increments (~2 stokes). 7. Record and plot the volume pumped against pressure until leak-off is observed, or until the predetermined limit pressure/EMW has been reached for a FIT. a. Leak-off is defined as the first point on the volume/pressure plot where either the initial static pressure or the final static pressure deviates from the trend observed in the previous observations. b. If the pump pressure suddenly drops, stop pumping but keep the well closed in. This indicates a leak in the system, cement failure or formation breakdown. Record the pressures every minute until they stabilize. If the drop in pressure is related to formation breakdown, this data can be used to derive the minimum in-situ stress. c. If FIT skip step 8. 8. Once a leak off is observed pump an additional 0.75bbls to confirm the leak off. 9. Stop pumping, shut in and record pressures. Monitor shut-in pressure for 10 min. Record initial shut-in pressure 10 seconds after shutting in. Then record pressures at thirty second increments for the first five minutes and then every one minute for the remainder of the shut in period. 10. If the pressure does not stabilize, this may be an indication of a system leak or a poor cement bond. 11. Bleed off pressure (through MPD choke) down to the starting MPD set-point pressure and record the volume returned to establish the volume of mud lost to the formation. Attachment 6: Cement Summary Surface Casing Cement Casing Size 13-3/8 68# L-80 BTC/TXP-BTC Surface Casing Basis Lead Open hole volume + 150% excess in permafrost / 50% excess below permafrost Lead TOC Surface Tail Open hole volume + 50% excess + 65 ft shoe track Tail TOC 500 ft MD above casing shoe Total Cement Volume Spacer ~80 bbls of 10.5 ppg Tuned Spacer Lead 11.0ppg Lead: 365.6 bbls, 2053 cuft, 810 sks ArcticCem, Yield: 2.53 cuft/sk Tail 15.3ppg Tail: 65.9 bbls, 370 cuft, 298 sks HalCem Type I/II 1.24 cuft/sk Temp BHST 60° F (2.25°/100 TVD below PermaFrost) Verification Method Cement returns to surface Notes Job will be mixed on the fly Verified cement calcs. -bjm Intermediate Liner Cement Casing Size 9-5/8 47# L-80 Hydril 563 Intermediate Liner Basis Tail Open hole volume + excess + 85 ft shoe track Tail TOC Stage 1: 200 TVD above the top Nanushuk formation Stage 2: Top of the 9-5/8 Liner (~150 liner lap) Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Tail Stage 1: 30% Open Hole Excess 15.3ppg Tail: 165.6 bbls, 930cuft, 750sks VersaCem Type I/II 1.24 cuft/sk Stage 2: 100% Open Hole Excess 15.3ppg Tail: 271.7 bbls, 1525cuft, 1230sks VersaCem Type I/II 1.24 cuft/sk Temp Stage 1 - BHST 105° F (2.25°/100 TVD below PermaFrost) Stage 2 - BHST 71° F (2.25°/100 TVD below PermaFrost) Notes Job will be mixed on the fly Verification Method - LWD Sonic will be used to log the 1st Stage Cement Job only. - 2nd Stage Cement Job will not be logged, assuming job parameters are as expected (no losses, good lift pressures, circulate cement off top of liner). Justification: - Stage tool allows for precise placement of base cement column at base Tuluvak hydrocarbon. - Bond log not required for 2nd Stage per Regulation 20 AAC 25.030(d)(5) - 2nd Stage bond evaluation does not affect 1st Stage bond evaluation and frac decision. - Logging of 1st Stage cement will demonstrate isolation between Nanushuk and Tuluvak, ensuring no potential crossflow. - 2nd Stage cement job will isolate Tuluvak with cement and a V0-rated LTP above it as a redundant means of isolation. - Well design allows for the OA annulus to be freeze protected by circulating in place (with Tieback) vs. bullheaded into place. With a sufficient initial LOT/FIT at the surface casing shoe, any potential Tuluvak pressures will be contained by the surface casing shoe and not cross flow into shallower formations. - Future hydraulic fracture operations will only be done in the Nanushuk formation. Log verification of the 1st stage cement job will verify proper isolation has been achieved for frac operations. - Tuluvak isolation has been achieved on all historical Pikka development wells. - Seeking to simplify an already complicated operation, saving time/money. Verified cement calcs. -bjm Attachment 7: Prognosed Formation Tops NDBi-006 Prognosed Tops Formation MD (ft) TVD KB (ft) TVDss (ft) Pore Pressure (ppg) Upper Schrader Bluff 1060 1049 -979 7.2 Base Permafrost Transition 1423 1391 -1322 7.3 Middle Schrader Bluff 1833 1744 -1674 7.6 MCU 2380 2132 -2062 7.8 Tuluvak Shale 3093 2460 -2391 7.9 Tuluvak Sand 3334 2527 -2457 10.1 TS_790 5189 2813 -2743 9.4 Seabee 7442 3158 -3088 9.2 Nanushuk 10618 3794 -3724 8.9 NT8 MFS 10722 3815 -3745 8.9 NT7 MFS 10899 3850 -3780 8.9 NT6 MFS 11182 3907 -3837 8.9 NT5 MFS 11435 3959 -3889 8.9 NT4 MFS 11700 4014 -3944 8.8 NT3 MFS 11713 4017 -3947 8.8 NT3.2 Top Reservoir 11893 4054 -3984 8.8 Attachment 8: Well Schematic Tuluvak Sand @ 3334' MD Top Nan 3.2 @11,893' MD Top Nanushuk @10,618' MD NDBi-006 Well Schematic 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2734' MD 13-3/8" 68 ppf L-80 Surface Casing2884' MD 9-5/8", 47ppf L-80 Production Liner 11,819' MD 4-½, 12.6ppf P-110S Production Liner22,340' MD 4-½ Liner Hanger/ Top Packer11,669' MD GL RKB Bottom Flange 29th Sep. 2025 9-5/8" Tieback2734' MD 9-5/8" Cflex Stage Tool (50' MD below TS790) 5239' MD 9-5/8" Primary TOC (200' TVD above Nanushuk FM.)9621' MD 8-½ Openhole TD22,357' MD *Qty of Frac Sleeves/Open Hole Packers and Equipment depth is approximate Attachment 9: Formation Evaluation Program 16 Surface Hole LWD Gamma Ray Resistivity 12-1/4 Intermediate Hole #1 LWD Gamma Ray Resistivity 8-1/2 Production Hole LWD Gamma Ray Resistivity Density Neutron Sonic (7 Liner Cement Evaluation Only) Ultrasonic Image Log Medium Resistivity Mudlogging No mudlogging is planned for NDBi-006 Attachment 10: Wellhead & Tree Diagram Attachment 11: Diverter Variance Request NDB Surface Hole Map View Attachment 12: Oil Search Alaska 21-day BOPE Test Schedule Waiver Approval Letter Attachment 13: Managed Pressure Drilling Managed Pressure Drilling (MPD) will be implemented on NDBi-006 in the Production hole section of the well. The MPD system will be provided by Beyond Energy Services and Technology with an integrated piping and choke manifold on the Parker 272 rig. The only MPD equipment located outside of the rig will be the nitrogen rack. The plan in the 8-1/2 Production hole will be to drill with a reduced 9.0 10.0ppg mud weight with MPD utilized to trap back-pressure in order to manage ECD for losses as well as providing adequate pressures to maintain wellbore stability through the Nanushuk formations. Weighted trip fluids will be utilized to maintain downhole pressures for the final trip out and running of the 4-1/2 liner without MPD. At no point will the static wellbore fluid be underbalanced. See below for a schematic of the BOP/MPD stack with the choke flow diagram. Attachment 14: As Built Survey NDBi-006 Well Conductor Final NDB-CISUV-000030 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. NANUSHUK OILPIKKA PIKKA NDBi-006 225-101 WELL PERMIT CHECKLISTCompanyOil Search (Alaska), LLCWell Name:PIKKA NDBi-006Initial Class/TypeSER / PENDGeoArea890Unit11580On/Off ShoreOnProgramSERWell bore segAnnular DisposalPTD#:2251010Field & Pool:PIKKA, NANUSHUK OIL - 600100NA1 Permit fee attachedYes ADL392984;ADL393016;ADL393015;ADL391455;ADL393011;ADL3914542 Lease number appropriateYes3 Unique well name and numberYes PIKKA, NANUSHUK OIL - 600100 - governed by CO 8074 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 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 4414 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15 All wells within 1/4 mile area of review identified (For service well only)No16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes 2 stage cement job will leave gap in cement across non-hc-bearing formations.21 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 proposedNo Diverter waiver requested27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes BOP test frequency variance granted to allow 21 days between tests.29 BOPEs, do they meet regulationYes MPSP = 1465 psi, BOP rated to 5k psi (BOP initial test to 5000 psi, susbsequent tests to 3000 psi)30 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 probableYes No wells within 1/4 mile of production liner section.34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S measures not required: None anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.374 to 0.525 psi/ft (7.2 to 10.1 ppg EMW), overpressure expected in Tuluvak36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprTCSDate10/14/2025ApprBJMDate10/20/2025ApprTCSDate10/13/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 10/20/2025