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Home My WebLink About225-108 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDBi-034 (50-103-20927-0000) 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: 2/10/2026 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: 225-108 T41361 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2026.02.10 14:52:28 -09'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDBi-034 Comparison View-1.pdf ؒ NDBi-034 Comparison View-2.pdf ؒ NDBi-034 Definitive Compass Survey Report - NAD27.pdf ؒ NDBi-034 Definitive Compass Survey Report - NAD83.pdf ؒ NDBi-034 Definitive Survey - NAD27.txt ؒ NDBi-034 Definitive Survey - NAD83.txt ؒ NDBi-034 Plan View.pdf ؒ NDBi-034 Vertical Section View.pdf ؒ NDBi-034 WA Definitive Survey.xlsx ؒ ؤؐؐؐLog Digital Data and Plots جؐؐؐBaker ؒ جؐؐؐDigital Data ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDBi-034_LWDGR_Res_Den_Neu_Cal_RM_BROOH_16667ft-26448ft.las ؒ ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_26450ft.las ؒ ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_AziTrak_26450ft.las ؒ ؒ ؒ NDBi-034_LWD_GR_Res_RM_BROOH_11650ft-12000ft.las ؒ ؒ ؒ NDBi-034_LWD_GR_Res_RM_BROOH_16000ft-16672ft.las ؒ ؒ ؒ NDBi-034_LWD_TruARMS_16566-26450ft.LAS ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDBi-034_AP_R01_RM.las ؒ ؒ ؒ NDBi-034_AP_R02_RM.las ؒ ؒ ؒ NDBi-034_AP_R03_RM.las ؒ ؒ ؒ NDBi-034_AP_R04_RM.las ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDBi-034_DMD_RM_26450ft.las ؒ ؒ NDBi-034_DMT_R01_RM.las ؒ ؒ NDBi-034_DMT_R02_RM.las ؒ ؒ NDBi-034_DMT_R03_RM.las ؒ ؒ NDBi-034_DMT_R04_RM.las ؒ ؒ ؒ ؤؐؐؐGraphic Images ؒ جؐؐؐCGM ؒ ؒ جؐؐؐFE ؒ ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_26450ft_2MD.cgm ؒ ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_26450ft_2TVD.cgm ؒ ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_26450ft_5MD.cgm ؒ ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_26450ft_5TVD.cgm LETTER OF TRANSMITTAL ؒ ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_BROOH_16667ft-26448ft.cgm ؒ ؒ ؒ NDBi-034_LWD_GR_Res_RM_BROOH_11650ft-12000ft.cgm ؒ ؒ ؒ NDBi-034_LWD_GR_Res_RM_BROOH_16000ft-16672ft.cgm ؒ ؒ ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ ؒ NDBi-034_AP_RM.cgm ؒ ؒ ؒ ؒ ؒ ؤؐؐؐVSS ؒ ؒ NDBi-034_DMD_RM_26450ft.cgm ؒ ؒ NDBi-034_DMT_RM.cgm ؒ ؒ ؒ ؤؐؐؐPDF ؒ جؐؐؐFE ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_26450ft_2MD.pdf ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_26450ft_2TVD.pdf ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_26450ft_5MD.pdf ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_26450ft_5TVD.pdf ؒ ؒ NDBi-034_LWD_GR_Res_Den_Neu_Cal_RM_BROOH_16667ft-26448ft.pdf ؒ ؒ NDBi-034_LWD_GR_Res_RM_BROOH_11650ft-12000ft.pdf ؒ ؒ NDBi-034_LWD_GR_Res_RM_BROOH_16000ft-16672ft.pdf ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDBi-034_AP_RM.pdf ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDBi-034_DMD_RM_26450ft.pdf ؒ NDBi-034_DMT_RM.pdf ؒ ؤؐؐؐSLB ؤؐؐؐCement Evaluation Logs ؤؐؐؐ7in Sonic CBL Oil_Search_Alaska_LLC_Pikka_NDBi_034_R4_7in_Liner_SonicScope475_ReamDown_RM_TOC_PPT.pdf PIKKA NDBi-034_TOC-RM_13500-16672ft_1000.Pdf PIKKA NDBi-034_TOC-RM_13500-16672ft_200.Pdf PIKKA NDBi-034_TOC-RM_13500-16672ft_2000.Pdf PIKKA NDBi-034_TOC-RM_13500-16672ft_4000.Pdf PIKKA NDBi-034_TOC-RM_13500-16672ft_4000_Labeled.Pdf PIKKA NDBi-034_TOC-RM_13500-16672ft_500.Pdf PIKKA NDBi-034_TOC-RM_13500-16672ft_6000.Pdf PIKKA_NDBi-034_TOC-RM_DLIS_13500-16672ft MD.dlis PIKKA_NDBi-034_TOC-RM_LAS_13500-16672ft MD.las 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): 26450 N/A Casing Collapse Conductor Surface 2,260 Intermediate 4,750 Tieback 4,750 Intermediate 2 5,410 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 2,851 Tieback 2,851 6,870 4,028 25,842 4,117 Length Scott Leahy 16,469 4-1/2" 16,469 4,414 11,590 2/20/2026 4,117 See attached packer report Perforation Depth MD (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 AOGCC USE ONLY 11,590 Tubing Grade: Tubing MD (ft): See attached packer report Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 392984, 391445, 393020, 393019, 392991, 392970 225-108 601 W 5th Avenue, Suite 600, Anchorage, AK 99501 50-103-20927-00-00 Oil Search Alaska, LLC Pikka NDBi-034 Size Proposed Pools: P110S TVD Burst 16,469 Pikka Nanushuk Oil Pool N/A MD 6,870 5,020 128 2,379 128 3,014 11,997 3,046 7" 16,669 20"x34" 13-3/8" 128 9-5/8"9,146 3,014 4,013 7,240 2,319 4-1/2" 25,8429,373 4-1/2" 12.6ppf 4,807 ogrogogogam onnnnn nddddddd on e tdowdodoodontdown rillllll nd sssssss l e teeeeeeeete teeeete ell Cla h ntttttttt vicecececece Well Statu S posed wor PLLLLLL RRRR PL eddeeded grigriggriiiggriigrity stsstssstst t eddddwn RRRRR eananannnan Up ogram NoNNNoNNoNNoNNNNNNNNNNN iccccc arrrryyy oesssssss N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov foregoing is true and the 01/25/2026 326-065 By Grace Chistianson at 12:28 pm, Jan 28, 2026 4014 -bjm 10-404 CDW 01/28/2026 DSR-2/2/26BJM 2/6/26 A.Dewhurst 29JAN26 02/06/26 Page 1 of 1 Packer Set Depths - NDBi-034 Wellbore Name Item Des Btm (ftKB) Btm (TVD) (ftKB) Original Hole ZXP Liner Top Hanger Packer W/HRD-E Profile 16,502.7 4,027.3 Original Hole OH Packer #18 SN DF25-128716-26 16,714.9 4,096.6 Original Hole OH Packer #17 SN DF25-128716-25 16,780.4 4,112.0 Original Hole OH Packer #16 SN DF25-128716-23 17,280.3 4,151.9 Original Hole OH Packer #15 SN DF25-128716-2 17,905.6 4,152.8 Original Hole OH Packer #14 SN DF25-128716-5 18,486.8 4,153.6 Original Hole OH Packer #13 SN DF25-128716-20 19,073.2 4,154.3 Original Hole OH Packer #12 SN DF25-128716-12 19,702.1 4,153.7 Original Hole OH Packer #11 SN DF25-128716-10 20,246.4 4,151.1 Original Hole OH Packer #10 SN DF25-128716-16 20,827.1 4,148.1 Original Hole OH Packer #9 SN DF25-128716-6 21,410.8 4,145.0 Original Hole OH Packer #8 SN DF25-128716-18 21,950.2 4,143.1 Original Hole OH Packer #7 SN DF25-128716-9 22,577.7 4,141.0 Original Hole OH Packer #6 SN DF25-128716-30 23,162.3 4,139.1 Original Hole OH Packer #5 SN DF25-128716-15 23,703.7 4,136.0 Original Hole OH Packer #4 SN GC25-44844-10 24,245.4 4,132.0 Original Hole OH Packer #3 SN GC25-44844-8 24,831.0 4,126.1 Original Hole OH Packer #2 SN GC25-44844-7 25,374.1 4,121.9 Original Hole OH Packer #1 SN GC25-44844-9 25,751.9 4,118.2 Page 1 of 20 NDBi-034 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-034. At the NDBi-034 location, the Permafrost interval extends down to approximately 1000-1400 ft and therefore, no shallow aquifers are located at the NDBi-034 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 in the proximity 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 968 feet (ft) total vertical depth subsea (TVDSS)/ 968 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: 968 to 2,372 ft TVDSS/1,404 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: 2,372 to 3,294 ft TVDSS/ 922 ft thick Hydrocarbon Zone: 2,716 to 3,294 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: 3,294 to 3,745 ft TVDSS/ 451 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: 3,745 to 4,699 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: 4,699 to 5,598 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 1-16 3,800 4,100 8,500 8,100 9,200 8,800 Note: GORV and pump trips to be set to 8700 psi to open Toe Sleeve 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 Mechanical condition of wells transecting the confining zones Fiord 2, Fiord 3 Fiord 3A, NDB-027, NDB-037, NDBi-044. Please see Attachment B as reference. 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 25,601 4,120 234 338 40 7,373 8 2 25,058 4,125 251 413 40 7,285 8 3 24,514 4,129 238 349 40 7,158 8 4 23,969 4,134 235 349 40 7,018 8 5 23,428 4,137 235 333 40 6,970 8 6 22,845 4,140 233 331 40 6,817 8 7 22,260 4,143 228 302 40 6,671 8 8 21,673 4,144 225 296 40 6,539 8 9 21,095 4,147 353 493 40 6,260 8 10 20,513 4,149 231 314 40 6,186 8 11 19,929 4,153 241 506 40 5,972 8 12 19,342 4,154 256 469 40 6,269 10 13 18,755 4,154 240 503 40 6,096 10 14 18,172 4,153 234 487 40 5,981 10 15 17,591 4,152 225 464 40 5,814 10 16 17,008 4,145 235 478 40 5,638 10 7,373 11.Suspected fault or fracture that may transect the confining zones: There are no known faults within the ½ mile radius of NDB-040. Please See Attachment B. Note: Fractures are estimated to propagate along wellbore longitudinally at ~330 o. 12.Detailed proposed fracturing program Attachments F & K 13.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 , 202 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 Sincerely, Jacob Owens 2/2 Contact Information: CERTIFIED MAIL CERTIFIED MAIL CERTIFIED MAIL CERTIFIED MAIL CERTIFIED MAIL State of Alaska Department of Natural Resources Alaska Division of Oil and Gas 550 W 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Arctic Slope Regional Corp. Attn: David Knutson 3900 C Street, Suite 801 Anchorage, AK 99503-5963 Kuukpik Corp 582 E. 36th Avenue Anchorage, AK 99503 Oil Search (Alaska), LLC 601 W 5th Ave Anchorage, AK 99501 Repsol E&P USA LLC 2455 Technology Forest Blvd. The Woodlands, TX 77381 CERTIFIED MAIL ADL 392991 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.58% DNR - 58.42% ADL 392984 Surface Owners: Kuukpi OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 392968 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 50% DNR - 50% ADL 392958 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 36.31% DNR - 63.69% ADL 392992 Surface Owners: State OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 0% DNR - 100% 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: Kuukp OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 31.69% DNR - 68.31% ADL 393016 Surface Owners: Kuukp OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 33.17% DNR - 66.83% ADL 391445 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.98% DNR - 58.02% ADL 391455 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 46.4% DNR - 53.6% 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% ADL 392970 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 40.29% DNR - 59.71% OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD TARGET BOTTOM HOLE SURFACE LOCATION WELL TRAJECTORY .5-MILE BUFFER SANTOS LEASES CPAI LEASES SECTIONS KUUKPIK BOUNDARIES DATE: 1/8/2026. By: JB 0 0.1 0.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-PE-M_NDBi34_well_ownership Map Frame: AP-DRL-PE-M_NDBi034_well_ownership GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 0.2 0.4 Kilometers PIKKA DEVELOPMENT NDBi-034 WELL AREA Attachment B ADL 392968 ADL 392991 ADL 392984ADL 372106ADL 392958 ADL 392992 ADL 392970 ADL 393021 ADL 393019 ADL 393018 ADL 393020 ADL 393015 ADL 393016 ADL 393006 ADL 393007 ADL 391445 ADL 391454 ADL 391455 ADL 393009 ADL 393011 ADL 393010 COLVILLE RIV UNIT CD1-15PB1COLVILLE RIV UNIT CD1-15 COLVILLE RIV UNIT CD1-15PB2 QUGRUK 3A FIORD 2 QUGRUK 7 FIORD 3 QUGRUK 301 FIORD 3A DW-02 NDB-010 NDB-011 NDB-024 NDB-025 NDB-027 NDB-032 NDB-037 NDB-040 NDB-051 NDBi-006 NDBi-014 NDBi-016 NDBi-018 NDBi-030 NDBi-034 NDBi-036 NDBi-043A NDBi-044 NDBi-049 OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD 0.25-MILE BUFFER 0.5-MILE BUFFER NDBI-034 SURFACE LOCATION NDBI-034 BOTTOM HOLE PRODUCTION INTERVAL NDBI-034 OTHER DRILLED NDB WELLS EXPLORATION WELLS BOTTOM HOLES WELL TRAJECTORIES BY OTHERS SANTOS Leases CPAI LEASES SECTIONS FAULT LINE DATE: 1/6/2026. By: JN 0 0.1 0.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDBi34_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 0.2 0.4 Kilometers PIKKA DEVELOPMENT NDBi-034 WELL 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 IntegrityFiord 2 Abandonded9-5/8" 53.5 ppf to 2,231' MD. 8-1/2" openhole to TD at 8,400'.Open Hole abandoment plugs in reservoir. Cased hole plugback set above hydrocarbon bearing zones.Plug 1 set with 55 bbls of Class G cement above 11.2 ppg mud and 20 bbls Hi-Vis at 8.044'MD. Top of Plug 1 tagged with 15K down at 7,437' and covers hydrocarbon sown, Kuparuk/J4, at 7,794'-7,994'. Plug 2 was set on top of 11.2 ppg mud with 20 bbls of Hi-vis pill on top at ~3,300'. Top of cement plug 2 is estmated at 2,400' md and covers an abnormal pressure zone C30 (2,890'-3,200'). Casing shoe plug (#3) is set betwen approximately 2,175-2,331' MD. Cement reatainer was set in casing at 2,175'md with 7 bbls of class G cement on top to ~2,075'. A bridge plug was set at 300' MD and had 19 bbls of a surface plug set on top of it (plug #4). Well was capped and backfilled. Well is fully abandoned. 03/1994Fiord 3A Abandonded9-5/8" 53.5ppf to 1,805' MD. 8-1/2 Openhole to TD at 9,148' MDOpen Hole abandoment plugs in reservoir. Cased hole abandonment plugs above hydrocarbon bearing zones.Estimate of Plug 1 from TD to 8,430' MD covering Hydrocarbon Bearning Zone-J-4 (8,770'-8,810'). Estimate of Plug 2 top at 8,010 MD covering Hydrocarbon Bearing Zone-Albian (8,110'-8,130'). For Cement plug 3, A 20 BBL HI Vis pill was placed at 2750 and a cement plug was placed over Hydrocarbon Bearning Zone, K-5 (2,490'-2,700'). Plug 3 was tagged at 2,391'. Cement plug 4 base set at 1905 MD with with cement retainer set at 1,730' MD. Estimated top of cement 4 plug is 1,619' MD. Bridge plug set at 300' MD and covered with surface cement plug rom 35'-300'. Well is fully abandoned. 04/1995Fiord 3 Abandonded9-5/8" 53.5ppf to 1,805' MD. 8-1/2 Openhole to TD at 7,030' MD/TVDOpen Hole abandoment plugs in reservoir. Cased hole plugback set above hydrocarbon bearing zones.Estimate of plug 1 from TD of well to 6,090' covering hydrocarbon bearing zone, J-4 (6,733'-6,770') and hydrocarbon bearing zone from 6,195-6,230'. 10.5 ppg mud with 20 bbl HI-Vis plug provided base for Plug 2 from 2,650' to 2,315'. Plug #2 top was confirmed by tag. Plug #2 covers hydrocarbon bearing zone K-5 (2,450'-2,600'). 20 bbl Hi-Vis plug provides base from cement plug #3 at 2,100'. Plug 3 was confirmed at 1,659' with a tag. Well was planned to be sidetracked (for Fiord 3A) at approximately 1,900'. Fiord 3 was abandonded with ops noted in the Fiord 3A P&A. Well is fully abandoned. 04/1995NDB-037 ACTIVE 9-5/8" 47ppf 9,704' (Nanushuk) 3,730' (Nanushuk) 7,985' 3,397' log open hole liner for productionTOC 3,730' & packer @ 10,695'Cement Job Observations: For the 1st stage of the cement job, we have adequate isolation in the upper Nanushuk formations across the hydrocarbon-bearing formations (top hydrocarbon estimated within NT8 at ~9,950 MD). This is supported by the CBL log, which indicates good cement throughout the first stage and a TOC at 7,985 MD. For the 2nd stage of the cement job, based on job execution results, cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation. Our assessment is that we have adequate isolation across hydrocarbon-bearing formations in the upper Nanushuk formations, as well as adequate isolation for frac operations. The 2nd stage cement job yielded adequate isolation below, across and above the Tuluvak significant hydrocarbons. 1/9/2025, 9-5/8" casing pressure tested to 4,000 psi for 30 min. NDB-027 ACTIVE 9-5/8" 47ppf 15,992' (Nanushuk) 3,730.9' (Nanushuk) 13,886' 3,516' log open hole liner for productionTOC 3,516' & packer @ 17,056'Cement Job Observations: 9-5/8 1st Stage: For the 1st stage of the cement job, based on job execution results, cement isolation was achieved across the 9-5/8 shoe. 9-5/8 2nd Stage: For the 2nd stage of the cement job, based on job execution results, cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation. 7 Intermediate 2 Liner The SLB TOC log indicates a transition zone from 13,350 to 13,886 MD, with the TOC at 13,886 MD (3,586 TVD), and good cement bond below this depth down to the 7 shoe. This places cement ~224 TVD above the top of the Nanushuk. 9/30/2025, 9-5/8" casing pressure tested to 4,300 psi for 30 min. NDBi-044 ACTIVE 9-5/8" 47ppf 9678 (Nanushuk) 3,804 (Nanushuk) 7964 3,496 log open hole liner for productionTOC 7,964' & packer @ 10,823'1.9-5/8 x 13-3/8 Primary cement joba.Pump 80 bbls 12.5 ppg tuned spacer, 131 bbls 13.0 ppg 400 sxs 1.84 ft^3/sx EconoCem Tpe I-II lead cement, and 80 bbls of 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail. Planned TOC was ~8,350 MD. b.No returns while displacing cement job. Wiper dart #2 was lodged in the liner running tool when it was recovered. The follow liner wiper plug was then found just below the 9-5/8 x 13-3/8 Liner top. A cleanout run was required to push the follow liner wiper plug to bottom and the shoe track was drilled out. Dynamic losses were encountered while drilling the float equipment indicating the lost circulation zone had not been isolated. c.A cement retainer was run in the hole and set at 11,010 MD and a second cement job was pumped through the shoed.15bbls 12.0 ppg tuned spacer and 95 bbls of 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail were circulated through the retainer, and 5 bbls were placed on top of the retainer. 2.9-5/8 Secondary Cement Joba.RIH and open up the Archer Cflex cement tool. Establish circulation and pump 80 bbls 12.5 ppg Tuned spacer 214 bbls 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail. 129 bbls were lost while displacing. The LTP was set and 263 bbls of contaminated mud / cement/ spacer was circulated to surface while circulating with the Cflex running tool. An additional 5 bbls of cement was circulated out off the top of the liner when circulating with the liner running too at the top of the liner. 3.9-5/8 Cement Evaluation Logsa.HES Cast tool was run in the hole on a welltec tractor. The 9-5/8 cement was logged. Showing the TOC of the primary job at 7,964' MD. 01/30/24, 9-5/8" casing pressure tested to 4284 psi for 30 minutes Attachment C 9-5/8 47# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensile (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 7 26# L80 HYDRIL 563 Liner Burst (Psi) Collapse (Psi) Tensile (klbs) ID (in) Drift ID (in) Connecti on OD (in) Make-up Torque (ft-lbs) Make-Up Loss (in) 7240 5410 604 6.276 6.151 7.656 13,700 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 2,850 MD 13-3/8 Casing Shoe at 3,014 MD 9-5/8 Archer Cflex Mechanical Stage tool: 6,588 MD 9-5/8 Shoe at 11,997 MD 7 Intermediate 2 Liner 7 Liner Top at 11,862 MD Shoe at 16,669 MD Geology Top of Tuluvak Sand Top at 3,724 MD Top of Tuluvak TS 790 formation at 6,527 MD. Top of the Nanushuk picked at 15,918 MD/ 3,814 TVD. Cement Job Planning/Execution A summary is provided below. See attached cementing reports for additional information. 9-5/8 INT1 Liner 1st Stage Cement Job -1st Stage of cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeting 1,000 MD above 9-5/8 shoe to ~10,997 MD. This cement job is not isolating any permeable or hydrocarbon zones. -No losses were observed while running liner. Encountered minimal losses throughout the 1st stage cement job (20 bbls of losses after cement exited the shoe). -More details on the cement job can be referenced in the Wellview Cementing report. -A good FIT to 14.0ppg was achieved at the 9-5/8 shoe. -All indications of a successful 1st stage job. 9-5/8 INT1 Liner 2nd Stage Cement Job -2nd Stage of cement job planned with CFLEX ~50 below the TS790. Planned with a full 14.5 ppg tail slurry at 100% excess, targeting TOC at the 9-5/8 liner top. This cement job is isolating the hydrocarbon zone within the upper Tuluvak formation. -Opened the CFLEX stage tool at ~6588 MD and established circulation up to 8 bpm. Pumped the 2 nd stage cement job with full returns and good lift pressure. Closed the CFLEX and set the LTP, then circulated ~46 bbls clean cement back to surface. -All indications of a successful 2nd stage cement job. Lighter weight 14.5ppg cement seemed to help reduce ECDs resulting in no losses. 7 INT2 Liner Cement Job -1st Stage of cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeting 200 TVD above Top Nanushuk to ~14,892 MD. Additionally, this well was planned with 145 bbl LVT spacer to be pumped ahead of the cement spacer to further lower cementing ECD. This cement job is isolating hydrocarbons in the Upper Nanushuk. -No issues or losses were encountered running liner and cementing the 1st stage cement job. -More details on the cement job can be referenced in the Wellview Cementing report. -A FIT of 14.0ppg was achieved at the 7 shoe. A SLB Sonic CBL was run on the 6- 1/8 drilling BHA results are discussed below and report is attached. Observations 9-5/8 Intermediate 1 Liner: -For the 1st stage of the cement job, based on job execution results, cement isolation was achieved across the 9-5/8 shoe. -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. 7 Intermediate 2 Liner: -The SLB Sonic TOC Log indicates there is good cement coverage across and above the Upper Nanushuk formations. Summary as follows: o Top of Partial Cement is 13,814' MD / 3,503' TVD - 2104' MD / 311' TVD above TNAN o Top of Good Cement is 14,098' MD / 3,531' TVD - 1820' MD / 283' TVD above TNAN o Top of Nanushuk is 15,918 MD / 3,814 TVD Page 1/2 Well Name: NDBi-034 Report Printed: 1/12/2026www.peloton.com Cement API/UWI 50103209270000 Surface Legal Location Field Name Pikka PTD # 225108 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.79 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.10 KB-Casing Flange Distance (ft) Spud Date 12/8/2025 09:00 Rig Release Date 1/12/2026 00:00 Surface Surface, Casing, 12/11/2025 07:45 Type Casing Cementing Start Date 12/11/2025 Cementing End Date 12/11/2025 Wellbore Original Hole String Surface Casing, 3,014.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Returns to Surface Cement Evaluation Results Good lift pressure observed. 100 bbls of clean cement to surface and no losses during cement job. Comment Cement 13-3/8 Surface casing as follows: - Rig to pump 40 bbl 10 ppg. 1 ppb PowerVis Spacer, at 4 bpm, 140 psi - Fill lines with 5 bbls water and pressure test to 4,000 psi for 5 minutes - Good test - Drop 1st bottom plug - Pump 80 bbls of 10.5 ppg Tuned Spacer at 5.0 bpm, 235 psi. - Release 2nd bottom plug. - Pump 440 bbls of 11.0 ppg ArcticCem lead cement at 5 bpm, excess volume 200% (973 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 fresh water. - Perform displacement with rig pumps and 9.4 ppg mud - Utilized conductor jet line with water to help clear intermittent packoffs during displacement. - 140 bbls displaced at 4 bpm: ICP 206 psi 11% return flow, FCP 568 psi. - Reduce rate to 3 bpm and pump 291 bbls ICP 424 psi 10-20 % returns bump: Final circulating pressure 680 psi prior to plug bump. - Bump plug and increase pressure to 1,160 psi, held for 5 min. bled off, check floats good. - Total displacement volume 431 bbls (measured by strokes at 96% pump efficiency). - Total losses for cement job and displacement: 0 bbls - Observed PowerVis interface at 87 bbls into displacement. - Dump to cuttings box 120 bbls. into displacement. - Observed Tuned Spacer with Red Dye Interface - Observed 100 bbls clean cement to surface - CIP at 12:50 hrs. - BOPE Test notification submitted to AOGCC, 12-9-25 @ 14:00 hrs for test date 12-11-25 @ 19:00 hrs. - Test witness waived by AOGCC Inspector Kam StJohn at 14:09 hrs 12/9/25 1, 0.0-3,024.0ftKB Top Depth (ftKB) 0.0 Bottom Depth (ftKB) 3,024.0 Full Return? No Vol Cement Ret (bbl) 100.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 786.0 Plug Bump Pressure (psi) 680.0 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 Amount (sacks) Class Volume Pumped (bbl) 40.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) 3,024.0 Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) Free Water (%) Density (lb/gal) 10.00 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 PowerVis Spacer Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) 3,024.0 Estimated Bottom Depth (ftKB) 3,024.0 Percent Excess Pumped (%) Yield (ft³/sack) Mix H20 Ratio (gal/sack) 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 Amount (sacks) 973 Class I/II Volume Pumped (bbl) 440.0 Estimated Top (ftKB) 3,024.0 Estimated Bottom Depth (ftKB) 3,024.0 Percent Excess Pumped (%) 200.0 Yield (ft³/sack) 2.54 Mix H20 Ratio (gal/sack) 12.21 Free Water (%) 0.00 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 p p g p , p , , - Total displacement volume 431 bbls (measured by strokes at 96% pump efficiency).p ( y - Total losses for cement job and displacement: 0 bbls Page 2/2 Well Name: NDBi-034 Report Printed: 1/12/2026www.peloton.com Cement API/UWI 50103209270000 Surface Legal Location Field Name Pikka PTD # 225108 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.79 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.10 KB-Casing Flange Distance (ft) Spud Date 12/8/2025 09:00 Rig Release Date 1/12/2026 00:00 Surface Tail Fluid Type Tail Fluid Description Amount (sacks) 312 Class I/II Volume Pumped (bbl) 69.0 Estimated Top (ftKB) 3,024.0 Estimated Bottom Depth (ftKB) 3,024.0 Percent Excess Pumped (%) 50.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.59 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 57.8 Thickening Time (hr) 10.75 1st Compressive Strength (psi) 500.0 Cement Stage Fluid Additives Add Type Conc Page 1/1 Well Name: NDBi-034 Report Printed: 1/12/2026www.peloton.com Cement API/UWI 50103209270000 Surface Legal Location Field Name Pikka PTD # 225108 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.79 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.10 KB-Casing Flange Distance (ft) Spud Date 12/8/2025 09:00 Rig Release Date 1/12/2026 00:00 Intermediate Casing Cement Stage 1 Intermediate Casing Cement Stage 1, Casing, 12/18/2025 18:00 Type Casing Cementing Start Date 12/18/2025 Cementing End Date 12/18/2025 Wellbore Original Hole String Intermediate Liner, 11,997.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement job parameters / FIT Cement Evaluation Results Good lift pressure observed and only 20 bbls of losses after cement exited shoe. FIT to 14.0ppg EMW at 9 -5/8" shoe. Comment Cement 1st stage 9-5/8 Intermediate Liner - Pump 5 bbls water & Pressure test cement lines to 1,000 psi low 4,000 psi High. - Pump 76 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol A downhole at 4 bpm with 465 psi, - Release bottom pump down plug, chase with 80 bbls of 15.3 ppg Versacem Tail cement type I/II at 4 bpm, initial circulating pressure 800 psi. FCP 250 PSI. Open hole excess volume 30%. - Flush lines with 20 bbl. water to cuttings box - Release top pump down plug - Perform displacement with rig pumps and 11.5 ppg MOBM as follows: - 709 bbls 11.5 ppg OBM at 4 bpm, ICP 428 psi, 3 bpm FCP 450 psi. (Bottom pump down dart latch up confirmed at 54 bbls displaced.) - Pressured up 500 psi over FCP (955 psi) and held 5 min, bled off, checked floats. Floats held. - Total displacement volume 709 bbls (measured by strokes at 96% pump efficiency). CIP @ 23:30 hrs. - 86 bbl total losses during cement job and displacement, 20 bbl loss from cement exiting the shoe to bumping the plug. 1, 10,997.0-12,000.0ftKB Top Depth (ftKB) 10,997.0 Bottom Depth (ftKB) 12,000.0 Full Return? No Vol Cement Ret (bbl) Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 450.0 Plug Bump Pressure (psi) 955.0 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) 76.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) 12,000.0 Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Tail Fluid Type Tail Fluid Description Versacem Amount (sacks) 363 Class I/II Volume Pumped (bbl) 80.0 Estimated Top (ftKB) 10,997.0 Estimated Bottom Depth (ftKB) 12,000.0 Percent Excess Pumped (%) 30.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.56 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 129.0 Thickening Time (hr) 7.00 1st Compressive Strength (psi) 500.0 Cement Stage Fluid Additives Add Type Conc Page 1/1 Well Name: NDBi-034 Report Printed: 1/12/2026www.peloton.com Cement API/UWI 50103209270000 Surface Legal Location Field Name Pikka PTD # 225108 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.79 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.10 KB-Casing Flange Distance (ft) Spud Date 12/8/2025 09:00 Rig Release Date 1/12/2026 00:00 Intermediate Casing Cement Stage 2 Intermediate Casing Cement Stage 2, Casing, 12/19/2025 13:00 Type Casing Cementing Start Date 12/19/2025 Cementing End Date 12/19/2025 Wellbore Original Hole String Intermediate Liner, 11,997.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement returns circulated off top of liner Cement Evaluation Results Good lift pressure observed when displacing cement. 46 bbls of clean cement returned to surface when circulating above the liner top after cement job. No losses during cement job. Comment Perform 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, 4,000 psi high. - Mix and pump 80 bbls of 12.5 ppg Mud Flush at 4 bpm, ICP 543psi, FCP 324 - Mix and pump 79 bbls of 13.5 Tuned Spacer at 4.2 bpm, ICP 395 psi. FCP 304 psi, - Mix and pump 418 bbls of 14.5 ppg Swiftcem Type I-II Tail cement at 4 bpm, ICP 505 psi, final pump rate 4 bpm, FCP 440 psi. No losses observed. - Excess volume 100% (1,664 sacks, yield 1.39 cu ft/sk) - Displace cement with 144 bbls at 4 bpm, 296 psi ICP, 753 psi FCP. CIP @ 16:23 hrs. - No losses during cement job or displacement - Observed red dye at shakers 92 bbls into displacement - Circulate 46 bbls clean cement off liner top. 2, 2,873.0-6,593.0ftKB Top Depth (ftKB) 2,873.0 Bottom Depth (ftKB) 6,593.0 Full Return? Yes Vol Cement Ret (bbl) 46.0 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) 440.0 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 Fluid Type Mud Flush 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 Swiftcem Tail Fluid Type Swiftcem Tail Fluid Description Swiftcem Type I/II Tail Amount (sacks) 1,664 Class I/II Volume Pumped (bbl) 418.0 Estimated Top (ftKB) 2,873.0 Estimated Bottom Depth (ftKB) Percent Excess Pumped (%) 100.0 Yield (ft³/sack) 1.39 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) 0.00 Density (lb/gal) 14.50 Plastic Viscosity (cP) 49.5 Thickening Time (hr) 7.00 1st Compressive Strength (psi) 500.0 Cement Stage Fluid Additives Add Type Conc Page 1/1 Well Name: NDBi-034 Report Printed: 1/12/2026www.peloton.com Cement API/UWI 50103209270000 Surface Legal Location Field Name Pikka PTD # 225108 State/Province Well Configuration Type Horizontal Ground Elevation (ft) 22.79 Casing Flange Elevation (ft) KB-Ground Distance (ft) 47.10 KB-Casing Flange Distance (ft) Spud Date 12/8/2025 09:00 Rig Release Date 1/12/2026 00:00 7" Intermediate Casing Cement 7" Intermediate Casing Cement, Casing, 12/26/2025 08:44 Type Casing Cementing Start Date 12/26/2025 Cementing End Date 12/26/2025 Wellbore Original Hole String Intermediate 2 Liner, 16,669.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Bond Log Cement Evaluation Results SLB SonicScope TOC Log: - Top of Partial Cement is 13,814' MD / 3,503' TVD - 2104' MD / 311' TVD above TNAN. - Top of Good Cement is 14,098' MD / 3,531' TVD - 1820' MD / 283' TVD above TNAN. - Top of Nanushuk is 15,918' MD / 3,814' TVD. Comment Cement 7 Intermediate liner. -PJSM with Third party and Rig personnel -Fill lines with water and pressure test to 4000 psi for 5 min. -Pump 145 bbls LVT at 4 bpm, 600 psi. -Pump 80 bbls of 12.5 ppg Tuned spacer at 3.8 bpm, 500 psi. -Release bottom Pump Down Plug -Pump 122 bbls of 15.3 ppg Type I/II VersaCem tail at 3.7 bpm, Excess Volume 30% (312 sacks, yield 1.24 cu.ft/sk). -Wash up Lines to cuttings box with 20 bbls water -Release top Pump Down Plug, -Perform displacement with rig pumps at 4 bpm. ICP 625 psi. FCP 670 psi with 350 bbls away. Reduce rate to 3 bpm, 600 psi to land plug at 369 bbls displacement. -Bump plug with 1,050 psi and hold for 5 mins. -No losses during cement job. -CIP at 13:47 hrs 1, 11,862.0-16,669.0ftKB Top Depth (ftKB) 11,862.0 Bottom Depth (ftKB) 16,669.0 Full Return? Yes Vol Cement Ret (bbl) Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 3 Avg Pump Rate (bbl/min) 3 Final Pump Pressure (psi) 670.0 Plug Bump Pressure (psi) 1,050.0 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 with 4lbs of red die and 65 gallons of surf B and 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 (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) Cement Stage Fluid Additives Add Type Conc Tail Fluid Type Tail Fluid Description VersaCem (Type I/II) Amount (sacks) 312 Class Type I/II Volume Pumped (bbl) 122.0 Estimated Top (ftKB) 14,750.0 Estimated Bottom Depth (ftKB) 16,660.0 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) 117.8 Thickening Time (hr) 8.00 1st Compressive Strength (psi) 500.0 Cement Stage Fluid Additives Add Type Conc Attachment D Attachment E Attachment F Well NameNDBi-03401/12/26 Preliminary 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 2600000c Pump Check WF26 404004001680016800400400dHSD- Monitor for ~30 min400 0 16800 0 400e DFITXL26 40300700 12600 29400 300 700fDFIT DisplacementWF26 404001100 16800 46200 400 1100gHSD- Monitor for ~2H1100 0 46200 0 1100 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 26404040 11401680 478800 0 40 114020Drop Stage 1 Ball/Collet FP 040343 1143126 480060 016/20-CL3 114330Stage 1 PADXL 2640 359402 150215078 630840 0 359 150240Slow for SeatXL 2640 50452 15522100 651840 0 50 155250Resume PadXL 2640 1453 155342 652260 0 1 155361Flat; Add Patina Tracer to PODXL 2640 125578 16785250 704765028 502816/20-CL120 167372FlatXL 2640 140718 18185880 7635610804 1583116/20-CL129 180183FlatXL 2640 170888 19887140 8349618910 3474116/20-CL150 195194FlatXL 2640 1701058 21587140 9063624265 5900716/20-CL144 2096105FlatXL 2640 1701228 23287140 9777629233 8823916/20-CL139 2235116FlatXL 2640 1701398 24987140 10491633853 12209216/20-CL134 2369127FlatXL 2640 1401538 26385880 11079631426 15351816/20-CL107 2476138FlatXL 2640 1251663 27635250 11604631020 18453816/20-CL92 2569140Clear Surface LinesXL 2640 151678 2778630 1166760 184538 15 2584150Spacer XL 2640151693 2793630 1173060 184538 15 2599160Drop Stage 2 Ball/Collet FP 04031696 2796126 1174320 184538 3 2602170Stage 2 PADXL 2640 3512047 314714742 1321740 184538 351 2953180Slow for Seat XL 2618502097 31972100 1342740 184538 50 3003190Resume PadXL 2640 492146 32462058 1363320 184538 49 3052201FlatXL 2640 1502296 33966300 1426326033 19057116/20-CL144 3195212FlatXL 2640 1752471 35717350 14998213505 20407616/20-CL161 3356223FlatXL 2640 2002671 37718400 15838222247 22632216/20-CL177 3533234FlatXL 2640 2002871 39718400 16678228547 25487016/20-CL170 3702245FlatXL 2640 2003071 41718400 17518234391 28926116/20-CL164 3866256FlatXL 2640 2003271 43718400 18358239827 32908816/20-CL158 4024267FlatXL 2640 1703441 45417140 19072238160 36724816/20-CL130 4154278FlatXL 2640 1353576 46765670 19639233501 40074916/20-CL100 4254280Clear Surface LinesXL 2640 153591 4691630 1970220 400749 15 4269290Spacer XL 2640153606 4706630 1976520 400749 15 4284300Drop Stage 3 Ball/Collet FP 04033609 4709126 1977780 400749 3 4287310Stage 3 PADXL 2640 3433952 505214406 2121840 400749 343 4630FLUID Neat WaterCOMMENTSEnsure Stage 1 ball/collet is loaded Prime and Pressure TestOpen well Well NameNDBi-03401/12/26 Preliminary 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 Water320Slow for Seat XL 2618504002 51022100 2142840 400749 50 4680330Resume PadXL 2640 574059 51592394 2166780 400749 57 4737341FlatXL 2640 1504209 53096300 2229786033 40678216/20-CL144 4880352FlatXL 2640 1754384 54847350 23032813505 42028716/20-CL161 5041363FlatXL 2640 2004584 56848400 23872822247 44253416/20-CL177 5218374FlatXL 2640 2004784 58848400 24712828547 47108116/20-CL170 5388385FlatXL 2640 2004984 60848400 25552834391 50547316/20-CL164 5551396FlatXL 2640 2005184 62848400 26392839827 54529916/20-CL158 5710407FlatXL 2640 1705354 64547140 27106838160 58346016/20-CL130 5839418FlatXL 2640 1355489 65895670 27673833501 61696116/20-CL100 5939420Clear Surface LinesXL 2640 155504 6604630 2773680 616961 15 5954430Spacer XL 2640155519 6619630 2779980 616961 15 5969440Drop Stage 4 Ball/Collet FP 04035522 6622126 2781240 616961 3 5972450Stage 4 PADXL 2640 3345856 695614028 2921520 616961 334 6306460Slow for Seat XL 2618505906 70062100 2942520 616961 50 6356470Resume PadXL 2640 415947 70471722 2959740 616961 41 6397481FlatXL 2640 1606107 72076720 3026946435 62339616/20-CL153 6550492FlatXL 2640 1706277 73777140 30983413119 63651516/20-CL156 6706503FlatXL 2640 1856462 75627770 31760420578 65709316/20-CL163 6870514FlatXL 2640 1856647 77477770 32537426406 68350016/20-CL157 7027525FlatXL 2640 1856832 79327770 33314431812 71531216/20-CL151 7178536FlatXL 2640 1857017 81177770 34091436840 75215116/20-CL146 7325547FlatXL 2640 1557172 82726510 34742434793 78694516/20-CL118 7443558FlatXL 2640 1407312 84125880 35330434742 82168716/20-CL103 7546560Clear Surface LinesXL 2640 157327 8427630 3539340 821687 15 7561570Spacer XL 2640157342 8442630 3545640 821687 15 7576580Drop Stage 5 Ball/Collet FP 04037345 8445126 3546900 821687 3 7579590Stage 5 PADXL 2640 3267671 877113692 3683820 821687 326 7905600Slow for Seat XL 2618507721 88212100 3704820 821687 50 7955610Resume PadXL 2640 497770 88702058 3725400 821687 49 8004621FlatXL 2640 1657935 90356930 3794706636 82832316/20-CL158 8162632FlatXL 2640 1808115 92157560 38703013891 84221416/20-CL165 8328643FlatXL 2640 1958310 94108190 39522021691 86390416/20-CL172 8500654FlatXL 2640 1958505 96058190 40341027834 89173816/20-CL166 8666665FlatXL 2640 1958700 98008190 41160033532 92527016/20-CL160 8825676FlatXL 2640 1958895 99958190 41979038831 96410116/20-CL154 8979687FlatXL 2640 1859080 101807770 42756041528 100562816/20-CL141 9121698FlatXL 2640 1709250 103507140 43470042187 104781516/20-CL126 9246700Clear Surface LinesXL 2640 159265 10365630 4353300 1047815 15 9261710Spacer XL 2640159280 10380630 4359600 1047815 15 9276720Drop Stage 6 Ball/Collet FP 04039283 10383126 4360860 1047815 3 9279730Stage 6 PADXL 2640 3179600 1070013314 4494000 1047815 317 9596740Slow for Seat XL 2618509650 107502100 4515000 1047815 50 9646 Well NameNDBi-03401/12/26 Preliminary 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 Water750Resume PadXL 2640 839733 108333486 4549860 1047815 83 9729761FlatXL 2640 1659898 109986930 4619166636 105445116/20-CL158 9887772FlatXL 2640 18010078 111787560 46947613891 106834216/20-CL165 10052783FlatXL 2640 19510273 113738190 47766621691 109003216/20-CL172 10225794FlatXL 2640 19510468 115688190 48585627834 111786616/20-CL166 10390805FlatXL 2640 19510663 117638190 49404633532 115139816/20-CL160 10550816FlatXL 2640 19510858 119588190 50223638831 119022916/20-CL154 10704827FlatXL 2640 18511043 121437770 51000641528 123175616/20-CL141 10845838FlatXL 2640 17011213 123137140 51714642187 127394316/20-CL126 10971840Clear Surface LinesXL 2640 1511228 12328630 5177760 1273943 15 10986850Spacer XL 26401511243 12343630 5184060 1273943 15 11001860Drop Stage 7 Ball/Collet FP 040311246 12346126 5185320 1273943 3 11004870XL Flush (DFIT)XL 2640 30811554 1265412936 5314680 1273943 308 11312880Slow for seat (DFIT) WF 26185011604 127042100 5335680 1273943 50 1136289DFIT FlushWF 2640230 11834 129349660 543228230 11592903000 feet MD + Surface EqmtFP20 7011904 130042949 546177TOTALS13004 5461771273943 Well NameNDBi-03401/12/26 Preliminary 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 263.54040168016804040040cWF 263.53383781419615876338378d Pump CheckWF26 401004784200200761004780 478 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 4181680 175560 0 40 51820Stage 7 PADXL 2640 450490 86818900 364560 016/20-CL450 96831FlatXL 2640 165655 10336930 433866636 663616/20-CL158 112642FlatXL 2640 180835 12137560 5094613891 2052716/20-CL165 129153FlatXL 2640 1951030 14088190 5913621691 4221816/20-CL172 146464FlatXL 2640 1951225 16038190 6732627834 7005116/20-CL166 162975FlatXL 2640 1951420 17988190 7551633532 10358316/20-CL160 178986FlatXL 2640 1951615 19938190 8370638831 14241416/20-CL154 194397FlatXL 2640 1851800 21787770 9147641528 18394116/20-CL141 2084108FlatXL 2640 1701970 23487140 9861642187 22612816/20-CL126 2210110Clear Surface LinesXL 2640 151985 2363630 992460 226128 15 2225120Spacer XL 2640152000 2378630 998760 226128 15 2240130Drop Stage 8 Ball/Collet FP 04032003 2381126 1000020 226128 3 2243140Stage 8 PADXL 2640 2992302 268012558 1125600 226128 299 2542150Slow for Seat XL 2618502352 27302100 1146600 226128 50 2592160Resume PadXL 2640 1012453 28314242 1189020 226128 101 2693171FlatXL 2640 1652618 29966930 1258326636 23276416/20-CL158 2851182FlatXL 2640 1802798 31767560 13339213891 24665516/20-CL165 3016193FlatXL 2640 1952993 33718190 14158221691 26834616/20-CL172 3188204FlatXL 2640 1953188 35668190 14977227834 29618016/20-CL166 3354215FlatXL 2640 1953383 37618190 15796233532 32971116/20-CL160 3514226FlatXL 2640 1953578 39568190 16615238831 36854216/20-CL154 3668237FlatXL 2640 1853763 41417770 17392241528 41006916/20-CL141 3809248FlatXL 2640 1703933 43117140 18106242187 45225616/20-CL126 3935250Clear Surface LinesXL 2640 153948 4326630 1816920 452256 15 3950260Spacer XL 2640153963 4341630 1823220 452256 15 3965270Drop Stage 9 Ball/Collet FP 04033966 4344126 1824480 452256 3 3968280Stage 9 PADXL 2640 2914257 463512222 1946700 452256 291 4259290Slow for Seat XL 2618504307 46852100 1967700 452256 50 4309300Resume PadXL 2640 1094416 47944578 2013480 452256 109 4418311FlatXL 2640 1654581 49596930 2082786636 45889316/20-CL158 4576322FlatXL 2640 1804761 51397560 21583813891 47278316/20-CL165 4741333FlatXL 2640 1954956 53348190 22402821691 49447416/20-CL172 4913Stage to "Line out XL"FLUID Neat WaterCOMMENTSEnsure Stage 8 ball/collet is loaded Prime and Pressure TestOpen well- Displace PT Drop Ball and SD- 5 minPump Ball to Seat Well NameNDBi-03401/12/26 Preliminary 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 Water344FlatXL 2640 1955151 55298190 23221827834 52230816/20-CL166 5079355FlatXL 2640 1955346 57248190 24040833532 55583916/20-CL160 5238366FlatXL 2640 1955541 59198190 24859838831 59467016/20-CL154 5393377FlatXL 2640 1855726 61047770 25636841528 63619816/20-CL141 5534388FlatXL 2640 1705896 62747140 26350842187 67838416/20-CL126 5659390Clear Surface LinesXL 2640 155911 6289630 2641380 678384 15 5674400Spacer XL 2640155926 6304630 2647680 678384 15 5689410Drop Stage 10 Ball/Collet FP 04035929 6307126 2648940 678384 3 5692420Stage 10 PADXL 2640 2826211 658911844 2767380 678384 282 5974430Slow for Seat XL 2618506261 66392100 2788380 678384 50 6024440Resume PadXL 2640 1186379 67574956 2837940 678384 118 6142451FlatXL 2640 1656544 69226930 2907246636 68502116/20-CL158 6300462FlatXL 2640 1806724 71027560 29828413891 69891116/20-CL165 6466473FlatXL 2640 1956919 72978190 30647421691 72060216/20-CL172 6638484FlatXL 2640 1957114 74928190 31466427834 74843616/20-CL166 6804495FlatXL 2640 1957309 76878190 32285433532 78196716/20-CL160 6963506FlatXL 2640 1957504 78828190 33104438831 82079816/20-CL154 7117517FlatXL 2640 1757679 80577350 33839439283 86008116/20-CL134 7251528FlatXL 2640 1707849 82277140 34553442187 90226816/20-CL126 7376530Clear Surface LinesXL 2640 157864 8242630 3461640 902268 15 7391540Spacer XL 2640157879 8257630 3467940 902268 15 7406550Drop Stage 11 Ball/Collet FP 04037882 8260126 3469200 902268 3 7409560Stage 11 PADXL 2640 2738155 853311466 3583860 902268 273 7682570Slow for Seat XL 2618508205 85832100 3604860 902268 50 7732580Resume PadXL 2640 1528357 87356384 3668700 902268 152 7884591FlatXL 2640 1708527 89057140 3740106837 90910516/20-CL163 8047602FlatXL 2640 2008727 91058400 38241015434 92453916/20-CL184 8231613FlatXL 2640 2208947 93259240 39165024472 94901116/20-CL194 8425624FlatXL 2640 2209167 95459240 40089031402 98041316/20-CL187 8612635FlatXL 2640 2209387 97659240 41013037830 101824316/20-CL180 8792646FlatXL 2640 2209607 99859240 41937043809 106205216/20-CL174 8966657FlatXL 2640 1909797 101757980 42735042650 110470216/20-CL145 9111668FlatXL 2640 1709967 103457140 43449042187 114688916/20-CL126 9237670Clear Surface LinesXL 2640 159982 10360630 4351200 1146889 15 9252680Spacer XL 2640159997 10375630 4357500 1146889 15 9267690Drop Stage 12 Ball/Collet FP 040310000 10378126 4358760 1146889 3 9270700Stage 12 PADXL 2640 26410264 1064211088 4469640 1146889 264 9534710Slow for Seat XL 26185010314 106922100 4490640 1146889 50 9584720Resume PadXL 2640 11110425 108034662 4537260 1146889 111 9695731FlatXL 2640 20010625 110038400 4621268044 115493316/20-CL192 9886742FlatXL 2640 22510850 112289450 47157617363 117229716/20-CL207 10093754FlatXL 2640 27511125 1150311550 48312639253 121154916/20-CL234 10327766FlatXL 2640 26011385 1176310920 49404651775 126332416/20-CL205 10532 Well NameNDBi-03401/12/26 Preliminary 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 Water778FlatXL 2640 24011625 1200310080 50412659558 132288116/20-CL177 107097810FlatXL 2640 20011825 122038400 51252658233 138111416/20-CL139 10848790Clear Surface LinesXL 2640 1511840 12218630 5131560 1381114 15 10863800Spacer XL 26401511855 12233630 5137860 1381114 15 10878810Drop Stage 13 Ball/Collet FP 040311858 12236126 5139120 1381114 3 10881820XL Flush (DFIT)XL 2640 25512113 1249110710 5246220 1381114 255 11136830Slow for seat (DFIT) XL 26185012163 125412100 5267220 1381114 50 1118684DFIT FlushWF 2640230 12393 127719660 538902230 11416853000 feet MD + Surface EqmtFP20 7012463 128412949 541851TOTALS12901 5418511381114 Well NameNDBi-03401/12/26 Preliminary 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 263.52853251197013650285325d Pump CheckWF26 41004254200178501004250 425 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 4651680 195300 0 40 46520Stage 13 PADXL 2640 425465 89017850 373800 016/20-CL425 89031FlatXL 2640 200665 10908400 457808044 804416/20-CL192 108242FlatXL 2640 225890 13159450 5523017363 2540716/20-CL207 128854FlatXL 2640 2751165 159011550 6678039253 6466016/20-CL234 152266FlatXL 2640 2601425 185010920 7770051775 11643516/20-CL205 172778FlatXL 2640 2401665 209010080 8778059558 17599216/20-CL177 1905810FlatXL 2640 2001865 22908400 9618058233 23422516/20-CL139 204390Clear Surface LinesXL 2640 151880 2305630 968100 234225 15 2058100Spacer XL 2640151895 2320630 974400 234225 15 2073110Drop Stage 14 Ball/Collet FP 04031898 2323126 975660 234225 3 2076120Stage 14 PADXL 2640 2462144 256910332 1078980 234225 246 2322130Slow for Seat XL 2618502194 26192100 1099980 234225 50 2372140Resume PadXL 2640 892283 27083738 1137360 234225 89 2461151FlatXL 2640 1902473 28987980 1217167642 24186716/20-CL182 2643163FlatXL 2640 2152688 31139030 13074623915 26578316/20-CL190 2833175FlatXL 2640 2402928 335310080 14082641270 30705216/20-CL197 3030187FlatXL 2640 2403168 359310080 15090653874 36092616/20-CL183 3213199FlatXL 2640 2203388 38139240 16014659475 42040116/20-CL157 33702010FlatXL 2640 1903578 40037980 16812655321 47572216/20-CL132 3502210Clear Surface LinesXL 2640 153593 4018630 1687560 475722 15 3517220Spacer XL 2640153608 4033630 1693860 475722 15 3532230Drop Stage 15 Ball/Collet FP 04033611 4036126 1695120 475722 3 3535240Stage 15 PADXL 2640 2373848 42739954 1794660 475722 237 3772250Slow for Seat XL 2618503898 43232100 1815660 475722 50 3822260Resume PadXL 2640 983996 44214116 1856820 475722 98 3920271FlatXL 2640 1904186 46117980 1936627642 48336416/20-CL182 4102283FlatXL 2640 2154401 48269030 20269223915 50728016/20-CL190 4292295FlatXL 2640 2404641 506610080 21277241270 54854916/20-CL197 4488307FlatXL 2640 2404881 530610080 22285253874 60242316/20-CL183 4671319FlatXL 2640 2205101 55269240 23209259475 66189816/20-CL157 48293210FlatXL 2640 1905291 57167980 24007255321 71721916/20-CL132 4960330Clear Surface LinesXL 2640 155306 5731630 2407020 717219 15 4975340Spacer XL 2640155321 5746630 2413320 717219 15 4990Stage to "Line out XL"FLUID Neat WaterCOMMENTSEnsure Stage 14 ball/collet is loaded Prime and Pressure TestDisplace PT- SD 5 MinPump Ball to Seat Well NameNDBi-03401/12/26 Preliminary 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 Water350Drop Stage 16 Ball/Collet FP 04035324 5749126 2414580 717219 3 4993360Stage 16 PADXL 2640 2285552 59779576 2510340 717219 228 5221370Slow for Seat XL 2618505602 60272100 2531340 717219 50 5271380Resume PadXL 2640 1075709 61344494 2576280 717219 107 5378391FlatXL 2640 1905899 63247980 2656087642 72486116/20-CL182 5560403FlatXL 2640 2156114 65399030 27463823915 74877716/20-CL190 5750415FlatXL 2640 2406354 677910080 28471841270 79004616/20-CL197 5947427FlatXL 2640 2406594 701910080 29479853874 84392016/20-CL183 6130439FlatXL 2640 2206814 72399240 30403859475 90339516/20-CL157 62874410FlatXL 2640 1907004 74297980 31201855321 95871616/20-CL132 6419450XL FlushXL264010 7014 7439420 31075810 6429460LG FlushWF2640178 7192 76177476 318234178 6607473000 feet MD + Surface EqmtFP20 707262 76872949 321183TOTALS7647 321183958716 Updated 1/13/20251/13/2026TBDAK TSCA StatusNorth SlopeTBDPreTBDTBDTBDTrade Name Supplier Purpose Ingredients Name CAS #Percentage by Mass of IngredientPercent of Ingredient in Total Mass PumpedMass of Ingredient (lbs)SMETracercoCarrier FluidSoy Methyl Ester67784-80-9100#VALUE!164.9055760000T-160CTracercoChemical Tracer2,4,6-Tribromotoluene6320-40-7100#VALUE!0.4409240000T-162ATracercoChemical Tracer1,4-Dibromobenzene106-37-6100#VALUE!1.1023100000T-163ATracercoChemical Tracer1,4-Diiodobenze624-38-4100#VALUE!0.4409240000T-164BTracercoChemical Tracer2-Bromonaphthalene580-13-2100#VALUE!1.1023100000T-720TracercoChemical Tracer1,2,4,5-Tetrabromobenzene636-28-2100#VALUE!0.4409240000T-719TracercoChemical Tracer3,4-Dichlorobenzophenone6284-79-3100#VALUE!0.4409240000T-758TracercoChemical Tracer3,4-Difluorobenzophenone85118-07-6100#VALUE!0.4409240000T-712TracercoChemical Tracer1,2,3-Trichlorobenzene87-61-6100#VALUE!2.2046200000T-784TracercoChemical Tracer2,4,6-Tribromoanisole607-99-8100#VALUE!0.4409240000T-776TracercoChemical Tracer1,4-Dibromonaphthalene83-53-4100#VALUE!0.6613860000T-757TracercoChemical Tracer3,3'-Difluorobenzophenone345-70-0100#VALUE!0.6613860000T-721TracercoChemical Tracer4,4'-Dichlorobenzophenone90-98-2100#VALUE!0.4409240000T-734TracercoChemical Tracer1-Bromo-2-(trifluoromethyl)benzene392-83-6100#VALUE!0.6613860000T-750TracercoChemical Tracer1,4-Dibromo-2-fluorobenzene1435-52-5100#VALUE!0.4409240000T-751TracercoChemical TracerBis(4-bromophenyl)ether2050-47-7100#VALUE!1.5432340000T-166ATracercoChemical Tracer5-Iodo-m-xylene22445-41-6100#VALUE!1.1023100000WaterTracercoCarrier FluidWater7732-18-5100#VALUE!134.8290180000T-140cTracercoChemical TracerSodium-4-Fluorobenzoate499-90-1100#VALUE!0.7716170000T-158aTracercoChemical TracerSodium-2,4-Difluorobenzoate1765-08-8100#VALUE!0.7716170000T-158bTracercoChemical TracerSodium-2,5-Difluorobenzoate522651-42-9100#VALUE!0.7716170000T-158eTracercoChemical TracerSodium-3,5-Difluorobenzoate530141-39-0100#VALUE!0.7716170000T-176aTracercoChemical TracerSodium-2,3,4-trifluorobenzoate402955-41-3100#VALUE!0.7716170000T-176bTracercoChemical TracerSodium-2,3,6-trifluorobenzoate1803845-07-9100#VALUE!0.7716170000T-176cTracercoChemical TracerSodium-2,4,5-trifluorobenzoate522651-48-5100#VALUE!0.7716170000T-801TracercoChemical TracerSodium-2-chlorobenzoate17264-74-3100#VALUE!0.7716170000T-803TracercoChemical TracerSodium-4-chlorobenzoate3686-66-6100#VALUE!0.7716170000T-804TracercoChemical TracerSodium-2,3-dichlorobenzoate118537-84-1100#VALUE!0.7716170000T-805TracercoChemical TracerSodium-2,4-Dichlorobenzoate38402-11-8100#VALUE!0.7716170000T-806TracercoChemical TracerSodium-2,5-dichlorobenzoate63891-98-5100#VALUE!0.7716170000T-808TracercoChemical TracerSodium-3,4-dichlorobenzoate17274-10-1100#VALUE!0.7716170000T-809TracercoChemical TracerSodium-3,5-dichlorobenzoate154862-40-5100#VALUE!0.7716170000T-911TracercoChemical TracerSodium-2-chloro-4-fluorobenzoate885471-43-1100#VALUE!0.7716170000T-912TracercoChemical TracerSodium-2-chloro-5-fluorobenzoate1382106-79-7100#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-034Hydraulic Fracturing Fluid Product Component Information DisclosureManufacturer Contact Tracerco 4106 New West Dr. Pasadena Texas 77507 Tel: 281-291-7769Fracture DateState: Approved For Tracerco Additive Additive Description D206 Antifoam Agent 0.0 Gal/mGal 10 gal F103 Surfactant 1.0 Gal/mGal 1,227.0 gal J450 Stabilizing Agent 0.5 Gal/mGal 562.0 gal J475 Breaker J475 6.0 lb/mGal 7,360.0 lbm J511 Stabilizing Agent 1.8 lb/mGal 2,248.0 lbm J532 Crosslinker 2.3 Gal/mGal 2,809.0 gal J580 Gel J580 26.0 lb/mGal 31,894.0 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 84.0 gal M002 Additive 0.0 lb/mGal 2 lbm M117 Clay Control Agent 333.3 lb/mGal 408,898.0 lbm M275 Bactericide 0.3 lb/mGal 396.0 lbm S522-1620 Propping Agent varied concentrations 3,616,519.0 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 % 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 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 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 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 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 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 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 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 CAS Number Chemical Name Mass Fraction - Water (Including Mix Water Supplied by Client)* YF126ST:WF126 gal Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. 1,226,694 Fluid Name & Volume Concentration Volume Disclosure Type: Pre-Job Well Completed: Date Prepared: 1/9/2026 State: Alaska County/Parish: North Slope Borough Case: Client: Oil Search Alaska Well: PIKKA NDBi-034 Basin/Field: Pikka # SLB-Private Page: 1 / 1 Hydraulic Fracturing Chemical Information Disclosure Supplier: Patina Energy 20 Kg Patina Copper Flow Insurance Proprietary chemical information on le supplied by Patina Energy to the AOGCC. Attachment G NDBi-034 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 Per regulation 20 AAC 25.235 (d) 6, Santos is requesting AOGCC permission to flare the produced gas g ( ) , q g p p g for the duration of the development well flowback work. Total volume of gas per the flowback programp outlined in Table 1 is approximately 15 MMscf. Attachment H NDBi-034 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 4,300 psi. 6. Before releasing, pressure test the IA to top liner hanger/packer to 3,500 psi for 10 min and passed. 7. Release running tool from liner hanger. 8. Circulate viscosified brine. 9. Flow check for 10 minutes. 10.POOH with liner hanger running tool. 11.Prepare to run upper completion. NDBi-034 4-1/2 Upper Completion Section Summary Procedure: 12.Run 4-1/2 12.6 ppf P110S TSH563 tubing and downhole jewellery. 13.Circulate out the OBM from liner top to surface with 9.2 ppg NaCl Brine. 14.Land tubing hanger. 15.MIT-IA to 4,000 psi for 30 minutes on rig (planned). (Post rig move, pressure test to 4,300 psi for 30 minutes (Planned)) 16.MIT-T to 3,500 psi for 30 minutes on rig (Planned). (Post rig move, pressure test to 5,500 psi for 30 minutes (Planned)) a. Post rig more pressure test criteria: (8,800 psi MAWP 3,800 psi IA hold) * 1.1 = 5,500 psi tubing 17.Nipple down BOP stack and install 10k frac tree. 18.RDMO NDBi-034 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 @ 3,724' MD Top Nan 3.2 @16,688' MD Top Nanushuk @15,918' NDBi-034 Well Schematic (As Built) 20" Insulated Conductor128' MD 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer 2,851' MD 9-5/8" Liner Hanger and Liner Top Packer 2,851' MD 13-3/8" 68 ppf L-80 Surface Casing 3,014' MD 13-3/8" 68 ppf L-80 Surface Casing 3,014' MD 4-½, 12.6ppf P-110S Production Liner25,842' MD 4-½, 12.6ppf P-110S Production Liner25,842' MD 4-½ Liner Hanger/Top Packer16,469' MD 4-½ Liner Hanger/Top Packer16,469' MD GL 69.74' RKB Bottom Flange 01/12/2026 9-5/8" Tieback2,851' MD 9-5/8" Tieback2,851' MD 9-5/8" Cflex Stage Tool (50' MD below TS790)6,588' MD 9-5/8" Cflex Stage Tool (50' MD below TS790)6,588' MD 7" TOC (200' TVD above top Nanushuk) 14,098' MD 7" TOC (200' TVD above top Nanushuk) 14,098' MD 7", 26ppf L-80 Production Liner16,669' MD 7", 26ppf L-80 Production Liner16,669' MD 9-5/8", 47ppf L-80 Intermediate Liner 11,997' MD 9-5/8", 47ppf L-80 Intermediate Liner 11,997' MD 9-5/8" Primary TOC (1000' MD above shoe) 10,997' MD 9-5/8" Primary TOC (1000' MD above shoe) 10,997' MD 7" Liner Hanger and Liner Top Packer 11,862' MD 7" Liner Hanger and Liner Top Packer 11,862' MD 23 29 10 47 44 8-½ Openhole TD26,450' MD 8-½ Openhole TD26,450' MD 46 454341393735333127252119171513119 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 448 7 6 5 4 3 2 1 # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1463 1420 26 3.813 5.201 2 Gaslift Mandrel 1.5" 2352 2084 54 3.865 7.640 3 X Landing Nipple 2420 2123 56 3.813 5.201 4 D/H Psi-Temp Gauge 16213 3914 68 3.864 5.830 5 EGL Valve 16318 3957 66 3.958 5.900 6 Tieback Seal Assy 16469 4414 67 3.860 5.190 7 7" x 4.5" LH/Packer 16469 4414 67 5.000 5.960 8 #18 OH Packer 16711 4096 75 3.898 5.750 9 #17 OH packer 16777 4111 78 3.898 5.750 10 Stg 16 - Collet Sleeve 16 17008 4145 86 3.735 5.634 11 #16 OH packer 17276 4152 90 3.898 5.750 12 Stg 15 - Collet Sleeve 15 17591 4152 90 3.735 5.634 13 #15 OH packer 17902 4153 90 3.898 5.750 14 Stg 14 - Collet Sleeve 14 18172 4153 90 3.735 5.634 15 #14 OH packer 18483 4154 90 3.898 5.750 16 Stg 13 - Collet Sleeve 13 18755 4154 90 3.735 5.634 17 #13 OH packer 19069 4154 90 3.898 5.750 18 Stg 12 - Collet Sleeve 12 19342 4154 90 3.735 5.634 19 #12 OH packer 19698 4152 90 3.898 5.750 20 Stg 11 - Collet Sleeve 11 19929 4153 90 3.735 5.634 21 #11 OH packer 20243 4151 90 3.898 5.750 22 Stg 10 - Collet Sleeve 10 20513 4149 90 3.735 5.634 23 #10 OH packer 20823 4148 90 3.898 5.750 24 Stg 9 - Collet Sleeve 9 21095 4147 90 3.735 5.634 25 #9 OH packer 21407 4145 90 3.898 5.750 26 Stg 8 - Collet Sleeve 8 21673 4144 90 3.735 5.634 27 #8 OH packer 21946 4143 90 3.898 5.750 28 Stg 7 - Collet Sleeve 7 22260 4143 90 3.735 5.634 29 #7 OH packer 22574 4141 90 3.898 5.750 30 Stg 6 - Collet Sleeve 6 22845 4140 90 3.735 5.634 31 #6 OH packer 23158 4139 90 3.898 5.750 32 Stg 5 - Collet Sleeve 5 23428 4137 90 3.735 5.634 33 #5 OH packer 23700 4136 90 3.898 5.750 34 Stg 4 - Collet Sleeve 4 23969 4134 90 3.735 5.634 35 #4 OH packer 24241 4132 91 3.898 5.750 36 Stg 3 - Collet Sleeve 3 24514 4129 91 3.735 5.634 37 #3 OH packer 24827 4126 91 3.898 5.750 38 Stg 2 - Collet Sleeve 2 25058 4125 90 3.735 5.634 39 #2 OH packer 25370 4122 91 3.898 5.750 40 Stg 1 - Collet Sleeve 1 25601 4120 91 3.735 5.634 41 #1 OH packer 25748 4118 91 3.898 5.750 42 Toe Sleeve 25814 4117 91 3.500 5.750 43 WIV Collar 25827 4117 91 N/A 5.620 44 Eccentric shoe 25840 4117 91 3.930 5.210 46 1 # 6 - C 6 OH olle pack Slee er eve 2 2 25 24' M 9 3-3 KB 1' M Sta w TS e C (1C ( e)) ner T 25 26 Stg MDMD top 6,66 Stg 6 33 34 2/2 Inc 2 3 914 395 44 91 7902 181 1 11 eve ker Sle pac olle OH 7 - C #7# Superseded Tuluvak Sand @ 3,724' MD Top Nan 3.2 @16,688' MD Top Nanushuk @15,918' NDBi-034 Well Schematic (As Built) 20" Insulated Conductor128' MD 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer 2,851' MD 9-5/8" Liner Hanger and Liner Top Packer 2,851' MD 13-3/8" 68 ppf L-80 Surface Casing 3,014' MD 13-3/8" 68 ppf L-80 Surface Casing 3,014' MD 4-½, 12.6ppf P-110S Production Liner25,842' MD 4-½, 12.6ppf P-110S Production Liner25,842' MD 4-½ Liner Hanger/Top Packer16,469' MD 4-½ Liner Hanger/Top Packer16,469' MD GL 69.74' RKB Bottom Flange 02/04/2026 9-5/8" Tieback2,851' MD 9-5/8" Tieback2,851' MD 9-5/8" Cflex Stage Tool (50' MD below TS790)6,588' MD 9-5/8" Cflex Stage Tool (50' MD below TS790)6,588' MD 7" TOC (200' TVD above top Nanushuk) 14,098' MD 7" TOC (200' TVD above top Nanushuk) 14,098' MD 7", 26ppf L-80 Production Liner16,669' MD 7", 26ppf L-80 Production Liner16,669' MD 9-5/8", 47ppf L-80 Intermediate Liner 11,997' MD 9-5/8", 47ppf L-80 Intermediate Liner 11,997' MD 9-5/8" Primary TOC (1000' MD above shoe) 10,997' MD 9-5/8" Primary TOC (1000' MD above shoe) 10,997' MD 7" Liner Hanger and Liner Top Packer 11,862' MD 7" Liner Hanger and Liner Top Packer 11,862' MD 23 29 10 47 44 8-½ Openhole TD26,450' MD 8-½ Openhole TD26,450' MD 46 454341393735333127252119171513119 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 448 7 6 5 4 3 2 1 # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1463 1420 26 3.813 5.201 2 Gaslift Mandrel 1.5" 2352 2084 54 3.865 7.640 3 X Landing Nipple 2420 2123 56 3.813 5.201 4 D/H Psi-Temp Gauge 16213 3914 68 3.864 5.830 5 EGL Valve 16318 3957 66 3.958 5.900 6 Tieback Seal Assy 16469 4014 67 3.860 5.190 7 7" x 4.5" LH/Packer 16469 4014 67 5.000 5.960 8 #18 OH Packer 16711 4096 75 3.898 5.750 9 #17 OH packer 16777 4111 78 3.898 5.750 10 Stg 16 - Collet Sleeve 16 17008 4145 86 3.735 5.634 11 #16 OH packer 17276 4152 90 3.898 5.750 12 Stg 15 - Collet Sleeve 15 17591 4152 90 3.735 5.634 13 #15 OH packer 17902 4153 90 3.898 5.750 14 Stg 14 - Collet Sleeve 14 18172 4153 90 3.735 5.634 15 #14 OH packer 18483 4154 90 3.898 5.750 16 Stg 13 - Collet Sleeve 13 18755 4154 90 3.735 5.634 17 #13 OH packer 19069 4154 90 3.898 5.750 18 Stg 12 - Collet Sleeve 12 19342 4154 90 3.735 5.634 19 #12 OH packer 19698 4152 90 3.898 5.750 20 Stg 11 - Collet Sleeve 11 19929 4153 90 3.735 5.634 21 #11 OH packer 20243 4151 90 3.898 5.750 22 Stg 10 - Collet Sleeve 10 20513 4149 90 3.735 5.634 23 #10 OH packer 20823 4148 90 3.898 5.750 24 Stg 9 - Collet Sleeve 9 21095 4147 90 3.735 5.634 25 #9 OH packer 21407 4145 90 3.898 5.750 26 Stg 8 - Collet Sleeve 8 21673 4144 90 3.735 5.634 27 #8 OH packer 21946 4143 90 3.898 5.750 28 Stg 7 - Collet Sleeve 7 22260 4143 90 3.735 5.634 29 #7 OH packer 22574 4141 90 3.898 5.750 30 Stg 6 - Collet Sleeve 6 22845 4140 90 3.735 5.634 31 #6 OH packer 23158 4139 90 3.898 5.750 32 Stg 5 - Collet Sleeve 5 23428 4137 90 3.735 5.634 33 #5 OH packer 23700 4136 90 3.898 5.750 34 Stg 4 - Collet Sleeve 4 23969 4134 90 3.735 5.634 35 #4 OH packer 24241 4132 91 3.898 5.750 36 Stg 3 - Collet Sleeve 3 24514 4129 91 3.735 5.634 37 #3 OH packer 24827 4126 91 3.898 5.750 38 Stg 2 - Collet Sleeve 2 25058 4125 90 3.735 5.634 39 #2 OH packer 25370 4122 91 3.898 5.750 40 Stg 1 - Collet Sleeve 1 25601 4120 91 3.735 5.634 41 #1 OH packer 25748 4118 91 3.898 5.750 42 Toe Sleeve 25814 4117 91 3.500 5.750 43 WIV Collar 25827 4117 91 N/A 5.620 44 Eccentric shoe 25840 4117 91 3.930 5.210 Attachment K Kinetix-Frac Completion Report Santos Country: United States Well Name: NDBi-034 Operator: Santos Field: Pikka Formation: Nanushuk Prepared By: Javier Del Real Report Date: January 8th 2026 NDBI-034 Stage N/A Page 2 of 97 Stage 1 Zoneset name: Stage 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 4007.97 29.83 0.7 2816.1 2786554.2 0.25 2500 Shale 4037.8 26.73 0.66 2665.6 2786554.2 0.25 2500 Top 3.2 NAN CS 4064.53 3.61 0.6 2460.1 1159218.9 0.26 600 Siltstone 4068.14 1.81 0.62 2510.6 1629236.3 0.26 1500 CleanSandstone 4069.95 1.8 0.6 2446.6 979798.8 0.26 600 Siltstone 4071.75 3.61 0.61 2468.5 1350455.1 0.26 1500 CleanSandstone 4075.36 3.58 0.61 2487.1 1206390.9 0.26 600 Siltstone 4078.94 3.61 0.61 2477 1313860.7 0.26 1500 CleanSandstone 4082.55 7.18 0.61 2480.3 1266403.2 0.26 600 Siltstone 4089.73 1.81 0.61 2479 1082935.6 0.26 1500 DirtySandstone 4091.54 1.8 0.62 2549.6 1222900.8 0.26 600 Shale 4093.34 1.8 0.62 2554.8 1419038.4 0.26 2500 DirtySandstone 4095.14 1.81 0.61 2519 1403385.6 0.26 600 NDBI-034 Stage N/A Page 3 of 97 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) Siltstone 4096.95 8.99 0.62 2534.7 1402756.3 0.26 1500 Shale 4105.94 3.61 0.66 2690.6 2181052.3 0.25 2500 DirtySandstone 4109.55 5.41 0.62 2553.7 1662780.4 0.26 1500 Siltstone 4114.96 1.77 0.63 2584.7 1963674.5 0.26 2500 DirtySandstone 4116.73 3.71 0.62 2561.8 1742901.7 0.26 1500 Siltstone 4120.44 5.41 0.63 2597.6 1681056.2 0.26 2500 Siltstone 4125.85 1.81 0.62 2566.9 1561073 0.26 1500 DirtySandstone 4127.66 1.8 0.62 2551.5 1262913.1 0.26 2500 Siltstone 4129.46 3.58 0.63 2611 1816969.7 0.26 1500 Shale 4133.04 11.02 0.65 2673.5 2238744.4 0.25 2500 CleanSandstone 4144.06 1.97 0.61 2516.1 1001510.6 0.26 600 Siltstone 4146.03 4 0.62 2571.8 1571504.2 0.26 1500 CleanSandstone 4150.03 2 0.6 2511.3 1267177.7 0.26 600 Shale 4152.03 2.01 0.66 2728.6 2789765.8 0.25 2500 Siltstone 4154.04 2 0.62 2563.7 1409418.9 0.26 1500 Shale 4156.04 2.1 0.66 2731.2 2789765.8 0.25 2500 NDBI-034 Stage N/A Page 4 of 97 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) DirtySandstone 4158.14 4 0.61 2537.7 1435306.6 0.26 1500 Siltstone 4162.14 4 0.62 2590.1 1765617.4 0.26 2500 DirtySandstone 4166.14 4 0.61 2559.2 1435651.3 0.26 1500 CleanSandstone 4170.14 2.1 0.59 2465.2 935658.3 0.26 2500 Siltstone 4172.24 4.01 0.62 2596.3 1491142.7 0.26 1500 Shale 4176.25 2 0.66 2744.4 2789765.8 0.25 2500 DirtySandstone 4178.25 10.99 0.62 2581.4 1462838 0.26 1500 Shale 4189.24 27 0.65 2740.2 2560999.9 0.25 2500 Siltstone 4216.24 2 0.63 2673.8 1857874.8 0.26 1500 Shale 4218.24 10.01 0.66 2770.5 2552268.6 0.25 2500 Siltstone 4228.25 2 0.63 2651.7 1509543.6 0.26 1500 Shale 4230.25 4.1 0.64 2708.7 2349461.1 0.25 2500 Siltstone 4234.35 2 0.64 2693.6 1482677.8 0.25 1500 Shale 4236.35 96.39 0.65 2797.8 2604074 0.25 2500 DirtySandstone 4332.74 2 0.61 2643.6 1153391 0.26 1500 Shale 4334.74 38.19 0.65 2851.7 2733692 0.25 2500 NDBI-034 Stage N/A Page 5 of 97 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) Siltstone 4372.93 2 0.62 2716.3 1526263.4 0.26 1500 Shale 4374.93 46.23 0.65 2880.7 2704369.9 0.25 2500 Siltstone 4421.16 1.97 0.64 2808.1 1825853.3 0.25 1500 Shale 4423.13 9.84 0.65 2891.5 2657615 0.25 2500 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 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 5027.5 125 CarboLite 16/20 1 5027.5 3.12 3 2 PPA 40 YF126ST 5402.2 140 CarboLite 16/20 2 10804.4 3.5 4 3 PPA 40 YF126ST 6303.8 170 CarboLite 16/20 3 18911.4 4.25 5 4 PPA 40 YF126ST 6066.9 170 CarboLite 16/20 4 24267.6 4.25 6 5 PPA 40 YF126ST 5847.3 170 CarboLite 16/20 5 29236.5 4.25 7 6 PPA 40 YF126ST 5642.9 170 CarboLite 16/20 6 33857.4 4.25 8 7 PPA 40 YF126ST 4490.2 140 CarboLite 16/20 7 31431.4 3.5 NDBI-034 Stage N/A Page 6 of 97 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) 9 8 PPA 40 YF126ST 3878.3 125 CarboLite 16/20 8 31026.4 3.13 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 28.25 24.84 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 59459.1 184562.6 1610 40.25 NDBI-034 Stage N/A Page 7 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 1 7373.4 233.68 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4025.9 4259.58 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 1 2.87 675.77 168.87 0.5 NDBI-034 Stage N/A Page 8 of 97 Stage 2 Zoneset name: Stage 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 4012.99 29.83 0.7 2819.68 2786554.2 0.25 2500 Shale 4042.81 26.73 0.66 2668.84 2786554.2 0.25 2500 Top 3.2 NAN CS 4069.52 3.61 0.6 2463.18 1159218.9 0.26 600 Siltstone 4073.16 1.81 0.62 2513.65 1629236.3 0.26 1500 CleanSandstone 4074.97 1.8 0.6 2449.69 979798.8 0.26 600 Siltstone 4076.77 3.61 0.61 2471.59 1350455.1 0.26 1500 CleanSandstone 4080.38 3.58 0.61 2490.15 1206390.9 0.26 600 Siltstone 4083.96 3.61 0.61 2480 1313860.7 0.26 1500 CleanSandstone 4087.57 7.18 0.61 2483.34 1266403.2 0.26 600 Siltstone 4094.75 1.81 0.61 2482.03 1082935.6 0.26 1500 DirtySandstone 4096.56 1.8 0.62 2552.66 1222900.8 0.26 600 Shale 4098.36 1.8 0.62 2557.89 1419038.4 0.26 2500 NDBI-034 Stage N/A Page 9 of 97 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) DirtySandstone 4100.13 1.81 0.61 2522.06 1403385.6 0.26 600 Siltstone 4101.97 8.99 0.62 2537.87 1402756.3 0.26 1500 Shale 4110.96 3.61 0.66 2693.93 2181052.3 0.25 2500 DirtySandstone 4114.57 5.41 0.62 2556.87 1662780.4 0.26 1500 Siltstone 4119.98 1.77 0.63 2587.91 1963674.5 0.26 2500 DirtySandstone 4121.75 3.71 0.62 2564.99 1742901.7 0.26 1500 Siltstone 4125.46 5.41 0.63 2600.82 1681056.2 0.26 2500 Siltstone 4130.87 1.81 0.62 2570.07 1561073 0.26 1500 DirtySandstone 4132.68 1.8 0.62 2554.55 1262913.1 0.26 2500 Siltstone 4134.48 3.58 0.63 2614.16 1816969.7 0.26 1500 Shale 4138.06 11.02 0.65 2676.67 2238744.4 0.25 2500 CleanSandstone 4149.08 1.97 0.61 2519.16 1001510.6 0.26 600 Siltstone 4151.05 4 0.62 2574.85 1571504.2 0.26 1500 CleanSandstone 4155.05 2 0.6 2514.37 1267177.7 0.26 600 Shale 4157.02 2.01 0.66 2731.93 2789765.8 0.25 2500 Siltstone 4159.06 2 0.62 2566.73 1409418.9 0.26 1500 NDBI-034 Stage N/A Page 10 of 97 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 4161.06 2.1 0.66 2734.54 2789765.8 0.25 2500 DirtySandstone 4163.16 4 0.61 2540.77 1435306.6 0.26 1500 Siltstone 4167.16 4 0.62 2593.27 1765617.4 0.26 2500 DirtySandstone 4171.16 4 0.61 2562.24 1435651.3 0.26 1500 CleanSandstone 4175.13 2.1 0.59 2468.11 935658.3 0.26 2500 Siltstone 4177.23 4.01 0.62 2599.37 1491142.7 0.26 1500 Shale 4181.27 2 0.66 2747.74 2789765.8 0.25 2500 DirtySandstone 4183.27 10.99 0.62 2584.43 1462838 0.26 1500 Shale 4194.26 27 0.65 2743.53 2560999.9 0.25 2500 Siltstone 4221.26 2 0.63 2676.96 1857874.8 0.26 1500 Shale 4223.26 10.01 0.66 2773.85 2552268.6 0.25 2500 Siltstone 4233.27 2 0.63 2654.92 1509543.6 0.26 1500 Shale 4235.27 4.1 0.64 2711.92 2349461.1 0.25 2500 Siltstone 4239.37 2 0.64 2696.83 1482677.8 0.25 1500 Shale 4241.37 96.39 0.65 2801.11 2604074 0.25 2500 DirtySandstone 4337.76 2 0.61 2646.65 1153391 0.26 1500 NDBI-034 Stage N/A Page 11 of 97 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 4339.73 38.19 0.65 2854.92 2733692 0.25 2500 Siltstone 4377.95 2 0.62 2719.46 1526263.4 0.26 1500 Shale 4379.92 46.23 0.65 2883.93 2704369.9 0.25 2500 Siltstone 4426.18 1.97 0.64 2811.27 1825853.3 0.25 1500 Shale 4428.15 9.84 0.65 2894.81 2657615 0.25 2500 NDBI-034 Stage N/A Page 12 of 97 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 40 YF126ST 18900 450 11.25 2 1 PPA 40 YF126ST 6033.2 150 CarboLite 16/20 1 6033.2 3.75 3 2 PPA 40 YF126ST 6752.7 175 CarboLite 16/20 2 13505.4 4.37 4 3 PPA 40 YF126ST 7416.2 200 CarboLite 16/20 3 22248.6 5 5 4 PPA 40 YF126ST 7137.5 200 CarboLite 16/20 4 28550 5 6 5 PPA 40 YF126ST 6879.2 200 CarboLite 16/20 5 34396 5 7 6 PPA 40 YF126ST 6638.7 200 CarboLite 16/20 6 39832.2 5 8 7 PPA 40 YF126ST 5452.4 170 CarboLite 16/20 7 38166.8 4.25 9 8 PPA 40 YF126ST 4188.4 135 CarboLite 16/20 8 33507.2 3.37 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.23 23.94 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 69398.3 216239.4 1879.99 47 NDBI-034 Stage N/A Page 13 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 2 7285 251.48 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4062.41 4313.89 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 2 2.35 825.9 184.62 0.45 NDBI-034 Stage N/A Page 14 of 97 Stage 3 Zoneset name: Stage 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 4017.98 29.83 0.7 2823.16 2786554.2 0.25 2500 Shale 4047.8 26.73 0.66 2672.18 2786554.2 0.25 2500 Top 3.2 NAN CS 4074.54 3.61 0.6 2466.22 1159218.9 0.26 600 Siltstone 4078.15 1.81 0.62 2516.84 1629236.3 0.26 1500 CleanSandstone 4079.95 1.8 0.6 2452.59 979798.8 0.26 600 Siltstone 4081.76 3.61 0.61 2474.63 1350455.1 0.26 1500 CleanSandstone 4085.37 3.58 0.61 2493.2 1206390.9 0.26 600 Siltstone 4088.94 3.61 0.61 2483.05 1313860.7 0.26 1500 CleanSandstone 4092.55 7.18 0.61 2486.38 1266403.2 0.26 600 Siltstone 4099.74 1.81 0.61 2485.08 1082935.6 0.26 1500 DirtySandstone 4101.54 1.8 0.62 2555.86 1222900.8 0.26 600 Shale 4103.35 1.8 0.62 2561.08 1419038.4 0.26 2500 NDBI-034 Stage N/A Page 15 of 97 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) DirtySandstone 4105.15 1.81 0.61 2525.11 1403385.6 0.26 600 Siltstone 4106.96 8.99 0.62 2540.92 1402756.3 0.26 1500 Shale 4115.94 3.61 0.66 2697.12 2181052.3 0.25 2500 DirtySandstone 4119.55 5.41 0.62 2559.92 1662780.4 0.26 1500 Siltstone 4124.97 1.77 0.63 2590.95 1963674.5 0.26 2500 DirtySandstone 4126.74 3.71 0.62 2568.04 1742901.7 0.26 1500 Siltstone 4130.45 5.41 0.63 2603.86 1681056.2 0.26 2500 Siltstone 4135.86 1.81 0.62 2573.11 1561073 0.26 1500 DirtySandstone 4137.66 1.8 0.62 2557.74 1262913.1 0.26 2500 Siltstone 4139.47 3.58 0.63 2617.35 1816969.7 0.26 1500 Shale 4143.04 11.02 0.65 2680.01 2238744.4 0.25 2500 CleanSandstone 4154.07 1.97 0.61 2522.21 1001510.6 0.26 600 Siltstone 4156.04 4 0.62 2578.05 1571504.2 0.26 1500 CleanSandstone 4160.04 2 0.6 2517.42 1267177.7 0.26 600 Shale 4162.04 2.01 0.66 2735.12 2789765.8 0.25 2500 Siltstone 4164.04 2 0.62 2569.92 1409418.9 0.26 1500 NDBI-034 Stage N/A Page 16 of 97 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 4166.04 2.1 0.66 2737.73 2789765.8 0.25 2500 DirtySandstone 4168.14 4 0.61 2543.82 1435306.6 0.26 1500 Siltstone 4172.15 4 0.62 2596.32 1765617.4 0.26 2500 DirtySandstone 4176.15 4 0.61 2565.28 1435651.3 0.26 1500 CleanSandstone 4180.15 2.1 0.59 2471.15 935658.3 0.26 2500 Siltstone 4182.25 4.01 0.62 2602.56 1491142.7 0.26 1500 Shale 4186.25 2 0.66 2750.93 2789765.8 0.25 2500 DirtySandstone 4188.25 10.99 0.62 2587.62 1462838 0.26 1500 Shale 4199.25 27 0.65 2746.72 2560999.9 0.25 2500 Siltstone 4226.25 2 0.63 2680.15 1857874.8 0.26 1500 Shale 4228.25 10.01 0.66 2777.04 2552268.6 0.25 2500 Siltstone 4238.25 2 0.63 2657.96 1509543.6 0.26 1500 Shale 4240.26 4.1 0.64 2715.11 2349461.1 0.25 2500 Siltstone 4244.36 2 0.64 2700.02 1482677.8 0.25 1500 Shale 4246.36 96.39 0.65 2804.3 2604074 0.25 2500 DirtySandstone 4342.75 2 0.61 2649.69 1153391 0.26 1500 NDBI-034 Stage N/A Page 17 of 97 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 4344.75 38.19 0.65 2858.26 2733692 0.25 2500 Siltstone 4382.94 2 0.62 2722.5 1526263.4 0.26 1500 Shale 4384.94 46.23 0.65 2887.27 2704369.9 0.25 2500 Siltstone 4431.17 1.97 0.64 2814.46 1825853.3 0.25 1500 Shale 4433.14 9.84 0.65 2898 2657615 0.25 2500 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 40 YF126ST 18900 450 11.25 2 1 PPA 40 YF126ST 6033.2 150 CarboLite 16/20 1 6033.2 3.75 3 2 PPA 40 YF126ST 6752.7 175 CarboLite 16/20 2 13505.4 4.37 4 3 PPA 40 YF126ST 7416.2 200 CarboLite 16/20 3 22248.6 5 5 4 PPA 40 YF126ST 7137.5 200 CarboLite 16/20 4 28550 5 6 5 PPA 40 YF126ST 6879.2 200 CarboLite 16/20 5 34396 5 7 6 PPA 40 YF126ST 6638.7 200 CarboLite 16/20 6 39832.2 5 NDBI-034 Stage N/A Page 18 of 97 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) 8 7 PPA 40 YF126ST 5452.4 170 CarboLite 16/20 7 38166.8 4.25 9 8 PPA 40 YF126ST 4188.4 135 CarboLite 16/20 8 33507.2 3.37 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.23 23.94 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 69398.3 216239.4 1879.99 47 NDBI-034 Stage N/A Page 19 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 3 7157.7 237.62 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4036 4273.62 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 3 2.98 697.03 181.31 0.53 NDBI-034 Stage N/A Page 20 of 97 Stage 4 Zoneset name: Stage 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 4022.97 29.83 0.7 2826.64 2786554.2 0.25 2500 Shale 4052.79 26.73 0.66 2675.51 2786554.2 0.25 2500 Top 3.2 NAN CS 4079.53 3.61 0.6 2469.12 1159218.9 0.26 600 Siltstone 4083.14 1.81 0.62 2519.89 1629236.3 0.26 1500 CleanSandstone 4084.94 1.8 0.6 2455.63 979798.8 0.26 600 Siltstone 4086.75 3.61 0.61 2477.53 1350455.1 0.26 1500 CleanSandstone 4090.35 3.58 0.61 2496.24 1206390.9 0.26 600 Siltstone 4093.93 3.61 0.61 2486.09 1313860.7 0.26 1500 CleanSandstone 4097.54 7.18 0.61 2489.43 1266403.2 0.26 600 Siltstone 4104.72 1.81 0.61 2488.12 1082935.6 0.26 1500 DirtySandstone 4106.53 1.8 0.62 2558.9 1222900.8 0.26 600 Shale 4108.33 1.8 0.62 2564.12 1419038.4 0.26 2500 NDBI-034 Stage N/A Page 21 of 97 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) DirtySandstone 4110.14 1.81 0.61 2528.15 1403385.6 0.26 600 Siltstone 4111.94 8.99 0.62 2543.96 1402756.3 0.26 1500 Shale 4120.93 3.61 0.66 2700.46 2181052.3 0.25 2500 DirtySandstone 4124.54 5.41 0.62 2562.96 1662780.4 0.26 1500 Siltstone 4129.95 1.77 0.63 2594.14 1963674.5 0.26 2500 DirtySandstone 4131.73 3.71 0.62 2571.08 1742901.7 0.26 1500 Siltstone 4135.43 5.41 0.63 2607.05 1681056.2 0.26 2500 Siltstone 4140.85 1.81 0.62 2576.16 1561073 0.26 1500 DirtySandstone 4142.65 1.8 0.62 2560.79 1262913.1 0.26 2500 Siltstone 4144.46 3.58 0.63 2620.54 1816969.7 0.26 1500 Shale 4148.03 11.02 0.65 2683.2 2238744.4 0.25 2500 CleanSandstone 4159.06 1.97 0.61 2525.25 1001510.6 0.26 600 Siltstone 4161.02 4 0.62 2581.09 1571504.2 0.26 1500 CleanSandstone 4165.03 2 0.6 2520.32 1267177.7 0.26 600 Shale 4167.03 2.01 0.66 2738.46 2789765.8 0.25 2500 Siltstone 4169.03 2 0.62 2572.97 1409418.9 0.26 1500 NDBI-034 Stage N/A Page 22 of 97 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 4171.03 2.1 0.66 2741.07 2789765.8 0.25 2500 DirtySandstone 4173.13 4 0.61 2546.86 1435306.6 0.26 1500 Siltstone 4177.13 4 0.62 2599.37 1765617.4 0.26 2500 DirtySandstone 4181.14 4 0.61 2568.47 1435651.3 0.26 1500 CleanSandstone 4185.14 2.1 0.59 2474.05 935658.3 0.26 2500 Siltstone 4187.24 4.01 0.62 2605.6 1491142.7 0.26 1500 Shale 4191.24 2 0.66 2754.27 2789765.8 0.25 2500 DirtySandstone 4193.24 10.99 0.62 2590.66 1462838 0.26 1500 Shale 4204.23 27 0.65 2749.92 2560999.9 0.25 2500 Siltstone 4231.23 2 0.63 2683.34 1857874.8 0.26 1500 Shale 4233.23 10.01 0.66 2780.37 2552268.6 0.25 2500 Siltstone 4243.24 2 0.63 2661.15 1509543.6 0.26 1500 Shale 4245.24 4.1 0.64 2718.3 2349461.1 0.25 2500 Siltstone 4249.34 2 0.64 2703.07 1482677.8 0.25 1500 Shale 4251.35 96.39 0.65 2807.64 2604074 0.25 2500 DirtySandstone 4347.74 2 0.61 2652.74 1153391 0.26 1500 NDBI-034 Stage N/A Page 23 of 97 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 4349.74 38.19 0.65 2861.59 2733692 0.25 2500 Siltstone 4387.93 2 0.62 2725.55 1526263.4 0.26 1500 Shale 4389.93 46.23 0.65 2890.46 2704369.9 0.25 2500 Siltstone 4436.15 1.97 0.64 2817.65 1825853.3 0.25 1500 Shale 4438.12 9.84 0.65 2901.33 2657615 0.25 2500 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 40 YF126ST 17850 425 10.62 2 1 PPA 40 YF126ST 6435.4 160 CarboLite 16/20 1 6435.4 4 3 2 PPA 40 YF126ST 6559.8 170 CarboLite 16/20 2 13119.6 4.25 4 3 PPA 40 YF126ST 6859.9 185 CarboLite 16/20 3 20579.7 4.62 5 4 PPA 40 YF126ST 6602.2 185 CarboLite 16/20 4 26408.8 4.62 6 5 PPA 40 YF126ST 6363.2 185 CarboLite 16/20 5 31816 4.62 7 6 PPA 40 YF126ST 6140.8 185 CarboLite 16/20 6 36844.8 4.62 NDBI-034 Stage N/A Page 24 of 97 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) 8 7 PPA 40 YF126ST 4971.2 155 CarboLite 16/20 7 34798.4 3.87 9 8 PPA 40 YF126ST 4343.5 140 CarboLite 16/20 8 34748 3.5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.99 23.74 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 66126 204750.7 1789.98 44.75 NDBI-034 Stage N/A Page 25 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 4 7018.2 235.29 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 4 2.97 697.87 177.89 0.53 NDBI-034 Stage N/A Page 26 of 97 Stage 5 Zoneset name: Stage 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 4025.98 29.83 0.7 2828.67 2786554.2 0.25 2500 Shale 4055.81 26.73 0.66 2677.4 2786554.2 0.25 2500 Top 3.2 NAN CS 4082.55 3.61 0.6 2471.01 1159218.9 0.26 600 Siltstone 4086.15 1.81 0.62 2521.77 1629236.3 0.26 1500 CleanSandstone 4087.96 1.8 0.6 2457.37 979798.8 0.26 600 Siltstone 4089.76 3.61 0.61 2479.42 1350455.1 0.26 1500 CleanSandstone 4093.37 3.58 0.61 2498.13 1206390.9 0.26 600 Siltstone 4096.95 3.61 0.61 2487.98 1313860.7 0.26 1500 CleanSandstone 4100.56 7.18 0.61 2491.17 1266403.2 0.26 600 Siltstone 4107.74 1.81 0.61 2489.86 1082935.6 0.26 1500 DirtySandstone 4109.55 1.8 0.62 2560.79 1222900.8 0.26 600 Shale 4111.35 1.8 0.62 2566.01 1419038.4 0.26 2500 NDBI-034 Stage N/A Page 27 of 97 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) DirtySandstone 4113.16 1.81 0.61 2530.04 1403385.6 0.26 600 Siltstone 4114.96 8.99 0.62 2545.85 1402756.3 0.26 1500 Shale 4123.95 3.61 0.66 2702.34 2181052.3 0.25 2500 DirtySandstone 4127.56 5.41 0.62 2564.85 1662780.4 0.26 1500 Siltstone 4132.97 1.77 0.63 2596.03 1963674.5 0.26 2500 DirtySandstone 4134.74 3.71 0.62 2572.97 1742901.7 0.26 1500 Siltstone 4138.45 5.41 0.63 2608.94 1681056.2 0.26 2500 Siltstone 4143.86 1.81 0.62 2578.05 1561073 0.26 1500 DirtySandstone 4145.67 1.8 0.62 2562.67 1262913.1 0.26 2500 Siltstone 4147.47 3.58 0.63 2622.43 1816969.7 0.26 1500 Shale 4151.05 11.02 0.65 2685.08 2238744.4 0.25 2500 CleanSandstone 4162.07 1.97 0.61 2526.99 1001510.6 0.26 600 Siltstone 4164.04 4 0.62 2582.98 1571504.2 0.26 1500 CleanSandstone 4168.04 2 0.6 2522.21 1267177.7 0.26 600 Shale 4170.05 2.01 0.66 2740.49 2789765.8 0.25 2500 Siltstone 4172.05 2 0.62 2574.85 1409418.9 0.26 1500 NDBI-034 Stage N/A Page 28 of 97 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 4174.05 2.1 0.66 2743.1 2789765.8 0.25 2500 DirtySandstone 4176.15 4 0.61 2548.75 1435306.6 0.26 1500 Siltstone 4180.15 4 0.62 2601.25 1765617.4 0.26 2500 DirtySandstone 4184.15 4 0.61 2570.21 1435651.3 0.26 1500 CleanSandstone 4188.16 2.1 0.59 2475.79 935658.3 0.26 2500 Siltstone 4190.26 4.01 0.62 2607.49 1491142.7 0.26 1500 Shale 4194.26 2 0.66 2756.3 2789765.8 0.25 2500 DirtySandstone 4196.26 10.99 0.62 2592.55 1462838 0.26 1500 Shale 4207.25 27 0.65 2751.95 2560999.9 0.25 2500 Siltstone 4234.25 2 0.63 2685.23 1857874.8 0.26 1500 Shale 4236.25 10.01 0.66 2782.26 2552268.6 0.25 2500 Siltstone 4246.26 2 0.63 2663.04 1509543.6 0.26 1500 Shale 4248.26 4.1 0.64 2720.18 2349461.1 0.25 2500 Siltstone 4252.36 2 0.64 2705.1 1482677.8 0.25 1500 Shale 4254.36 96.39 0.65 2809.53 2604074 0.25 2500 DirtySandstone 4350.75 2 0.61 2654.63 1153391 0.26 1500 NDBI-034 Stage N/A Page 29 of 97 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 4352.76 38.19 0.65 2863.48 2733692 0.25 2500 Siltstone 4390.94 2 0.62 2727.43 1526263.4 0.26 1500 Shale 4392.95 46.23 0.65 2892.49 2704369.9 0.25 2500 Siltstone 4439.17 1.97 0.64 2819.53 1825853.3 0.25 1500 Shale 4441.14 9.84 0.65 2903.22 2657615 0.25 2500 NDBI-034 Stage N/A Page 30 of 97 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 18900 450 11.25 2 1 PPA 40 YF126ST 6636.5 165 CarboLite 16/20 1 6636.5 4.12 3 2 PPA 40 YF126ST 6945.6 180 CarboLite 16/20 2 13891.2 4.5 4 3 PPA 40 YF126ST 7230.8 195 CarboLite 16/20 3 21692.4 4.87 5 4 PPA 40 YF126ST 6959.1 195 CarboLite 16/20 4 27836.4 4.87 6 5 PPA 40 YF126ST 6707 195 CarboLite 16/20 5 33535 4.87 7 6 PPA 40 YF126ST 6472.8 195 CarboLite 16/20 6 38836.8 4.88 8 7 PPA 40 YF126ST 5933.4 185 CarboLite 16/20 7 41533.8 4.62 9 8 PPA 40 YF126ST 5274.3 170 CarboLite 16/20 8 42194.4 4.25 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.6 23.32 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71059.5 226156.5 1929.98 48.25 NDBI-034 Stage N/A Page 31 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 5 6969.9 235.31 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4044.87 4280.18 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 5 5.62 666.7 182.82 0.56 NDBI-034 Stage N/A Page 32 of 97 Stage 6 Zoneset name: Stage 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 4030.97 29.83 0.7 2832.15 2786554.2 0.25 2500 Shale 4060.79 26.73 0.66 2680.73 2786554.2 0.25 2500 Top 3.2 NAN CS 4087.53 3.61 0.6 2474.05 1159218.9 0.26 600 Siltstone 4091.14 1.81 0.62 2524.82 1629236.3 0.26 1500 CleanSandstone 4092.95 1.8 0.6 2460.42 979798.8 0.26 600 Siltstone 4094.75 3.61 0.61 2482.47 1350455.1 0.26 1500 CleanSandstone 4098.36 3.58 0.61 2501.18 1206390.9 0.26 600 Siltstone 4101.94 3.61 0.61 2491.02 1313860.7 0.26 1500 CleanSandstone 4105.54 7.18 0.61 2494.21 1266403.2 0.26 600 Siltstone 4112.73 1.81 0.61 2492.91 1082935.6 0.26 1500 DirtySandstone 4114.53 1.8 0.62 2563.98 1222900.8 0.26 600 Shale 4116.34 1.8 0.62 2569.2 1419038.4 0.26 2500 NDBI-034 Stage N/A Page 33 of 97 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) DirtySandstone 4118.14 1.81 0.61 2533.08 1403385.6 0.26 600 Siltstone 4119.95 8.99 0.62 2548.89 1402756.3 0.26 1500 Shale 4128.94 3.61 0.66 2705.68 2181052.3 0.25 2500 DirtySandstone 4132.55 5.41 0.62 2568.04 1662780.4 0.26 1500 Siltstone 4137.96 1.77 0.63 2599.08 1963674.5 0.26 2500 DirtySandstone 4139.73 3.71 0.62 2576.16 1742901.7 0.26 1500 Siltstone 4143.44 5.41 0.63 2612.13 1681056.2 0.26 2500 Siltstone 4148.85 1.81 0.62 2581.24 1561073 0.26 1500 DirtySandstone 4150.66 1.8 0.62 2565.72 1262913.1 0.26 2500 Siltstone 4152.46 3.58 0.63 2625.47 1816969.7 0.26 1500 Shale 4156.04 11.02 0.65 2688.42 2238744.4 0.25 2500 CleanSandstone 4167.06 1.97 0.61 2530.04 1001510.6 0.26 600 Siltstone 4169.03 4 0.62 2586.02 1571504.2 0.26 1500 CleanSandstone 4173.03 2 0.6 2525.25 1267177.7 0.26 600 Shale 4175.03 2.01 0.66 2743.68 2789765.8 0.25 2500 Siltstone 4177.03 2 0.62 2577.9 1409418.9 0.26 1500 NDBI-034 Stage N/A Page 34 of 97 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 4179.04 2.1 0.66 2746.29 2789765.8 0.25 2500 DirtySandstone 4181.14 4 0.61 2551.79 1435306.6 0.26 1500 Siltstone 4185.14 4 0.62 2604.44 1765617.4 0.26 2500 DirtySandstone 4189.14 4 0.61 2573.26 1435651.3 0.26 1500 CleanSandstone 4193.14 2.1 0.59 2478.84 935658.3 0.26 2500 Siltstone 4195.24 4.01 0.62 2610.53 1491142.7 0.26 1500 Shale 4199.25 2 0.66 2759.49 2789765.8 0.25 2500 DirtySandstone 4201.25 10.99 0.62 2595.6 1462838 0.26 1500 Shale 4212.24 27 0.65 2755.14 2560999.9 0.25 2500 Siltstone 4239.24 2 0.63 2688.42 1857874.8 0.26 1500 Shale 4241.24 10.01 0.66 2785.59 2552268.6 0.25 2500 Siltstone 4251.25 2 0.63 2666.08 1509543.6 0.26 1500 Shale 4253.25 4.1 0.64 2723.37 2349461.1 0.25 2500 Siltstone 4257.35 2 0.64 2708.29 1482677.8 0.25 1500 Shale 4259.35 96.39 0.65 2812.86 2604074 0.25 2500 DirtySandstone 4355.74 2 0.61 2657.67 1153391 0.26 1500 NDBI-034 Stage N/A Page 35 of 97 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 4357.74 38.19 0.65 2866.82 2733692 0.25 2500 Siltstone 4395.93 2 0.62 2730.63 1526263.4 0.26 1500 Shale 4397.93 46.23 0.65 2895.82 2704369.9 0.25 2500 Siltstone 4444.16 1.97 0.64 2822.72 1825853.3 0.25 1500 Shale 4446.13 9.84 0.65 2906.56 2657615 0.25 2500 NDBI-034 Stage N/A Page 36 of 97 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 18900 450 11.25 2 1 PPA 40 YF126ST 6636.5 165 CarboLite 16/20 1 6636.5 4.12 3 2 PPA 40 YF126ST 6945.6 180 CarboLite 16/20 2 13891.2 4.5 4 3 PPA 40 YF126ST 7230.8 195 CarboLite 16/20 3 21692.4 4.87 5 4 PPA 40 YF126ST 6959.1 195 CarboLite 16/20 4 27836.4 4.87 6 5 PPA 40 YF126ST 6707 195 CarboLite 16/20 5 33535 4.87 7 6 PPA 40 YF126ST 6472.8 195 CarboLite 16/20 6 38836.8 4.88 8 7 PPA 40 YF126ST 5933.4 185 CarboLite 16/20 7 41533.8 4.62 9 8 PPA 40 YF126ST 5274.3 170 CarboLite 16/20 8 42194.4 4.25 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.6 23.32 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71059.5 226156.5 1929.98 48.25 NDBI-034 Stage N/A Page 37 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max SurfacePressure (psi) Max Height (ft) Stage 6 6816.8 233.23 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4047.45 4280.68 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 6 3.73 662.58 181.14 0.56 NDBI-034 Stage N/A Page 38 of 97 Stage 7 Zoneset name: Stage 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 4036.48 29.83 0.7 2836.07 2786554.2 0.25 2500 Shale 4066.31 26.73 0.66 2684.36 2786554.2 0.25 2500 Top 3.2 NAN CS 4093.04 3.61 0.6 2477.39 1159218.9 0.26 600 Siltstone 4096.65 1.81 0.62 2528.15 1629236.3 0.26 1500 CleanSandstone 4098.46 1.8 0.6 2463.76 979798.8 0.26 600 Siltstone 4100.26 3.61 0.61 2485.8 1350455.1 0.26 1500 CleanSandstone 4103.87 3.58 0.61 2504.51 1206390.9 0.26 600 Siltstone 4107.45 3.61 0.61 2494.36 1313860.7 0.26 1500 CleanSandstone 4111.06 7.18 0.61 2497.55 1266403.2 0.26 600 Siltstone 4118.24 1.81 0.61 2496.24 1082935.6 0.26 1500 DirtySandstone 4120.05 1.8 0.62 2567.31 1222900.8 0.26 600 Shale 4121.85 1.8 0.62 2572.53 1419038.4 0.26 2500 NDBI-034 Stage N/A Page 39 of 97 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) DirtySandstone 4123.65 1.81 0.61 2536.56 1403385.6 0.26 600 Siltstone 4125.46 8.99 0.62 2552.37 1402756.3 0.26 1500 Shale 4134.45 3.61 0.66 2709.3 2181052.3 0.25 2500 DirtySandstone 4138.06 5.41 0.62 2571.37 1662780.4 0.26 1500 Siltstone 4143.47 1.77 0.63 2602.56 1963674.5 0.26 2500 DirtySandstone 4145.24 3.71 0.62 2579.5 1742901.7 0.26 1500 Siltstone 4148.95 5.41 0.63 2615.61 1681056.2 0.26 2500 Siltstone 4154.36 1.81 0.62 2584.57 1561073 0.26 1500 DirtySandstone 4156.17 1.8 0.62 2569.05 1262913.1 0.26 2500 Siltstone 4157.97 3.58 0.63 2628.95 1816969.7 0.26 1500 Shale 4161.55 11.02 0.65 2691.9 2238744.4 0.25 2500 CleanSandstone 4172.57 1.97 0.61 2533.37 1001510.6 0.26 600 Siltstone 4174.54 4 0.62 2589.5 1571504.2 0.26 1500 CleanSandstone 4178.54 2 0.6 2528.59 1267177.7 0.26 600 Shale 4180.54 2.01 0.66 2747.3 2789765.8 0.25 2500 Siltstone 4182.55 2 0.62 2581.24 1409418.9 0.26 1500 NDBI-034 Stage N/A Page 40 of 97 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 4184.55 2.1 0.66 2749.92 2789765.8 0.25 2500 DirtySandstone 4186.65 4 0.61 2555.13 1435306.6 0.26 1500 Siltstone 4190.65 4 0.62 2607.78 1765617.4 0.26 2500 DirtySandstone 4194.65 4 0.61 2576.74 1435651.3 0.26 1500 CleanSandstone 4198.65 2.1 0.59 2482.03 935658.3 0.26 2500 Siltstone 4200.75 4.01 0.62 2614.02 1491142.7 0.26 1500 Shale 4204.76 2 0.66 2763.11 2789765.8 0.25 2500 DirtySandstone 4206.76 10.99 0.62 2598.93 1462838 0.26 1500 Shale 4217.75 27 0.65 2758.76 2560999.9 0.25 2500 Siltstone 4244.75 2 0.63 2691.9 1857874.8 0.26 1500 Shale 4246.75 10.01 0.66 2789.22 2552268.6 0.25 2500 Siltstone 4256.76 2 0.63 2669.56 1509543.6 0.26 1500 Shale 4258.76 4.1 0.64 2727 2349461.1 0.25 2500 Siltstone 4262.86 2 0.64 2711.77 1482677.8 0.25 1500 Shale 4264.86 96.39 0.65 2816.49 2604074 0.25 2500 DirtySandstone 4361.25 2 0.61 2661.01 1153391 0.26 1500 NDBI-034 Stage N/A Page 41 of 97 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 4363.25 38.19 0.65 2870.44 2733692 0.25 2500 Siltstone 4401.44 2 0.62 2733.96 1526263.4 0.26 1500 Shale 4403.44 46.23 0.65 2899.3 2704369.9 0.25 2500 Siltstone 4449.67 1.97 0.64 2826.21 1825853.3 0.25 1500 Shale 4451.64 9.84 0.65 2910.18 2657615 0.25 2500 NDBI-034 Stage N/A Page 42 of 97 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 18900 450 11.25 2 1 PPA 40 YF126ST 6636.5 165 CarboLite 16/20 1 6636.5 4.12 3 2 PPA 40 YF126ST 6945.6 180 CarboLite 16/20 2 13891.2 4.5 4 3 PPA 40 YF126ST 7230.8 195 CarboLite 16/20 3 21692.4 4.87 5 4 PPA 40 YF126ST 6959.1 195 CarboLite 16/20 4 27836.4 4.87 6 5 PPA 40 YF126ST 6707 195 CarboLite 16/20 5 33535 4.87 7 6 PPA 40 YF126ST 6472.8 195 CarboLite 16/20 6 38836.8 4.88 8 7 PPA 40 YF126ST 5933.4 185 CarboLite 16/20 7 41533.8 4.62 9 8 PPA 40 YF126ST 5274.3 170 CarboLite 16/20 8 42194.4 4.25 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.6 23.32 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71059.5 226156.5 1929.98 48.25 NDBI-034 Stage N/A Page 43 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 7 6671.4 228.64 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4051.51 4280.15 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 7 4.33 604.23 191.4 0.59 NDBI-034 Stage N/A Page 44 of 97 Stage 8 Zoneset name: Stage 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 4039.47 29.83 0.7 2838.1 2786554.2 0.25 2500 Shale 4069.29 26.73 0.66 2686.39 2786554.2 0.25 2500 Top 3.2 NAN CS 4096.03 3.61 0.6 2479.13 1159218.9 0.26 600 Siltstone 4099.64 1.81 0.62 2530.04 1629236.3 0.26 1500 CleanSandstone 4101.44 1.8 0.6 2465.5 979798.8 0.26 600 Siltstone 4103.25 3.61 0.61 2487.54 1350455.1 0.26 1500 CleanSandstone 4106.86 3.58 0.61 2506.25 1206390.9 0.26 600 Siltstone 4110.43 3.61 0.61 2496.1 1313860.7 0.26 1500 CleanSandstone 4114.04 7.18 0.61 2499.44 1266403.2 0.26 600 Siltstone 4121.23 1.81 0.61 2498.13 1082935.6 0.26 1500 DirtySandstone 4123.03 1.8 0.62 2569.2 1222900.8 0.26 600 Shale 4124.84 1.8 0.62 2574.42 1419038.4 0.26 2500 DirtySandstone 4126.64 1.81 0.61 2538.31 1403385.6 0.26 600 NDBI-034 Stage N/A Page 45 of 97 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) Siltstone 4128.44 8.99 0.62 2554.11 1402756.3 0.26 1500 Shale 4137.43 3.61 0.66 2711.19 2181052.3 0.25 2500 DirtySandstone 4141.04 5.41 0.62 2573.26 1662780.4 0.26 1500 Siltstone 4146.46 1.77 0.63 2604.44 1963674.5 0.26 2500 DirtySandstone 4148.23 3.71 0.62 2581.38 1742901.7 0.26 1500 Siltstone 4151.94 5.41 0.63 2617.5 1681056.2 0.26 2500 Siltstone 4157.35 1.81 0.62 2586.46 1561073 0.26 1500 DirtySandstone 4159.15 1.8 0.62 2570.94 1262913.1 0.26 2500 Siltstone 4160.96 3.58 0.63 2630.84 1816969.7 0.26 1500 Shale 4164.53 11.02 0.65 2693.79 2238744.4 0.25 2500 CleanSandstone 4175.56 1.97 0.61 2535.26 1001510.6 0.26 600 Siltstone 4177.53 4 0.62 2591.39 1571504.2 0.26 1500 CleanSandstone 4181.53 2 0.6 2530.33 1267177.7 0.26 600 Shale 4183.53 2.01 0.66 2749.34 2789765.8 0.25 2500 Siltstone 4185.53 2 0.62 2583.12 1409418.9 0.26 1500 Shale 4187.53 2.1 0.66 2751.95 2789765.8 0.25 2500 NDBI-034 Stage N/A Page 46 of 97 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) DirtySandstone 4189.63 4 0.61 2556.87 1435306.6 0.26 1500 Siltstone 4193.64 4 0.62 2609.66 1765617.4 0.26 2500 DirtySandstone 4197.64 4 0.61 2578.48 1435651.3 0.26 1500 CleanSandstone 4201.64 2.1 0.59 2483.77 935658.3 0.26 2500 Siltstone 4203.74 4.01 0.62 2615.9 1491142.7 0.26 1500 Shale 4207.74 2 0.66 2765.14 2789765.8 0.25 2500 DirtySandstone 4209.74 10.99 0.62 2600.82 1462838 0.26 1500 Shale 4220.73 27 0.65 2760.79 2560999.9 0.25 2500 Siltstone 4247.74 2 0.63 2693.79 1857874.8 0.26 1500 Shale 4249.74 10.01 0.66 2791.11 2552268.6 0.25 2500 Siltstone 4259.74 2 0.63 2671.45 1509543.6 0.26 1500 Shale 4261.75 4.1 0.64 2728.89 2349461.1 0.25 2500 Siltstone 4265.85 2 0.64 2713.66 1482677.8 0.25 1500 Shale 4267.85 96.39 0.65 2818.37 2604074 0.25 2500 DirtySandstone 4364.24 2 0.61 2662.75 1153391 0.26 1500 Shale 4366.24 38.19 0.65 2872.33 2733692 0.25 2500 NDBI-034 Stage N/A Page 47 of 97 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) Siltstone 4404.43 2 0.62 2735.85 1526263.4 0.26 1500 Shale 4406.43 46.23 0.65 2901.33 2704369.9 0.25 2500 Siltstone 4452.66 1.97 0.64 2828.09 1825853.3 0.25 1500 Shale 4454.63 9.84 0.65 2912.07 2657615 0.25 2500 NDBI-034 Stage N/A Page 48 of 97 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 18900 450 11.25 2 1 PPA 40 YF126ST 6636.5 165 CarboLite 16/20 1 6636.5 4.12 3 2 PPA 40 YF126ST 6945.6 180 CarboLite 16/20 2 13891.2 4.5 4 3 PPA 40 YF126ST 7230.8 195 CarboLite 16/20 3 21692.4 4.87 5 4 PPA 40 YF126ST 6959.1 195 CarboLite 16/20 4 27836.4 4.87 6 5 PPA 40 YF126ST 6707 195 CarboLite 16/20 5 33535 4.87 7 6 PPA 40 YF126ST 6472.8 195 CarboLite 16/20 6 38836.8 4.88 8 7 PPA 40 YF126ST 5933.4 185 CarboLite 16/20 7 41533.8 4.62 9 8 PPA 40 YF126ST 5274.3 170 CarboLite 16/20 8 42194.4 4.25 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.6 23.32 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71059.5 226156.5 1929.98 48.25 NDBI-034 Stage N/A Page 49 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 8 6539.3 225.15 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4052.05 4277.2 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 8 4.55 591.24 193.3 0.61 NDBI-034 Stage N/A Page 50 of 97 Stage 9 Zoneset name: Stage 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 4045.18 29.83 0.7 2842.16 2786554.2 0.25 2500 Shale 4075 26.73 0.66 2690.01 2786554.2 0.25 2500 Top 3.2 NAN CS 4101.74 3.61 0.6 2482.61 1159218.9 0.26 600 Siltstone 4105.35 1.81 0.62 2533.52 1629236.3 0.26 1500 CleanSandstone 4107.15 1.8 0.6 2468.98 979798.8 0.26 600 Siltstone 4108.96 3.61 0.61 2491.02 1350455.1 0.26 1500 CleanSandstone 4112.57 3.58 0.61 2509.73 1206390.9 0.26 600 Siltstone 4116.14 3.61 0.61 2499.58 1313860.7 0.26 1500 CleanSandstone 4119.75 7.18 0.61 2502.92 1266403.2 0.26 600 Siltstone 4126.94 1.81 0.61 2501.61 1082935.6 0.26 1500 DirtySandstone 4128.74 1.8 0.62 2572.82 1222900.8 0.26 600 Shale 4130.54 1.8 0.62 2578.05 1419038.4 0.26 2500 NDBI-034 Stage N/A Page 51 of 97 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) DirtySandstone 4132.35 1.81 0.61 2541.93 1403385.6 0.26 600 Siltstone 4134.15 8.99 0.62 2557.74 1402756.3 0.26 1500 Shale 4143.14 3.61 0.66 2714.96 2181052.3 0.25 2500 DirtySandstone 4146.75 5.41 0.62 2576.74 1662780.4 0.26 1500 Siltstone 4152.17 1.77 0.63 2608.07 1963674.5 0.26 2500 DirtySandstone 4153.94 3.71 0.62 2585.01 1742901.7 0.26 1500 Siltstone 4157.64 5.41 0.63 2620.98 1681056.2 0.26 2500 Siltstone 4163.06 1.81 0.62 2590.08 1561073 0.26 1500 DirtySandstone 4164.86 1.8 0.62 2574.56 1262913.1 0.26 2500 Siltstone 4166.67 3.58 0.63 2634.47 1816969.7 0.26 1500 Shale 4170.24 11.02 0.65 2697.56 2238744.4 0.25 2500 CleanSandstone 4181.27 1.97 0.61 2538.74 1001510.6 0.26 600 Siltstone 4183.23 4 0.62 2594.87 1571504.2 0.26 1500 CleanSandstone 4187.24 2 0.6 2533.81 1267177.7 0.26 600 Shale 4189.24 2.01 0.66 2753.11 2789765.8 0.25 2500 Siltstone 4191.24 2 0.62 2586.6 1409418.9 0.26 1500 NDBI-034 Stage N/A Page 52 of 97 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 4193.24 2.1 0.66 2755.57 2789765.8 0.25 2500 DirtySandstone 4195.34 4 0.61 2560.35 1435306.6 0.26 1500 Siltstone 4199.34 4 0.62 2613.29 1765617.4 0.26 2500 DirtySandstone 4203.35 4 0.61 2582.11 1435651.3 0.26 1500 CleanSandstone 4207.35 2.1 0.59 2487.25 935658.3 0.26 2500 Siltstone 4209.45 4.01 0.62 2619.38 1491142.7 0.26 1500 Shale 4213.45 2 0.66 2768.77 2789765.8 0.25 2500 DirtySandstone 4215.45 10.99 0.62 2604.3 1462838 0.26 1500 Shale 4226.44 27 0.65 2764.42 2560999.9 0.25 2500 Siltstone 4253.44 2 0.63 2697.41 1857874.8 0.26 1500 Shale 4255.45 10.01 0.66 2794.88 2552268.6 0.25 2500 Siltstone 4265.45 2 0.63 2675.08 1509543.6 0.26 1500 Shale 4267.45 4.1 0.64 2732.51 2349461.1 0.25 2500 Siltstone 4271.56 2 0.64 2717.28 1482677.8 0.25 1500 Shale 4273.56 96.39 0.65 2822.14 2604074 0.25 2500 DirtySandstone 4369.95 2 0.61 2666.23 1153391 0.26 1500 NDBI-034 Stage N/A Page 53 of 97 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 4371.95 38.19 0.65 2876.1 2733692 0.25 2500 Siltstone 4410.14 2 0.62 2739.47 1526263.4 0.26 1500 Shale 4412.14 46.23 0.65 2905.11 2704369.9 0.25 2500 Siltstone 4458.37 1.97 0.64 2831.72 1825853.3 0.25 1500 Shale 4460.33 9.84 0.65 2915.84 2657615 0.25 2500 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 18900 450 11.25 2 1 PPA 40 YF126ST 6636.5 165 CarboLite 16/20 1 6636.5 4.12 3 2 PPA 40 YF126ST 6945.6 180 CarboLite 16/20 2 13891.2 4.5 4 3 PPA 40 YF126ST 7230.8 195 CarboLite 16/20 3 21692.4 4.87 5 4 PPA 40 YF126ST 6959.1 195 CarboLite 16/20 4 27836.4 4.87 6 5 PPA 40 YF126ST 6707 195 CarboLite 16/20 5 33535 4.87 7 6 PPA 40 YF126ST 6472.8 195 CarboLite 16/20 6 38836.8 4.88 NDBI-034 Stage N/A Page 54 of 97 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) 8 7 PPA 40 YF126ST 5933.4 185 CarboLite 16/20 7 41533.8 4.62 9 8 PPA 40 YF126ST 5274.3 170 CarboLite 16/20 8 42194.4 4.25 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.6 23.32 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71059.5 226156.5 1929.98 48.25 NDBI-034 Stage N/A Page 55 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 9 6260.1 353.49 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4039 4392.49 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 9 1.39 985.25 294.84 0.31 NDBI-034 Stage N/A Page 56 of 97 Stage 10 Zoneset name: Stage 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 4044.16 29.83 0.7 2841.43 2786554.2 0.25 2500 Shale 4074.02 26.73 0.66 2689.43 2786554.2 0.25 2500 Top 3.2 NAN CS 4100.72 3.61 0.6 2482.03 1159218.9 0.26 600 Siltstone 4104.33 1.81 0.62 2532.94 1629236.3 0.26 1500 CleanSandstone 4106.14 1.8 0.6 2468.4 979798.8 0.26 600 Siltstone 4107.94 3.61 0.61 2490.44 1350455.1 0.26 1500 CleanSandstone 4111.55 3.58 0.61 2509.15 1206390.9 0.26 600 Siltstone 4115.12 3.61 0.61 2499 1313860.7 0.26 1500 CleanSandstone 4118.77 7.18 0.61 2502.34 1266403.2 0.26 600 Siltstone 4125.92 1.81 0.61 2500.89 1082935.6 0.26 1500 DirtySandstone 4127.76 1.8 0.62 2572.1 1222900.8 0.26 600 Shale 4129.53 1.8 0.62 2577.32 1419038.4 0.26 2500 NDBI-034 Stage N/A Page 57 of 97 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) DirtySandstone 4131.33 1.81 0.61 2541.21 1403385.6 0.26 600 Siltstone 4133.14 8.99 0.62 2557.02 1402756.3 0.26 1500 Shale 4142.13 3.61 0.66 2714.24 2181052.3 0.25 2500 DirtySandstone 4145.73 5.41 0.62 2576.16 1662780.4 0.26 1500 Siltstone 4151.15 1.77 0.63 2607.49 1963674.5 0.26 2500 DirtySandstone 4152.92 3.71 0.62 2584.28 1742901.7 0.26 1500 Siltstone 4156.63 5.41 0.63 2620.4 1681056.2 0.26 2500 Siltstone 4162.04 1.81 0.62 2589.36 1561073 0.26 1500 DirtySandstone 4163.85 1.8 0.62 2573.84 1262913.1 0.26 2500 Siltstone 4165.65 3.58 0.63 2633.89 1816969.7 0.26 1500 Shale 4169.23 11.02 0.65 2696.83 2238744.4 0.25 2500 CleanSandstone 4180.25 1.97 0.61 2538.02 1001510.6 0.26 600 Siltstone 4182.22 4 0.62 2594.29 1571504.2 0.26 1500 CleanSandstone 4186.22 2 0.6 2533.23 1267177.7 0.26 600 Shale 4188.22 2.01 0.66 2752.38 2789765.8 0.25 2500 Siltstone 4190.26 2 0.62 2586.02 1409418.9 0.26 1500 NDBI-034 Stage N/A Page 58 of 97 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 4192.22 2.1 0.66 2754.99 2789765.8 0.25 2500 DirtySandstone 4194.32 4 0.61 2559.77 1435306.6 0.26 1500 Siltstone 4198.33 4 0.62 2612.56 1765617.4 0.26 2500 DirtySandstone 4202.33 4 0.61 2581.38 1435651.3 0.26 1500 CleanSandstone 4206.33 2.1 0.59 2486.53 935658.3 0.26 2500 Siltstone 4208.43 4.01 0.62 2618.8 1491142.7 0.26 1500 Shale 4212.43 2 0.66 2768.19 2789765.8 0.25 2500 DirtySandstone 4214.44 10.99 0.62 2603.72 1462838 0.26 1500 Shale 4225.43 27 0.65 2763.84 2560999.9 0.25 2500 Siltstone 4252.43 2 0.63 2696.69 1857874.8 0.26 1500 Shale 4254.43 10.01 0.66 2794.3 2552268.6 0.25 2500 Siltstone 4264.44 2 0.63 2674.35 1509543.6 0.26 1500 Shale 4266.44 4.1 0.64 2731.93 2349461.1 0.25 2500 Siltstone 4270.54 2 0.64 2716.56 1482677.8 0.25 1500 Shale 4272.54 96.39 0.65 2821.42 2604074 0.25 2500 DirtySandstone 4368.93 2 0.61 2665.65 1153391 0.26 1500 NDBI-034 Stage N/A Page 59 of 97 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 4370.93 38.19 0.65 2875.37 2733692 0.25 2500 Siltstone 4409.12 2 0.62 2738.75 1526263.4 0.26 1500 Shale 4411.12 46.23 0.65 2904.38 2704369.9 0.25 2500 Siltstone 4457.35 1.97 0.64 2831.14 1825853.3 0.25 1500 Shale 4459.32 9.84 0.65 2915.11 2657615 0.25 2500 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 18900 450 11.25 2 1 PPA 40 YF126ST 6636.5 165 CarboLite 16/20 1 6636.5 4.12 3 2 PPA 40 YF126ST 6945.6 180 CarboLite 16/20 2 13891.2 4.5 4 3 PPA 40 YF126ST 7230.8 195 CarboLite 16/20 3 21692.4 4.87 5 4 PPA 40 YF126ST 6959.1 195 CarboLite 16/20 4 27836.4 4.87 6 5 PPA 40 YF126ST 6707 195 CarboLite 16/20 5 33535 4.87 7 6 PPA 40 YF126ST 6472.8 195 CarboLite 16/20 6 38836.8 4.88 NDBI-034 Stage N/A Page 60 of 97 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) 8 7 PPA 40 YF126ST 5933.4 185 CarboLite 16/20 7 41533.8 4.62 9 8 PPA 40 YF126ST 5274.3 170 CarboLite 16/20 8 42194.4 4.25 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.6 23.32 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71059.5 226156.5 1929.98 48.25 NDBI-034 Stage N/A Page 61 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Bottomhole Pressure (psi) Max Height (ft) Stage 10 3611.6 230.56 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4062.26 4292.82 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 10 3.28 628.88 184.18 0.47 NDBI-034 Stage N/A Page 62 of 97 Stage 11 Zoneset name: Stage 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 4061.35 10.01 0.73 2975.3 1461000.3 0.22 2500 Shale 4071.36 14.99 0.69 2834.76 1762000.5 0.22 2500 Nanushuk 3 SS 4086.35 15.32 0.68 2775.88 1898000.5 0.22 2000 Top Nan 4101.67 6 0.65 2664.2 838900.2 0.27 1000 Shale 4107.68 2.01 0.7 2895.1 2665000.7 0.23 2500 Nan DS 4109.68 1.47 0.64 2617.5 819400.2 0.27 1500 Nan DS 4111.15 2 0.64 2648.82 1222000.3 0.26 1500 Nan CS 4113.16 13.03 0.63 2595.16 869100.2 0.27 1000 Nan CS 4126.18 1.47 0.61 2529.75 1002000.3 0.27 1000 Nan CS 4127.66 4.01 0.65 2663.91 706600.2 0.28 1000 Nan CS 4131.66 8.99 0.61 2510.6 1166000.3 0.27 1000 Nan CS 4140.65 7.02 0.65 2693.21 769000.2 0.27 1000 NDBI-034 Stage N/A Page 63 of 97 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 4147.67 5.48 0.62 2575.58 1278000.4 0.26 1000 Nan CS 4153.15 13.02 0.65 2699.01 691700.2 0.28 1000 Nan DS 4166.17 2.49 0.68 2852.89 1748000.4 0.26 1500 Nan DS 4168.67 12.5 0.64 2655.21 1111000.3 0.27 1500 Nan DS 4181.17 4.01 0.7 2927.73 1692000.4 0.26 1500 Nan DS 4185.17 2.49 0.65 2709.01 822100.2 0.27 1500 Shale 4187.66 2 0.7 2919.46 2665000.7 0.23 2500 Nan DS 4189.67 4 0.65 2716.12 1159000.3 0.27 1500 Nan DS 4193.67 4.01 0.63 2630.69 838300.2 0.27 1000 Shale 4197.67 4 0.7 2958.19 2665000.7 0.23 2500 Nan DS 4201.67 6 0.65 2715.83 1133000.3 0.27 1500 Shale 4207.68 2.01 0.7 2933.39 2665000.7 0.23 2500 Nan DS 4209.68 2 0.63 2647.08 1078000.3 0.27 1500 Nan DS 4211.68 6.49 0.67 2816.05 1694000.4 0.26 1500 Nan DS 4218.18 4.01 0.62 2608.5 898500.2 0.27 1500 Nan DS 4222.18 3.47 0.65 2745.13 929100.3 0.27 1500 NDBI-034 Stage N/A Page 64 of 97 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 4225.66 2 0.7 2945.86 2665000.7 0.23 2500 Nan DS 4227.66 12.5 0.65 2731.93 1562000.4 0.26 1500 Nan DS 4240.16 2.01 0.66 2781.53 1397000.4 0.26 1500 Shale 4242.16 2 0.7 2957.46 2665000.7 0.23 2500 Nan DS 4244.16 2 0.65 2763.55 1242000.3 0.26 1500 Shale 4246.16 8 0.69 2928.31 2665000.7 0.23 2500 Nan DS 4254.17 2 0.64 2723.81 932500.2 0.27 1500 Shale 4256.17 4.01 0.7 2967.91 2665000.7 0.23 2500 Nan DS 4260.17 6 0.65 2753.83 1427000.4 0.26 1500 Shale 4266.17 8.01 0.7 2976.32 2665000.7 0.23 2500 Nan DS 4274.18 6.49 0.65 2800.53 1469000.4 0.26 1500 Shale 4280.68 6.01 0.69 2951.52 2665000.7 0.23 2500 Nan DS 4286.68 2 0.64 2759.92 838400.2 0.27 1000 Shale 4288.68 1.97 0.7 2989.95 2665000.7 0.23 2500 Nan DS 4290.65 4 0.65 2790.24 1469000.4 0.26 1500 Shale 4294.65 2 0.7 2994.01 2665000.7 0.23 2500 NDBI-034 Stage N/A Page 65 of 97 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 4296.65 6 0.67 2884.22 1545000.4 0.26 1500 Shale 4302.66 12.01 0.7 3003.15 2665000.7 0.23 2500 Nan DS 4314.67 2.5 0.65 2787.92 1214000.3 0.27 1500 Shale 4317.16 20.01 0.69 2981.4 2665000.7 0.23 2500 NDBI-034 Stage N/A Page 66 of 97 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 19950 475 11.88 2 1 PPA 40 YF126ST 6837.6 170 CarboLite 16/20 1 6837.6 4.25 3 2 PPA 40 YF126ST 7717.4 200 CarboLite 16/20 2 15434.8 5 4 3 PPA 40 YF126ST 8157.8 220 CarboLite 16/20 3 24473.4 5.5 5 4 PPA 40 YF126ST 7851.2 220 CarboLite 16/20 4 31404.8 5.5 6 5 PPA 40 YF126ST 7566.9 220 CarboLite 16/20 5 37834.5 5.5 7 6 PPA 40 YF126ST 7302.6 220 CarboLite 16/20 6 43815.6 5.5 8 7 PPA 40 YF126ST 6093.9 190 CarboLite 16/20 7 42657.3 4.75 9 8 PPA 40 YF126ST 5274.3 170 CarboLite 16/20 8 42194.4 4.25 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 25.99 22.78 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 76751.7 244652.4 2084.98 52.12 NDBI-034 Stage N/A Page 67 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 11 5971.5 240.91 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4066.44 4307.35 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 11 1.39 1012.59 184.6 0.39 NDBI-034 Stage N/A Page 68 of 97 Stage 12 Zoneset name: Stage 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 4062.37 10.01 0.73 2976.17 1461000.3 0.22 2500 Shale 4072.38 14.99 0.69 2835.49 1762000.5 0.22 2500 Nanushuk 3 SS 4087.37 15.32 0.68 2776.46 1898000.5 0.22 2000 Top Nan 4102.69 6 0.65 2664.78 838900.2 0.27 1000 Shale 4108.69 2.01 0.7 2895.82 2665000.7 0.23 2500 Nan DS 4110.7 1.47 0.64 2618.22 819400.2 0.27 1500 Nan DS 4112.17 2 0.64 2649.55 1222000.3 0.26 1500 Nan CS 4114.17 13.03 0.63 2595.89 869100.2 0.27 1000 Nan CS 4127.2 1.47 0.61 2530.47 1002000.3 0.27 1000 Nan CS 4128.67 4.01 0.65 2664.63 706600.2 0.28 1000 Nan CS 4132.68 8.99 0.61 2511.18 1166000.3 0.27 1000 Nan CS 4141.67 7.02 0.65 2693.79 769000.2 0.27 1000 NDBI-034 Stage N/A Page 69 of 97 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 4148.69 5.48 0.62 2576.31 1278000.4 0.26 1000 Nan CS 4154.17 13.02 0.65 2699.73 691700.2 0.28 1000 Nan DS 4167.19 2.49 0.68 2853.62 1748000.4 0.26 1500 Nan DS 4169.69 12.5 0.64 2655.93 1111000.3 0.27 1500 Nan DS 4182.19 4.01 0.7 2928.46 1692000.4 0.26 1500 Nan DS 4186.19 2.49 0.65 2709.74 822100.2 0.27 1500 Shale 4188.68 2 0.7 2920.19 2665000.7 0.23 2500 Nan DS 4190.68 4 0.65 2716.85 1159000.3 0.27 1500 Nan DS 4194.69 4.01 0.63 2631.27 838300.2 0.27 1000 Shale 4198.69 4 0.7 2958.91 2665000.7 0.23 2500 Nan DS 4202.69 6 0.65 2716.56 1133000.3 0.27 1500 Shale 4208.69 2.01 0.7 2934.11 2665000.7 0.23 2500 Nan DS 4210.7 2 0.63 2647.66 1078000.3 0.27 1500 Nan DS 4212.7 6.49 0.67 2816.78 1694000.4 0.26 1500 Nan DS 4219.19 4.01 0.62 2609.08 898500.2 0.27 1500 Nan DS 4223.2 3.47 0.65 2745.85 929100.3 0.27 1500 NDBI-034 Stage N/A Page 70 of 97 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 4226.67 2 0.7 2946.59 2665000.7 0.23 2500 Nan DS 4228.67 12.5 0.65 2732.51 1562000.4 0.26 1500 Nan DS 4241.17 2.01 0.66 2782.11 1397000.4 0.26 1500 Shale 4243.18 2 0.7 2958.19 2665000.7 0.23 2500 Nan DS 4245.18 2 0.65 2764.27 1242000.3 0.26 1500 Shale 4247.18 8 0.69 2929.04 2665000.7 0.23 2500 Nan DS 4255.18 2 0.64 2724.39 932500.2 0.27 1500 Shale 4257.19 4.01 0.7 2968.63 2665000.7 0.23 2500 Nan DS 4261.19 6 0.65 2754.56 1427000.4 0.26 1500 Shale 4267.19 8.01 0.7 2977.04 2665000.7 0.23 2500 Nan DS 4275.2 6.49 0.65 2801.11 1469000.4 0.26 1500 Shale 4281.69 6.01 0.69 2952.1 2665000.7 0.23 2500 Nan DS 4287.7 2 0.64 2760.5 838400.2 0.27 1000 Shale 4289.7 1.97 0.7 2990.68 2665000.7 0.23 2500 Nan DS 4291.67 4 0.65 2790.96 1469000.4 0.26 1500 Shale 4295.67 2 0.7 2994.74 2665000.7 0.23 2500 NDBI-034 Stage N/A Page 71 of 97 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 4297.67 6 0.67 2884.95 1545000.4 0.26 1500 Shale 4303.67 12.01 0.7 3003.88 2665000.7 0.23 2500 Nan DS 4315.68 2.5 0.65 2788.64 1214000.3 0.27 1500 Shale 4318.18 20.01 0.69 2982.12 2665000.7 0.23 2500 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 17850 425 CarboLite 16/20 0 0 10.62 2 1 PPA 40 YF126ST 8044.2 200 CarboLite 16/20 1 8044.2 5 3 2 PPA 40 YF126ST 8682.2 225 CarboLite 16/20 2 17364.4 5.62 4 4 PPA 40 YF126ST 9814.1 275 CarboLite 16/20 4 39256.4 6.87 5 6 PPA 40 YF126ST 8630.4 260 CarboLite 16/20 6 51782.4 6.5 6 8 PPA 40 YF126ST 7446 240 CarboLite 16/20 8 59568 6 7 10 PPA 40 YF126ST 5824.7 200 CarboLite 16/20 10 58247 5 NDBI-034 Stage N/A Page 72 of 97 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.93 23.29 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 66291.6 234262.4 1825 45.62 NDBI-034 Stage N/A Page 73 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 12 6268.9 256 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4062.43 4318.43 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 12 1.64 937.77 217.17 0.42 NDBI-034 Stage N/A Page 74 of 97 Stage 13 Zoneset name: Stage 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 4062.76 10.01 0.73 2976.32 1461000.3 0.22 2500 Shale 4072.77 14.99 0.69 2835.78 1762000.5 0.22 2500 Nanushuk 3 SS 4087.76 15.32 0.68 2776.75 1898000.5 0.22 2000 Top Nan 4103.08 6 0.65 2665.07 838900.2 0.27 1000 Shale 4109.09 2.01 0.7 2895.97 2665000.7 0.23 2500 Nan DS 4111.09 1.47 0.64 2618.37 819400.2 0.27 1500 Nan DS 4112.57 2 0.64 2649.84 1222000.3 0.26 1500 Nan CS 4114.57 13.03 0.63 2596.03 869100.2 0.27 1000 Nan CS 4127.59 1.47 0.61 2530.62 1002000.3 0.27 1000 Nan CS 4129.07 4.01 0.65 2664.92 706600.2 0.28 1000 Nan CS 4133.07 8.99 0.61 2511.47 1166000.3 0.27 1000 Nan CS 4142.06 7.02 0.65 2694.08 769000.2 0.27 1000 NDBI-034 Stage N/A Page 75 of 97 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 4149.08 5.48 0.62 2576.6 1278000.4 0.26 1000 Nan CS 4154.56 13.02 0.65 2700.02 691700.2 0.28 1000 Nan DS 4167.59 2.49 0.68 2853.91 1748000.4 0.26 1500 Nan DS 4170.08 12.5 0.64 2656.08 1111000.3 0.27 1500 Nan DS 4182.58 4.01 0.7 2928.75 1692000.4 0.26 1500 Nan DS 4186.58 2.49 0.65 2710.03 822100.2 0.27 1500 Shale 4189.07 2 0.7 2920.48 2665000.7 0.23 2500 Nan DS 4191.08 4 0.65 2717.14 1159000.3 0.27 1500 Nan DS 4195.08 4.01 0.63 2631.56 838300.2 0.27 1000 Shale 4199.08 4 0.7 2959.06 2665000.7 0.23 2500 Nan DS 4203.08 6 0.65 2716.85 1133000.3 0.27 1500 Shale 4209.09 2.01 0.7 2934.4 2665000.7 0.23 2500 Nan DS 4211.09 2 0.63 2647.95 1078000.3 0.27 1500 Nan DS 4213.09 6.49 0.67 2817.07 1694000.4 0.26 1500 Nan DS 4219.59 4.01 0.62 2609.37 898500.2 0.27 1500 Nan DS 4223.59 3.47 0.65 2746.14 929100.3 0.27 1500 NDBI-034 Stage N/A Page 76 of 97 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 4227.07 2 0.7 2946.88 2665000.7 0.23 2500 Nan DS 4229.07 12.5 0.65 2732.8 1562000.4 0.26 1500 Nan DS 4241.57 2.01 0.66 2782.4 1397000.4 0.26 1500 Shale 4243.57 2 0.7 2958.48 2665000.7 0.23 2500 Nan DS 4245.57 2 0.65 2764.56 1242000.3 0.26 1500 Shale 4247.57 8 0.69 2929.18 2665000.7 0.23 2500 Nan DS 4255.58 2 0.64 2724.68 932500.2 0.27 1500 Shale 4257.58 4.01 0.7 2968.92 2665000.7 0.23 2500 Nan DS 4261.58 6 0.65 2754.85 1427000.4 0.26 1500 Shale 4267.59 8.01 0.7 2977.33 2665000.7 0.23 2500 Nan DS 4275.59 6.49 0.65 2801.4 1469000.4 0.26 1500 Shale 4282.09 6.01 0.69 2952.39 2665000.7 0.23 2500 Nan DS 4288.09 2 0.64 2760.79 838400.2 0.27 1000 Shale 4290.09 1.97 0.7 2990.97 2665000.7 0.23 2500 Nan DS 4292.06 4 0.65 2791.25 1469000.4 0.26 1500 Shale 4296.06 2 0.7 2995.03 2665000.7 0.23 2500 NDBI-034 Stage N/A Page 77 of 97 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 4298.06 6 0.67 2885.24 1545000.4 0.26 1500 Shale 4304.07 12.01 0.7 3004.17 2665000.7 0.23 2500 Nan DS 4316.08 2.5 0.65 2788.93 1214000.3 0.27 1500 Shale 4318.57 20.01 0.69 2982.27 2665000.7 0.23 2500 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 17850 425 CarboLite 16/20 0 0 10.62 2 1 PPA 40 YF126ST 8044.2 200 CarboLite 16/20 1 8044.2 5 3 2 PPA 40 YF126ST 8682.2 225 CarboLite 16/20 2 17364.4 5.62 4 4 PPA 40 YF126ST 9814.1 275 CarboLite 16/20 4 39256.4 6.87 5 6 PPA 40 YF126ST 8630.4 260 CarboLite 16/20 6 51782.4 6.5 6 8 PPA 40 YF126ST 7446 240 CarboLite 16/20 8 59568 6 7 10 PPA 40 YF126ST 5824.7 200 CarboLite 16/20 10 58247 5 NDBI-034 Stage N/A Page 78 of 97 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.93 23.29 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 66291.6 234262.4 1825 45.62 NDBI-034 Stage N/A Page 79 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 13 6096.1 240.22 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4067.79 4308.01 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 13 1.58 1005.16 183.49 0.44 NDBI-034 Stage N/A Page 80 of 97 Stage 14 Zoneset name: Stage 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 4062.76 10.01 0.73 2976.32 1461000.3 0.22 2500 Shale 4072.77 14.99 0.69 2835.78 1762000.5 0.22 2500 Nanushuk 3 SS 4087.76 15.32 0.68 2776.75 1898000.5 0.22 2000 Top Nan 4103.08 6 0.65 2665.07 838900.2 0.27 1000 Shale 4109.09 2.01 0.7 2895.97 2665000.7 0.23 2500 Nan DS 4111.09 1.47 0.64 2618.37 819400.2 0.27 1500 Nan DS 4112.57 2 0.64 2649.84 1222000.3 0.26 1500 Nan CS 4114.57 13.03 0.63 2596.03 869100.2 0.27 1000 Nan CS 4127.59 1.47 0.61 2530.62 1002000.3 0.27 1000 Nan CS 4129.07 4.01 0.65 2664.92 706600.2 0.28 1000 Nan CS 4133.07 8.99 0.61 2511.47 1166000.3 0.27 1000 Nan CS 4142.06 7.02 0.65 2694.08 769000.2 0.27 1000 NDBI-034 Stage N/A Page 81 of 97 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 4149.08 5.48 0.62 2576.6 1278000.4 0.26 1000 Nan CS 4154.56 13.02 0.65 2700.02 691700.2 0.28 1000 Nan DS 4167.59 2.49 0.68 2853.91 1748000.4 0.26 1500 Nan DS 4170.08 12.5 0.64 2656.08 1111000.3 0.27 1500 Nan DS 4182.58 4.01 0.7 2928.75 1692000.4 0.26 1500 Nan DS 4186.58 2.49 0.65 2710.03 822100.2 0.27 1500 Shale 4189.07 2 0.7 2920.48 2665000.7 0.23 2500 Nan DS 4191.08 4 0.65 2717.14 1159000.3 0.27 1500 Nan DS 4195.08 4.01 0.63 2631.56 838300.2 0.27 1000 Shale 4199.08 4 0.7 2959.06 2665000.7 0.23 2500 Nan DS 4203.08 6 0.65 2716.85 1133000.3 0.27 1500 Shale 4209.09 2.01 0.7 2934.4 2665000.7 0.23 2500 Nan DS 4211.09 2 0.63 2647.95 1078000.3 0.27 1500 Nan DS 4213.09 6.49 0.67 2817.07 1694000.4 0.26 1500 Nan DS 4219.59 4.01 0.62 2609.37 898500.2 0.27 1500 Nan DS 4223.59 3.47 0.65 2746.14 929100.3 0.27 1500 NDBI-034 Stage N/A Page 82 of 97 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 4227.07 2 0.7 2946.88 2665000.7 0.23 2500 Nan DS 4229.07 12.5 0.65 2732.8 1562000.4 0.26 1500 Nan DS 4241.57 2.01 0.66 2782.4 1397000.4 0.26 1500 Shale 4243.57 2 0.7 2958.48 2665000.7 0.23 2500 Nan DS 4245.57 2 0.65 2764.56 1242000.3 0.26 1500 Shale 4247.57 8 0.69 2929.18 2665000.7 0.23 2500 Nan DS 4255.58 2 0.64 2724.68 932500.2 0.27 1500 Shale 4257.58 4.01 0.7 2968.92 2665000.7 0.23 2500 Nan DS 4261.58 6 0.65 2754.85 1427000.4 0.26 1500 Shale 4267.59 8.01 0.7 2977.33 2665000.7 0.23 2500 Nan DS 4275.59 6.49 0.65 2801.4 1469000.4 0.26 1500 Shale 4282.09 6.01 0.69 2952.39 2665000.7 0.23 2500 Nan DS 4288.09 2 0.64 2760.79 838400.2 0.27 1000 Shale 4290.09 1.97 0.7 2990.97 2665000.7 0.23 2500 Nan DS 4292.06 4 0.65 2791.25 1469000.4 0.26 1500 Shale 4296.06 2 0.7 2995.03 2665000.7 0.23 2500 NDBI-034 Stage N/A Page 83 of 97 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 4298.06 6 0.67 2885.24 1545000.4 0.26 1500 Shale 4304.07 12.01 0.7 3004.17 2665000.7 0.23 2500 Nan DS 4316.08 2.5 0.65 2788.93 1214000.3 0.27 1500 Shale 4318.57 20.01 0.69 2982.27 2665000.7 0.23 2500 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 16170 385 CarboLite 16/20 0 0 9.62 2 1 PPA 40 YF126ST 7642 190 CarboLite 16/20 1 7642 4.75 3 3 PPA 40 YF126ST 7972.4 215 CarboLite 16/20 3 23917.2 5.37 4 5 PPA 40 YF126ST 8255 240 CarboLite 16/20 5 41275 6 5 7 PPA 40 YF126ST 7697.4 240 CarboLite 16/20 7 53881.8 6 6 9 PPA 40 YF126ST 6609.8 220 CarboLite 16/20 9 59488.2 5.5 7 10 PPA 40 YF126ST 5533.3 190 CarboLite 16/20 10 55333 4.75 NDBI-034 Stage N/A Page 84 of 97 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27 22.92 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 59879.9 241537.2 1680 42 NDBI-034 Stage N/A Page 85 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 14 5981.2 234.52 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4066.56 4301.08 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 14 1.57 973.84 180.12 0.42 NDBI-034 Stage N/A Page 86 of 97 Stage 15 Zoneset name: Stage 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 4063.16 10.01 0.73 2976.61 1461000.3 0.22 2500 Shale 4073.16 14.99 0.69 2836.07 1762000.5 0.22 2500 Nanushuk 3 SS 4088.16 15.32 0.68 2777.04 1898000.5 0.22 2000 Top Nan 4103.48 6 0.65 2665.36 838900.2 0.27 1000 Shale 4109.48 2.01 0.7 2896.26 2665000.7 0.23 2500 Nan DS 4111.48 1.47 0.64 2618.66 819400.2 0.27 1500 Nan DS 4112.96 2 0.64 2649.98 1222000.3 0.26 1500 Nan CS 4114.96 13.03 0.63 2596.32 869100.2 0.27 1000 Nan CS 4127.99 1.47 0.61 2530.91 1002000.3 0.27 1000 Nan CS 4129.46 4.01 0.65 2665.07 706600.2 0.28 1000 Nan CS 4133.46 8.99 0.61 2511.62 1166000.3 0.27 1000 Nan CS 4142.45 7.02 0.65 2694.37 769000.2 0.27 1000 NDBI-034 Stage N/A Page 87 of 97 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 4149.48 5.48 0.62 2576.74 1278000.4 0.26 1000 Nan CS 4154.95 13.02 0.65 2700.31 691700.2 0.28 1000 Nan DS 4167.98 2.49 0.68 2854.2 1748000.4 0.26 1500 Nan DS 4170.47 12.5 0.64 2656.37 1111000.3 0.27 1500 Nan DS 4182.97 4.01 0.7 2929.04 1692000.4 0.26 1500 Nan DS 4186.98 2.49 0.65 2710.18 822100.2 0.27 1500 Shale 4189.47 2 0.7 2920.77 2665000.7 0.23 2500 Nan DS 4191.47 4 0.65 2717.28 1159000.3 0.27 1500 Nan DS 4195.47 4.01 0.63 2631.85 838300.2 0.27 1000 Shale 4199.48 4 0.7 2959.35 2665000.7 0.23 2500 Nan DS 4203.48 6 0.65 2716.99 1133000.3 0.27 1500 Shale 4209.48 2.01 0.7 2934.69 2665000.7 0.23 2500 Nan DS 4211.48 2 0.63 2648.24 1078000.3 0.27 1500 Nan DS 4213.48 6.49 0.67 2817.21 1694000.4 0.26 1500 Nan DS 4219.98 4.01 0.62 2609.52 898500.2 0.27 1500 Nan DS 4223.98 3.47 0.65 2746.29 929100.3 0.27 1500 NDBI-034 Stage N/A Page 88 of 97 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 4227.46 2 0.7 2947.17 2665000.7 0.23 2500 Nan DS 4229.46 12.5 0.65 2733.09 1562000.4 0.26 1500 Nan DS 4241.96 2.01 0.66 2782.69 1397000.4 0.26 1500 Shale 4243.96 2 0.7 2958.77 2665000.7 0.23 2500 Nan DS 4245.96 2 0.65 2764.71 1242000.3 0.26 1500 Shale 4247.97 8 0.69 2929.47 2665000.7 0.23 2500 Nan DS 4255.97 2 0.64 2724.97 932500.2 0.27 1500 Shale 4257.97 4.01 0.7 2969.21 2665000.7 0.23 2500 Nan DS 4261.98 6 0.65 2754.99 1427000.4 0.26 1500 Shale 4267.98 8.01 0.7 2977.62 2665000.7 0.23 2500 Nan DS 4275.98 6.49 0.65 2801.69 1469000.4 0.26 1500 Shale 4282.48 6.01 0.69 2952.68 2665000.7 0.23 2500 Nan DS 4288.48 2 0.64 2761.08 838400.2 0.27 1000 Shale 4290.49 1.97 0.7 2991.26 2665000.7 0.23 2500 Nan DS 4292.45 4 0.65 2791.4 1469000.4 0.26 1500 Shale 4296.46 2 0.7 2995.32 2665000.7 0.23 2500 NDBI-034 Stage N/A Page 89 of 97 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 4298.46 6 0.67 2885.53 1545000.4 0.26 1500 Shale 4304.46 12.01 0.7 3004.46 2665000.7 0.23 2500 Nan DS 4316.47 2.5 0.65 2789.08 1214000.3 0.27 1500 Shale 4318.96 20.01 0.69 2982.56 2665000.7 0.23 2500 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 16170 385 CarboLite 16/20 0 0 9.62 2 1 PPA 40 YF126ST 7642 190 CarboLite 16/20 1 7642 4.75 3 3 PPA 40 YF126ST 7972.4 215 CarboLite 16/20 3 23917.2 5.37 4 5 PPA 40 YF126ST 8255 240 CarboLite 16/20 5 41275 6 5 7 PPA 40 YF126ST 7697.4 240 CarboLite 16/20 7 53881.8 6 6 9 PPA 40 YF126ST 6609.8 220 CarboLite 16/20 9 59488.2 5.5 7 10 PPA 40 YF126ST 5533.3 190 CarboLite 16/20 10 55333 4.75 NDBI-034 Stage N/A Page 90 of 97 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27 22.92 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 59879.9 241537.2 1680 42 NDBI-034 Stage N/A Page 91 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max SurfacePressure (psi) Max Height (ft) Stage 15 5813.7 225.22 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4003 4228.22 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 15 1.74 928.49 174.72 0.44 NDBI-034 Stage N/A Page 92 of 97 Stage 16 Zoneset name: Stage 16 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 4056.76 10.01 0.73 2972 1461000.3 0.22 2500 Shale 4066.77 14.99 0.69 2831.6 1762000.5 0.22 2500 Nanushuk 3 SS 4081.76 15.32 0.68 2772.7 1898000.5 0.22 2000 Top Nan 4097.08 6 0.65 2661.2 838900.2 0.27 1000 Shale 4103.08 2.01 0.7 2891.8 2665000.7 0.23 2500 Nan DS 4105.09 1.47 0.64 2614.6 819400.2 0.27 1500 Nan DS 4106.56 2 0.64 2645.9 1222000.3 0.26 1500 Nan CS 4108.56 13.03 0.63 2592.3 869100.2 0.27 1000 Nan CS 4121.59 1.47 0.61 2527 1002000.3 0.27 1000 Nan CS 4123.06 4.01 0.65 2661 706600.2 0.28 1000 Nan CS 4127.07 8.99 0.61 2507.8 1166000.3 0.27 1000 Nan CS 4136.06 7.02 0.65 2690.2 769000.2 0.27 1000 NDBI-034 Stage N/A Page 93 of 97 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 4143.08 5.48 0.62 2572.8 1278000.4 0.26 1000 Nan CS 4148.56 13.02 0.65 2696.1 691700.2 0.28 1000 Nan DS 4161.58 2.49 0.68 2849.8 1748000.4 0.26 1500 Nan DS 4164.07 12.5 0.64 2652.3 1111000.3 0.27 1500 Nan DS 4176.57 4.01 0.7 2924.5 1692000.4 0.26 1500 Nan DS 4180.58 2.49 0.65 2706.1 822100.2 0.27 1500 Shale 4183.07 2 0.7 2916.3 2665000.7 0.23 2500 Nan DS 4185.07 4 0.65 2713.2 1159000.3 0.27 1500 Nan DS 4189.07 4.01 0.63 2627.8 838300.2 0.27 1000 Shale 4193.08 4 0.7 2954.9 2665000.7 0.23 2500 Nan DS 4197.08 6 0.65 2712.9 1133000.3 0.27 1500 Shale 4203.08 2.01 0.7 2930.2 2665000.7 0.23 2500 Nan DS 4205.09 2 0.63 2644.2 1078000.3 0.27 1500 Nan DS 4207.09 6.49 0.67 2813 1694000.4 0.26 1500 Nan DS 4213.58 4.01 0.62 2605.6 898500.2 0.27 1500 Nan DS 4217.59 3.47 0.65 2742.2 929100.3 0.27 1500 NDBI-034 Stage N/A Page 94 of 97 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 4221.06 2 0.7 2942.7 2665000.7 0.23 2500 Nan DS 4223.06 12.5 0.65 2728.9 1562000.4 0.26 1500 Nan DS 4235.56 2.01 0.66 2778.5 1397000.4 0.26 1500 Shale 4237.57 2 0.7 2954.3 2665000.7 0.23 2500 Nan DS 4239.57 2 0.65 2760.6 1242000.3 0.26 1500 Shale 4241.57 8 0.69 2925.1 2665000.7 0.23 2500 Nan DS 4249.57 2 0.64 2720.8 932500.2 0.27 1500 Shale 4251.57 4.01 0.7 2964.7 2665000.7 0.23 2500 Nan DS 4255.58 6 0.65 2750.9 1427000.4 0.26 1500 Shale 4261.58 8.01 0.7 2973.1 2665000.7 0.23 2500 Nan DS 4269.59 6.49 0.65 2797.5 1469000.4 0.26 1500 Shale 4276.08 6.01 0.69 2948.3 2665000.7 0.23 2500 Nan DS 4282.09 2 0.64 2756.9 838400.2 0.27 1000 Shale 4284.09 1.97 0.7 2986.8 2665000.7 0.23 2500 Nan DS 4286.06 4 0.65 2787.3 1469000.4 0.26 1500 Shale 4290.06 2 0.7 2990.8 2665000.7 0.23 2500 NDBI-034 Stage N/A Page 95 of 97 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 4292.06 6 0.67 2881.2 1545000.4 0.26 1500 Shale 4298.06 12.01 0.7 3000 2665000.7 0.23 2500 Nan DS 4310.07 2.5 0.65 2785 1214000.3 0.27 1500 Shale 4312.57 20.01 0.69 2978.2 2665000.7 0.23 2500 Name: Stage 16 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 16 PAD 40 YF126ST 16170 385 CarboLite 16/20 0 0 9.62 2 1 PPA 40 YF126ST 7642 190 CarboLite 16/20 1 7642 4.75 3 3 PPA 40 YF126ST 7972.4 215 CarboLite 16/20 3 23917.2 5.37 4 5 PPA 40 YF126ST 8255 240 CarboLite 16/20 5 41275 6 5 7 PPA 40 YF126ST 7697.4 240 CarboLite 16/20 7 53881.8 6 6 9 PPA 40 YF126ST 6609.8 220 CarboLite 16/20 9 59488.2 5.5 7 10 PPA 40 YF126ST 5533.3 190 CarboLite 16/20 10 55333 4.75 NDBI-034 Stage N/A Page 96 of 97 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27 22.92 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 59879.9 241537.2 1680 42 NDBI-034 Stage N/A Page 97 of 97 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Stage 16 5637.8 235.62 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4068.97 4304.59 Summary Table: Propped Fracture Results Case FCD Closed Fracture Parameters Perforation FCD Length (ft) Height (ft) Avg Wellbore Width (in) Stage 16 1.78 956.28 181.31 0.47 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-034 (PTD No. 225-108; Sundry No. 326-065) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 February 6, 2026 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. A.Dewhurst 29JAN26 (a)(2) Plat Provided with application. A.Dewhurst 29JAN26 (a)(2)(A) Well location Provided with application. A.Dewhurst 29JAN26 (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-034. There are no subsurface water rights or temporary subsurface water rights within 14 miles of the surface location of Pikka NDBi-034. A.Dewhurst 29JAN26 (a)(2)(C) Identify all well types within ½ mile Provided with application. A.Dewhurst 29JAN26 (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 29JAN26 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-034 (PTD No. 225-108; Sundry No. 326-065) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 February 6, 2026 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 29JAN26 (a)(5) Casing and cementing information Provided with application. As Built provided. CDW 01/28/2026 (a)(6) Casing and cementing operation assessment 13-3/8 surface casing cemented to surface with no losses reported and 100 bbl cement circulated at surface. 440 bbl lead, 69 bbl tail pumped. 9-5/8 CFLEX stage tool, 2 stage cement job, Liner top 2850 ft, shoe 11997 ft. Stage 1 pumped from shoe to est. 1000 ft (10997 ft). Minimal losses of 20 bbl after cement exited shoe. 2nd Stage at 6588 ft plan at 100% excess. Target liner top. Cemented with full returns, 46 bbl clean cement circulated off liner top back to surface. 7 liner top 11862 ft, TOC 14098 , shoe 16,669 ft. Top Nanushuk 15,918 ft MD. SLB Sonic CBL, 13814 ft top of partial cement, 14098 ft top of good cement. 122 bbl (30% excess) cement pumped, no losses during cement job. 4.5 production liner with packer set at 16502 ft (+/- 200 ft above 7 shoe in good cement) with TD 25,842 ft. Frac isolated by liner top packer and 2 open hole packer at approx.. 16711 and 16777 ft. Shallowest frac stage at 17008 ft. No variance requested. Based on TOC logging, shoe drill out and test, and 4.5 liner packers should isolate the frac to approved zone. Drlg Eng CDW 01/28/2026 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-034 (PTD No. 225-108; Sundry No. 326-065) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 February 6, 2026 (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 29JAN26 (a)(6)( B) Each hydrocarbon zone is isolated Yes. The Nanushuk is adequately isolated by the 7 intermediate-2 casing cement. TOC measured by CBL is 238 TVD above the top of the Nanushuk (at least 100 TVD required by variance granted for PTD 225-108). The Tuluvak is adequately isolated by the second stage of the 9-5/8 intermediate casing cement. A.Dewhurst 29JAN26/ 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 01/28/2026 (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 8100 and GORV 8500 psi., lines test 9200 psi. CDW 01/28/2026 (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 450 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). 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.Dewhurst 29JAN26 (a)(10) Location, orientation, report on mechanical condition of each well that It is unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids from this / 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-034 (PTD No. 225-108; Sundry No. 326-065) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 February 6, 2026 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 operation because of cement isolation and / or separation distance. There are 3 fully P&Ad exploratory wells within ½ mile of Pikka NDBi-034 that do not have cement isolation across the fracturing interval. Plugs in these wells do isolate freshwater and other significant HC zones. A.Dewhurst 29JAN26 CDW 01/28/2026 (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 not identified any faults within a ½-mile radius of Pikka NDBi-034. 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 29JAN26 (a)(12) Proposed program for fracturing operation Provided with application. CDW 01/28/2026 (a)(12)(A) Estimated volume Provided with application. 33.5K bbl total dirty vol. 3.61million lb total proppant CDW 01/28/2026 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 01/28/2026 (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 01/28/2026 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 01/28/2026 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure expected of 7373 psi. Max. 8800 psi allowable treating pressure. Max pressure is 8100 psi trips and 8500 GORV. With 3800 psi back pressure IA (IA popoff set 4100 psi), max tubing differential should be 5000 psi. CDW 01/28/2026 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-034 (PTD No. 225-108; Sundry No. 326-065) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 February 6, 2026 (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 506 according to the Operators computer simulation. Computer simulation indicates the maximum anticipated height of the induced fractures will be 295, so it is unlikely that induced fractures will penetrate into the overlying confining zone. Detailed depths are provided in the application. A.Dewhurst 29JAN26 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified. CDW 01/28/2026 (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 01/28/2026 (c) Fracturing string (c)(1) Packer >100 below TOC of production or intermediate casing 7 liner top 11862 ft, TOC 14098 , shoe 16,669 ft. Top Nanushuk 15,918 ft MD. SLB Sonic CBL, 13814 ft top of partial cement, 14098 ft top of good cement. 122 bbl (30% excess) cement pumped, no losses during cement job. 4.5 production liner with packer set at 16502 ft (+/- 200 ft above 7 shoe in good cement) with TD 25,842 ft. Frac isolated by liner top packer and 2 open hole packer at approx.. 16711 and 16777 ft. Shallowest frac stage at 17008 ft. No variance requested. Based on TOC logging, shoe drill out and test, and 4.5 liner packers, should isolate the frac to approved zone. CDW 01/28/2026 (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 01/28/2026 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device 9200 psi line pressure test, pump knock out 8100 psi with max. global kickout 8500 psi. MAWP 8800 psi. IA PRV set as 4100 psi. CDW 01/28/2026 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDBi-034 (PTD No. 225-108; Sundry No. 326-065) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 February 6, 2026 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 01/28/2026 (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 01/28/2026 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 01/28/2026 (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 29JAN26 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. A.Dewhurst 29JAN26 (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. 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, Garret (Garret) Subject:RE: NDBi-034 (PTD 225-108) 9-5/8" 2nd Stage Cement Slurry Change Date:Tuesday, December 2, 2025 1:21:00 PM Attachments:image002.png Garret, This change is approved. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Staudinger, Garret (Garret) <Garret.Staudinger@santos.com> Sent: Tuesday, December 2, 2025 1:20 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: NDBi-034 (PTD 225-108) 9-5/8" 2nd Stage Cement Slurry Change Hey Bryan, I wanted to give you a heads up on a minor change to the PTD for NDBi-034. For the 2nd stage cement job on the 9-5/8” liner (targeting Tuluvak isolation), we are planning to pump a 14.5ppg tail slurry rather than the 15.3ppg slurry listed in the permit. Existing permit states the following: Stage 2: 100% Open Hole Excess 15.3ppg Tail: 413 bbls, 2318cuft, 1869sks VersaCem Type I/II – 1.24 cuft/sk New change would be as follows: Stage 2: 100% Open Hole Excess 14.5ppg Tail: 413 bbls, 2318cuft, 1667sks VersaCem Type I/II – 1.39 cuft/sk The reason for the change is to minimize ECD and chance of losses. This density difference gives us a modelled ECD of 0.4ppg less at the end of displacement. We still get plenty of compressive strength with the new slurry, things just take a little longer to set up. However, compressive strength times are still not an issue for rig operations. Let me know if you have any questions or concerns. Thanks, Garret Garret Staudinger ERD Team Lead m: +1 (907) 440 6892 | e: garret.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 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 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 Staudinger Senior Drilling Engineer Oil Search Alaska, LLC 601 W 5th Avenue Anchorage, AK, 99501 Re: Pikka Field, Nanushuk Oil Pool, NDBi-034 Oil Search Alaska, LLC Permit to Drill Number: 225-108 Surface Location: 2355 FSL, 3168 FEL, Sec 4, T11N, R6E, UM Bottomhole Location: 3003 FSL, 4784 FEL, Sec 24, T12N, R5E, UM Dear Mr. Staudinger: 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 5th day of November 2025. 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 26,460' TVD: 4,034' 4a. Location of Well (Governmental Section): 7. Property Designation: ADL 392984, 391445 Surface: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 3003 FSL, 4784 FEL, Sec 24, T12N, R5E, UM 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 69.79' 15. Distance to Nearest Well Open Surface: x- 422,076 y- 5,972,741 Zone- 4 22.79' to Same Pool: 470' 16. Deviated wells: Kickoff depth: 347 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 105 degrees Downhole: Surface: 1,481' 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 3,050' Surface Surface 3,050' 2,396' 12-1/4" 9-5/8" 47#L-80 HYD 563 9,100' 2,900' 2,344' 12,000' 3,328' Tieback 9-5/8" 47#L-80 HYD 563 2,900' Surface Surface 2,900' 2,344' 8-1/2" x 9-7/8"7" 26#L-80 HYD 563 4,810' 11,850' 16,660' 4,083' 6-1/8" 4-1/2" 12.6#P-110S HYD 563 9,950' 16,510' 4,032' 26,460' 4,034' Tubing 4-1/2" 12.6#P-110S HYD 563 16,510' Surface Surface 16,510' 4,032' 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: Garret Staudinger Authorized Name: Garret Staudinger Contact Email: garret.staudinger@santos.com Authorized Title: ERD Team Lead Contact Phone: 1-907-440-6892 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 Top of Productive Horizon: 5263 FSL, 460 FEL, Sec 36, T12N, R5E, UM NDBi-034 Pikka/Nanushuk Oil Pool Uncemented See attachment 6 11/25/2025 500' Total Depth MD (ft): Total Depth TVD (ft): IS000361277U 1,895' Cement Quantity, c.f. or sacks Cement Volume STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 See attachment 6 LONS 19-003 601 W Fifth Avenue, Anchorage, AK 99501-6301 Oil Search Alaska, LLC 2355 FSL, 3168 FEL, Sec 4, T11N, R6E, UM 393020, 393019, 392991, 392970, 392968 4,391 18. Casing Program: Top - Setting Depth - BottomSpecifications (including stage data) Grouted to surface See attachment 6 See attachment 6 N/A Authorized Signature: Production Liner Intermediate Commission Use Only See cover letter for other requirements. 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): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): Conductor/Structural LengthCasing Size Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): MD ions 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 to Drill API Number:Permit Approval er:Date: See cover letter for other requirements. Commission Use Only Contact Name:Garret Staudinger ized Name: Garret Staudinger Contact Email: garret.staudinger@santos.com ized Title: ERD Team Lead Contact Phone: 1-907-440-6892 Date:ized Signature: hereby certify that the foregoing is true and the procedure approved herein will not be ed from without prior written approval. tachments: 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 ulic Fracture planned?Yes No Perforation Depth TVD (ft):ation Depth MD (ft): Liner pe of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas rator Name:5.Bond: Blanket Single Well 11.Well Name and Number: Bond No. ress:6.Proposed Depth:12.Field/Pool(s): MD: 26,460'TVD: 4,034' ocation of Well (Governmental Section):7.Property Designation: ADL 392984, 391445 e: 8.DNR Approval Number:13.Approximate Spud Date: Depth: 3003 FSL, 4784 FEL, Sec 24, T12N, R5E,UM 9. Acres in Property:14. Distance to Nearest Property: cation of Well (State Base Plane Coordinates - NAD 27): 10.KB Elevation above MSL (ft):69.79' 15.Distance to Nearest Well Open e: x- 422,076 y- 5,972,741 Zone-4 22.79' to Same Pool:470' viated wells:Kickoff depth: 347 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 105 degrees Downhole:Surface: 1,481' e Casing Weight Grade Coupling Length MD TVD MD TVD " 20'x34" 215#X-52 Welded 80' Surface Surface 128' 128' "13-3/8" 68#L-80 TXP BTC 3,050' Surface Surface 3,050' 2,396' /4" 9-5/8" 47#L-80 HYD 563 9,100' 2,900' 2,344' 12,000' 3,328' ack 9-5/8" 47#L-80 HYD 563 2,900' Surface Surface 2,900' 2,344' 9-7/8"7" 26#L-80 HYD 563 4,810' 11,850' 16,660'4,083' /8" 4-1/2" 12.6#P-110S HYD 563 9,950' 16,510' 4,032' 26,460' 4,034' ng 4-1/2" 12.6#P-110S HYD 563 16,510' Surface Surface 16,510' 4,032' PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Productive Horizon: 5263 FSL, 460 FEL, Sec 36, T12N, R5E, UM NDBi-034 Pikka/Nanushuk Oil Pool Uncemented See attachment 6 11/25/2025 500' l Depth MD (ft): Total Depth TVD (ft): IS000361277U 1,895' Cement Quantity, c.f. or sacks Cement Volume See attachment 6 LONS 19-003 Fifth Avenue, Anchorage, AK 99501-6301 arch Alaska, LLC 393020, 393019, 392991,392970, 3929682355 FSL, 3168 FEL, Sec 4, T11N, R6E, UM 4,391 sing Program:Top - Setting Depth - BottomSpecifications (including stage data) Grouted to surface See attachment 6 See attachment 6 N/A Production ntermediate Surface GL / BF Elevation above MSL (ft): ductor/Structural LengthCasing Size Plugs (measured):Effect. Depth MD (ft):Effect. Depth TVD (ft): MD Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) m Lead 225-108 By Grace Christianson at 7:33 am, Oct 10, 2025 TS 10/27/25 See attached conditions of approval 50-103-20927-00-00 Note, this is the first Pikka PTD where drilling with mud weight insufficient to overbalance formation with MPD used to maintain overbalance has been requested. DSR-10/15/25BJM 11/4/25 11/05/25 11/05/25 NDBi-034 (PTD 225-108) Approval 1. Diverter variance 250 - 2. . All a 3. - -25- 4. 5. . Cement 9-. . - : a. - - - 8. -~ 9. 2 10. - are met: a. a - - c. d. 11. - a. c. d. e. - : i. A ii. iii. - Page 1 of 1 09 October 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 NDBi-034 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-034 is planned to be a horizontal injector targeting the Nanushuk 3. The approximate spud date is anticipated to be November 25 th, 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 #1 will be drilled into the Seabee formation at an inclination of ~84 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 after the 7 liner is set. The 8-1/2 x 9-7/8 Intermediate Hole #2 will be drilled through the Seabee and Nanushuk formations with the casing set in the Nanushuk 3 formation at ~73 degrees. A 7 liner will be set and cemented from TD to cover the Nanushuk formation. The 6-1/8 Production Hole will be geo-steered and landed 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 production liner will be tied back to surface with a 4-1/2 tubing upper completion string. Managed Pressure Drilling (MPD) will be implemented in the Intermediate #2 and Production Hole intervals. 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) 440-6892 or garret.staudinger@santos.com. Respectfully, Garret Staudinger ERD Team Lead Oil Search (Alaska), LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Respectfully, Application for Permit to Drill NDBi-034 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..........................................................................................................7 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................................................12 15. Proposed Variance Request........................................................................................................12 Attachments..................................................................................................................................................17 Attachment 1: Location Maps..........................................................................................................18 Attachment 2: Directional Plan........................................................................................................19 Attachment 3: BOPE Equipment ......................................................................................................20 Attachment 4: Drilling Hazards.........................................................................................................21 Attachment 5A: Leak Off Test Procedure (Conventional)................................................................23 Attachment 5B: Leak Off Test Procedure (With MPD).....................................................................24 Attachment 6: Cement Summary.....................................................................................................25 Attachment 7: Prognosed Formation Tops......................................................................................29 Attachment 8: Well Schematic.........................................................................................................30 Attachment 9: Formation Evaluation Program................................................................................31 Attachment 10: Wellhead & Tree Diagram......................................................................................32 Attachment 11: Diverter Variance Request NDB Surface Hole Map View.......................................33 Attachment 12: Oil Search Alaska 21-day BOPE Test Schedule Waiver Approval Letter.................34 Attachment 13: Injector Area of Review..........................................................................................37 Attachment 14: Managed Pressure Drilling.....................................................................................40 Attachment 15: As Built Survey NDB Well 34 Conductor Final........................................................42 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-034. 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 2355 FSL, 3168 FEL, Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,741 E 422,076 Rig KB Elevation 47 above GL Ground Level 22.79 above MSL Location at Top of Productive Interval Reference to Government Section Lines 5263 FSL, 460 FEL, Sec 36, T12N, R5E, UM NAD 27 Coordinate System N 5,981,069 E 409,430 Measured Depth, Rig KB (MD)17,075 Total Vertical Depth, Rig KB (TVD)4,143 Total vertical Depth, Subsea (TVDSS)4,073 Location at Bottom of Productive Interval Reference to Government Section Lines 3003 FSL, 4784 FEL, Sec 24, T12N, R5E, UM NAD 27 Coordinate System N 5,989,422 E 405,206 Measured Depth, Rig KB (MD)26,460 Total Vertical Depth, Rig KB (TVD)4,034 Total vertical Depth, Subsea (TVDSS)3,964 (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 #1 Hole Pressure Data Maximum anticipated BHP 1,575 psi at TD in Seabee at 3,328 TVD (9.1ppg EMW in the Seabee formation to section TD) Maximum surface pressure 1,242 psi from TD in the Seabee (0.10 psi/ft gas gradient to surface, 3,328 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. (12.7 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 Intermediate #2 Hole Pressure Data Maximum anticipated BHP 1,868 psi in the Nanushuk 3 at 4,082 TVD (8.8ppg EMW Nanushuk 3 formation to section TD) Maximum surface pressure 1,460 psi from the Nanushuk 3 (0.10 psi/ft gas gradient to surface, 4,082 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. (11.4 ppg LOT required for Kick Tolerance with 10.5ppg 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) 6-1/8 Production Hole Pressure Data Maximum anticipated BHP 1,895 psi in the Nanushuk 3.2 at 4,142 TVD (8.8ppg EMW top NT3.2 formation to heel target) Maximum surface pressure 1,481 psi from the NT3.2 (0.10 psi/ft gas gradient to surface, 4,142 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 6-1/8 hole FIT after drilling 20-50 of new hole to 14.0 ppg. (10.3 ppg required for infinite kick tolerance with 9.8ppg MW) 7 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 10.2ppg 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. (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 20x34215# X-52 Welded 80Surface 128 / 128 16 13-3/868# L-80 TXP BTC 3,050Surface 3,050 / 2,396 12-1/4 9-5/847# L-80 HYD 563 9,1002,900 12,000 /3,328 Tie Back 9-5/847# L-80 HYD 563 2,900Surface 2,900 / 2,344 8-1/2 x 9-7/87 26 L-80 HYD 563 4,81011,850 16,660 / 4,083 6-1/8 4-1/212.6# P-110S HYD 563 9,95016,510 26,460 / 4,034 Tubing 4-1/212.6# P-110S HYD 563 16,510Surface 16,510 / 4,032 Please refer to Attachment 6: Cement Summary for further details. The Tuluvak is expected to be over-pressured at 10.2ppg pore pressure. 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 Please refer to Attachment 3: BOPE Equipment for further details. A diverter variance is requested for NDBi-034. 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 Int #2 Hole 6-1/8 Prod Hole Mud Type Spud Mud (WBM)MOBM 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 9.5 - 12.0 ppg 50 - 80 sec ALAP 15 - 30 n/a < 5 ml/30min n/a n/a 7.5* - 10.0 ppg (>9.0ppg via MPD) 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. *Please refer to Section 15 for further detail on mud weight variance request in production hole by using Managed Pressure Drilling (MPD) technology while drilling to stay dynamically overbalanced at all times. Recommend granting diverter variance on the condition that the surface hole will not be drilled more than 250' TVD below the MCU marker. TS 10/24/25 (>9.0ppg via MPD A diverter variance is requested for NDBi-034 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-034 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-034 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed NDBi-034 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 48hrs 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 #1 to TD. Perform wiper trips as required. Circulate and condition hole to run liner. POOH. 13. RU and run 9-5/8 intermediate liner #1 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 and lay down 5- 7/8 drillpipe and liner running tool. 17. Pressure test casing 13-3/8 casing and 9-5/8 liner to 2600 psi for 30 min. 18. Make up 8-1/2 RSS BHA with MWD and LWD tools. RIH on 5 drillpipe, clean out to top of float equipment and drill out the shoe track. 19. Drill out the 9-5/8 shoe and 20 - 50 of new formation. Perform FIT / LOT. 20. Install the MPD bearing assembly and adjust mud weight as required for ECD management with MPD. 21. Directionally drill 8-1/2 x 9-7/8 intermediate hole section #2 to TD utilizing MPD. Perform wiper trips as required. 22. Circulate and condition hole to run liner. Displace weighted trip fluid as required and POOH. 23. Run cleanout/string mill assembly to dress the 9-5/8 CFLEX tool. 24. RU and run 7 intermediate liner #2 as per casing tally then RIH on 5 DP / HWDP to TD. Circulate and condition mud prior to commencing cement job. 25. Set liner hanger and release running tool. Cement 7 liner as per cement program. Monitor returns during displacement until plug bump. 26. Set liner top packer, un-sting from liner hanger, POOH and LD liner running tools. 27. RIH with polish mill assembly for cleanout of the 9-5/8 liner top PBR. Run 9-5/8 tieback string. Freeze protect the 13-3/8 x 9-5/8 annulus with diesel and land tieback. 28. Pressure test the 13-3/8 x 9-5/8 annulus to 2600 psi for 30 min. 29. Change upper BOP rams from 4-1/2 x 7 VBRs to 3-1/2 x 5-1/2 VBRs. Test rams to 3600 psi high and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 48hrs notice for witnessing BOP test. 30. Pressure test the 9-5/8 liner / tieback and 7 liner to 3500 psi for 30 min. 31. Make up 6-1/8 RSS BHA with MWD and LWD tools. RIH on tapered string with 4 x 5 drillpipe. 32. RIH to top of the float equipment logging 7 liner cement with Sonic LWD tool on the trip in. 33. Displace well to MOBM at the required mud weight for MPD while drilling out the shoe track. 34. Circulate casing clean, install the MPD bearing assembly and test MPD surface equipment as required. 35. Drill 20 - 50 of new formation. Perform FIT / LOT. 36. Directionally drill 6-1/8 production hole section to TD using MPD. Perform wiper trips as required. 37. Circulate and condition hole to run liner. Displace weighted trip fluid as required and POOH. 38. RU and run 4-1/2 production liner as per tally then RIH on tapered 4 x 5 DP to TD. 39. Circulate MOBM out of open hole with NaCl brine with biocide. Spot tail end of the spacer near the liner hanger/packer. Drop 1.125 ball during circulation to close WIV. 40. Close WIV collar and liner hanger/top packer. 41. 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. 42. Circulate 9.2ppg viscosified brine with Lube 776 at 10 bpm. 43. POOH and LD liner running tool. 44. RU and run 4-1/2 upper completion and downhole jewelry with TEC wire. Space out seals. 45. Circulate 9.2ppg NaCl Brine with corrosion inhibitor and biocide. Land tubing hanger. 46. 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. 47. Reverse circulate freeze protect and U-Tube. 48. Install TWC, pressure test to 2,500 psi for 10 mins. ND BOPE, NU frac tree. 49. 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 Request 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-034 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-034 surface hole is surrounded by more than 20 other existing surface holes at the NDB pad location. Additionally, there are 2 previously drilled wells (NDB-027 and NDB-037) within 600 of the proposed NDBi-034 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 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-034 well. NDBi-034 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-034 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, NDBi-034 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 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 Cement Job: The primary cement job will target a top of cement 1000 feet MD (~100 feet TVD at ~84° inclination) above the 9-5/8 shoe. Due to ERD nature of this section, 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. Note, with this well design the 9-5/8 is considered as an intermediate drilling liner and the shoe is not designed to isolate any significant hydrocarbon zones or abnormally geo-pressured strata. Isolation over the top of the Nanushuk formation will be provided by cement integrity at the subsequent 7 liner shoe. 2. 9-5/8 Secondary Cement Job: To not place cement across the entire annular space from the 9-5/8 shoe to above shallowest significant hydrocarbon zone. A two-stage cement job will be performed to isolate the shoe in the Seabee, and the second stage cement job will isolate the significant hydrocarbon zone in the Tuluvak formation. Due to the ERD nature and high angle of the Pikka NDB development wells, a single stage cement job on the 9-5/8 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: 1) provide suitable and safe operating conditions for the total measured depth proposed; 2) confine fluids to the wellbore; 3) prevent migration of fluids from one stratum to another; 4) ensure control of well pressures encountered; 5) protect against thaw subsidence and freezeback effects within permafrost; 6) prevent contamination of freshwater; 7) protect significant hydrocarbon zones; and 8) 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 2,640 TVD. The Tuluvak formation below 2,640 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. 3. 7 Liner Cement Job: The 7 liner 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 73-84°), 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 ~263 feet TVD (~1323 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. c) Minimize the operational risk of cement returns up into the 9-5/8 shoe and above the top of the 7 liner hanger. 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. Recommend approving variance for two stage cement job. TS 10/27/25 20 AAC 25.033. Primary well control for drilling: drilling fluid program and drilling fluid system. (b)(1)(A) A drilling fluid of sufficient density to overbalance the pressure of uncased formations penetrated A variance is requested to the above regulation 20 AAC 25.033 (b)(1)(A) for drilling fluid density in the production hole only. Due to the ERD nature of these wells, staying under the ECD limit of 13.5ppg has become extremely difficult to manage. Exceeding the 13.5ppg ECD limit greatly increases the risk of lost circulation and further increases the risk of unsuccessful well execution. A ~7.5-8.0ppg mud weight will be used with Managed Pressure Drilling (MPD). MPD will be utilized to drill the production hole while being statically and dynamically overbalanced to the Nanushuk formation by holding back pressure on connections and while drilling (if needed). A 9.5-10.0ppg fluid will be circulated in the hole prior to tripping. Two independent barriers will be maintained throughout the operations: 6-1/8 Drilling: (1) RCD and MPD choke (2) BOP stack 6-1/8 Tripping and 4-1/2 Liner Run: (1) 9.5-10.0ppg mud (2) BOP stack The Pikka development at NDB pad has well established pore pressures with active monitoring via downhole pressure gauges. The target interval is an oil reservoir with limited formation permeability. The MPD choke will be set up to automatically trap pressure on connections, or anytime the mud pump is stopped. The choke pressure will be set to maintain a constant bottom hole pressure. The MPD chokes will prevent a sudden drop in surface pressure if the pumps are stopped suddenly. MPD equipment has been installed and in use on the rig since October 2024. The rig crews are familiar with the equipment and communication between the rig crew and MPD technicians have been excellent. There is an additional driller responsibility to notify the MPD technician of a change in pump rate, however, this is a courtesy notification as the MPD system will automatically trap pressure when the pump is shut down. The MPD provider (Beyond Energy Services) has extensive experience utilizing the MPD system to drill dynamically overbalanced. Beyond has established procedures and contingency plans in place fit for purpose for the Parker 272 rig to ensure that sufficient surface pressure is kept on the well to maintain overbalanced to the Nanushuk formation. All influxes to be circulated out per conventional well kill protocols. Rig crew to monitor flow and pit levels per standard operations. Rig crew to shut in per standard operations (no change to standing orders). Influx will be managed conventionally with closed BOP and slow pump rate. This is the first time Oil Search has requested this variance. See conditions of approval. -bjm Attachments Attachment 1: Location Maps ADL 392991 ADL 392968 ADL 392991 ADL 392984ADL 372106ADL 392958 ADL 392992 ADL 392970 ADL 393021 ADL 393019 ADL 393018 ADL 393020 ADL 393015 ADL 393016 ADL 393006 ADL 393007 ADL 391445 ADL 391454 ADL 391455 ADL 393009 ADL 393011 ADL 393010 FIORD 3A FIORD 3 QUGRUK 301 QUGRUK 3A COLVILLE RIV UNIT CD1-15 FIORD 2 QUGRUK 7 CD1-15PB1 Colville River Unit CD1-15PB2 DW-02 NDB-010 NDB-011 NDB-024 NDB-025 NDB-027 NDB-032 NDB-037 NDB-040 NDB-051 NDBi-006 NDBi-014 NDBi-016 NDBi-018 NDBi-030 NDBi-034 NDBi-036 NDBi-043A NDBi-044 NDBi-049 OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD 0.25-MILE BUFFER 0.5-MILE BUFFER NDBI-034 SURFACE LOCATION NDBI-034 BOTTOM HOLE PRODUCTION INTERVAL NDBI-034 OTHER DRILLED NDB WELLS EXPLORATION WELLS BOTTOM HOLES WELL TRAJECTORIES BY OTHERS SANTOS LEASES CPAI LEASES SECTIONS DATE: 9/19/2025. By: JN 0 0.1 0.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDBi34_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 0.2 0.4 Kilometers PIKKA DEVELOPMENT NDBi-034 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 0.00 347.0 0.0 0.0 0.00 0.00 0.0 Start Build 3.00 3 587.0 6.00 308.00 586.6 7.7 -9.9 2.50 308.00 12.5 4 1000.3 18.40 308.00 989.8 61.4 -78.6 3.00 0.00 99.2 5 1160.3 18.40 308.00 1141.6 92.5 -118.4 0.00 0.00 149.4 6 2832.0 68.36 300.39 2319.1 686.4 -1057.2 3.00 -9.23 1236.9 7 2932.0 68.36 300.39 2356.0 733.4 -1137.4 0.00 0.00 1327.3 8 3464.4 84.31 299.47 2481.4 990.5 -1584.3 3.00 -3.32 1827.2 9 15065.1 84.31 299.47 3632.2 6670.1 -11633.9 0.00 0.00 12997.7 10 16454.2 65.13 338.11 4010.0 7637.9 -12509.5 3.00 121.57 14300.0 11 17075.9 90.00 338.11 4142.8 8196.8 -12734.1 4.00 0.0014850.1 NDBi-034 Alt Heel Rev 5.0_650ft 12 19458.4 90.00 338.11 4142.8 10407.5 -13622.4 0.00 0.00 17026.2 NDBi-034 Alt Mid Point Rev 1.0 13 19840.1 90.23 330.48 4142.0 10751.2 -13787.9 2.00 -88.2617384.1 14 25847.1 90.23 330.48 4117.8 15978.2 -16748.0 0.00 0.00 23146.7 Initiation Point of the Toe-Up 15 26460.2 105.49 330.61 4034.2 16505.5 -17045.8 2.49 0.48 23727.4 NDbi-034 Alt Toe up Rev 5.0 47 500 500 1000 1000 1500 1500 2000 2000 2500 2500 3000 3000 5000 5000 6000 6000 7000 7000 8000 8000 9000 9000 10000 10000 12000 12000 14000 14000 16000 16000 18000 18000 20000 20000 25000 Plan: NDBi-034 Rev M.0 Plan Summary 0 3 Dogleg Severity0 4000 8000 12000 16000 20000 24000 Measured Depth 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Intermediate Liner 7" Intermediate Liner 4-1/2" x 6-1/8" 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] 475075100125150175200225250275300325350374398423447471496520544568NDB-29 Slot Saver475176101126151176201226251276301326351375400424448473497522546571595619644668692717741765789813837NDBi-030 475075100125150175200225250 275300325350375399424448473497521546570594618641665688712735758781803826NDB-031 475075100125150175200225250275300325350375399424449474498523547572596621645670694718742766790814838862886909933957980NDB-032 7075100125150175200225250275300325350375400424449474499523548572596620644668691715738761784807830 852 Plan: NDB-033 Rev A.0 475075100125150175200225250275300325350375400425450475500525550575600625650674699723747772796820843867891914937960983NDB-035 Slot Saver 475075100125150175200225250 275300325350375400425451476501526551576601626651675700724748772796820843 866 889 NDBi-036 475075100125150175200225250275300325350376401427452478503528554579605630656681707 7327587838098348598859109359619861011103610611086111111361161118612111236126112861311133613611386141014351460148515091534155915831608163316571682170617311755178018041828185318771901192619501974199820222047207120952119214321672190221422382262NDB-037 475075100125150175200225250275300325350375401426452477502527552577602627651676700724748772796Plan: NDBi-038 Rev A.0 475075100125150175200225250275300325350376401427453478504530555581607632658684710735761787813838 8648909169419679931018104310681093111811431168119412201246127112971323134913751401Plan: NDB-039 Rev A.0 19628 19611 19594 19577 19559 19542 19524 19507 19489 Fiord 3A 0 2250 True Vertical Depth0 3250 6500 9750 13000 16250 19500 22750 Vertical Section at 314.08° 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Intermediate Liner 7" Intermediate Liner 4-1/2" x 6-1/8" 0 28 55 Centre to Centre Separation0 275 550 825 1100 1375 1650 1925 Measured Depth Equivalent Magnetic Distance DDI 7.591 SURVEY PROGRAM Date: 2021-02-16T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 47.0 1000.0 Plan: NDBi-034 Rev M.0 (NDBi-034)SDI_URSA+SAG 1000.0 3050.0 Plan: NDBi-034 Rev M.0 (NDBi-034)3_MWD+IFR2+MS+Sag 3050.0 12000.0 Plan: NDBi-034 Rev M.0 (NDBi-034)3_MWD+IFR2+MS+Sag 12000.0 16660.0 Plan: NDBi-034 Rev M.0 (NDBi-034)3_MWD+IFR2+MS+Sag 16660.0 26460.2 Plan: NDBi-034 Rev M.0 (NDBi-034)3_MWD+IFR2+MS+Sag Surface Location North / 5972488.93 East / 1562109.30 Elevation / 22.8 CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2396.1 3050.013-3/8" Surface Casing 3328.1 12000.09-5/8" Intermediate Liner 4082.8 16660.0 7" Intermediate Liner 4034.2 26460.0 4-1/2" x 6-1/8" Mag Model & Date: BGGM2025 31-Dec-25 Magnetic North is 13.41° East of True North (Magnetic De Mag Dip & Field Strength: 80.51°57091.97576 FORMATION TOP DETAILS TVDPathFormation 1045.6 Upper SB 1394.1 BP Transition 1740.0 Middle SB 2146.7 MCU 2443.7 Tuluvak Shale 2498.4 Tuluvak Sand 2794.8 TS_790 3412.0 Seabee 3808.8 Nanushuk 3863.2NT8 MFS 3909.7 NT7 MFS 3953.5 NT6 MFS 3984.4 NT5 MFS 4033.6 NT4 MFS 4061.5NT3.2 Top Res. Toe Up 4067.3NT3 MFS Toe Up 4086.9 NT3 MFS 4090.7NT3.2 Top Reservoir 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 17 September, 2025 Plan: Plan: NDBi-034 Rev M.0 Santos NAD27 Conversion Pikka NDB B-34 NDBi-034 Santos Ltd Planning Report - Geographic Well B-34Local 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-34Well: NDBi-034Wellbore: Plan: NDBi-034 Rev M.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-34 Wellhead Elevation:0.5 0.0 0.0 5,972,740.93 422,076.50 70° 20' 8.345 N 150° 37' 55.918 W 22.8 usft usft usft usft usft usft usft °-0.60Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NDBi-034 Model NameMagnetics BGGM2025 31/12/2025 13.41 80.51 57,091.97549720 Phase:Version: Audit Notes: Design Plan: NDBi-034 Rev M.0 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:47.0 314.080.00.047.0 Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Date 17/09/2025 Depth To (usft) Depth From (usft) SDI_URSA+SAG SDI URSA gyroMWD + SAG Plan: NDBi-034 Rev M.0 (NDBi-0147.0 1,000.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-034 Rev M.0 (NDBi-021,000.0 3,050.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-034 Rev M.0 (NDBi-033,050.0 12,000.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-034 Rev M.0 (NDBi-0412,000.0 16,660.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDBi-034 Rev M.0 (NDBi-0516,660.0 26,460.0 17/09/2025 15:36:53 COMPASS 5000.17 Build Page 2 Santos Ltd Planning Report - Geographic Well B-34Local 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-34Well: NDBi-034Wellbore: Plan: NDBi-034 Rev M.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 0.000.000.000.000.00.0347.00.000.00347.0 308.000.002.502.50-9.97.7586.6308.006.00587.0 0.000.003.003.00-78.661.4989.8308.0018.401,000.3 0.000.000.000.00-118.492.51,141.6308.0018.401,160.3 -9.23-0.462.993.00-1,057.2686.42,319.1300.3968.362,832.0 0.000.000.000.00-1,137.4733.42,356.0300.3968.362,932.0 -3.30-0.173.003.00-1,584.3990.62,481.3299.4884.313,464.4 0.000.000.000.00-11,633.46,670.73,632.3299.4884.3115,064.9 121.572.78-1.383.00-12,508.97,638.54,010.0338.1165.1316,453.9 0.000.004.004.00-12,733.48,197.44,142.8338.1190.0017,075.6 NDBi-034 Alt Heel R 90.000.000.000.00-13,621.610,408.24,142.8338.1290.0019,458.1 NDBi-034 Alt Mid P -88.26-2.000.062.00-13,787.110,752.14,142.0330.4890.2319,840.1 0.000.000.000.00-16,746.715,979.24,117.8330.4890.2325,846.9 Initiation Point of the 0.480.022.492.49-17,044.416,506.54,034.2330.61105.4926,460.0 NDbi-034 Alt Toe up 17/09/2025 15:36:53 COMPASS 5000.17 Build Page 3 Santos Ltd Planning Report - Geographic Well B-34Local 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-34Well: NDBi-034Wellbore: Plan: NDBi-034 Rev M.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 0.00.00 422,076.505,972,740.93 70° 20' 8.345 N 150° 37' 55.918 W 100.0 0.00 100.0 0.0 0.00.00 422,076.505,972,740.93 70° 20' 8.345 N 150° 37' 55.918 W 128.0 0.00 128.0 0.0 0.00.00 422,076.505,972,740.93 70° 20' 8.345 N 150° 37' 55.918 W 20" Conductor Casing 200.0 0.00 200.0 0.0 0.00.00 422,076.505,972,740.93 70° 20' 8.345 N 150° 37' 55.918 W 300.0 0.00 300.0 0.0 0.00.00 422,076.505,972,740.93 70° 20' 8.345 N 150° 37' 55.918 W 347.0 0.00 347.0 0.0 0.00.00 422,076.505,972,740.93 70° 20' 8.345 N 150° 37' 55.918 W Start Build 3.00 400.0 1.33 400.0 0.4 -0.5308.00 422,076.025,972,741.32 70° 20' 8.349 N 150° 37' 55.932 W 500.0 3.83 499.9 3.1 -4.0308.00 422,072.515,972,744.12 70° 20' 8.376 N 150° 37' 56.036 W 547.0 5.00 546.7 5.4 -6.9308.00 422,069.685,972,746.37 70° 20' 8.398 N 150° 37' 56.119 W Start DLS 3.00 TFO -45.70 587.0 6.00 586.6 7.7 -9.9308.00 422,066.695,972,748.76 70° 20' 8.422 N 150° 37' 56.207 W 600.0 6.39 599.5 8.6 -11.0308.00 422,065.595,972,749.64 70° 20' 8.430 N 150° 37' 56.239 W 700.0 9.39 698.5 17.0 -21.8308.00 422,054.865,972,758.20 70° 20' 8.513 N 150° 37' 56.555 W 800.0 12.39 796.7 28.7 -36.7308.00 422,040.105,972,769.98 70° 20' 8.627 N 150° 37' 56.990 W 900.0 15.39 893.8 43.5 -55.6308.00 422,021.345,972,784.96 70° 20' 8.773 N 150° 37' 57.542 W 1,000.0 18.39 989.5 61.3 -78.5308.00 421,998.645,972,803.08 70° 20' 8.949 N 150° 37' 58.211 W 1,000.3 18.40 989.8 61.4 -78.6308.00 421,998.565,972,803.14 70° 20' 8.949 N 150° 37' 58.213 W 1,059.1 18.40 1,045.6 72.8 -93.2308.00 421,984.065,972,814.72 70° 20' 9.062 N 150° 37' 58.640 W Upper Schrader Bluff 1,100.0 18.40 1,084.3 80.8 -103.4308.00 421,973.975,972,822.77 70° 20' 9.140 N 150° 37' 58.937 W 1,160.3 18.40 1,141.6 92.5 -118.4308.00 421,959.095,972,834.64 70° 20' 9.255 N 150° 37' 59.376 W 1,200.0 19.58 1,179.1 100.4 -128.6307.43 421,948.965,972,842.64 70° 20' 9.333 N 150° 37' 59.674 W 1,300.0 22.55 1,272.4 121.9 -157.4306.25 421,920.425,972,864.46 70° 20' 9.544 N 150° 38' 0.514 W 1,400.0 25.52 1,363.7 145.7 -190.4305.33 421,887.635,972,888.60 70° 20' 9.779 N 150° 38' 1.479 W 1,433.8 26.53 1,394.1 154.3 -202.5305.06 421,875.615,972,897.27 70° 20' 9.863 N 150° 38' 1.833 W Base Permafrost Transition 1,500.0 28.50 1,452.8 171.7 -227.6304.59 421,850.685,972,914.99 70° 20' 10.034 N 150° 38' 2.566 W 1,600.0 31.49 1,539.4 199.9 -268.9303.98 421,809.675,972,943.57 70° 20' 10.311 N 150° 38' 3.773 W 1,700.0 34.48 1,623.3 230.1 -314.2303.47 421,764.715,972,974.25 70° 20' 10.608 N 150° 38' 5.095 W 1,800.0 37.46 1,704.2 262.3 -363.3303.03 421,715.945,973,006.95 70° 20' 10.925 N 150° 38' 6.529 W 1,845.5 38.83 1,740.0 277.6 -386.9302.85 421,692.505,973,022.48 70° 20' 11.075 N 150° 38' 7.219 W Middle Schrader Bluff 1,900.0 40.46 1,782.0 296.4 -416.2302.64 421,663.475,973,041.58 70° 20' 11.260 N 150° 38' 8.072 W 2,000.0 43.45 1,856.3 332.3 -472.6302.30 421,607.465,973,078.05 70° 20' 11.613 N 150° 38' 9.719 W 2,100.0 46.44 1,927.1 369.8 -532.4302.00 421,548.055,973,116.25 70° 20' 11.983 N 150° 38' 11.466 W 2,200.0 49.43 1,994.1 409.0 -595.4301.72 421,485.425,973,156.08 70° 20' 12.368 N 150° 38' 13.307 W 2,300.0 52.43 2,057.1 449.7 -661.5301.47 421,419.735,973,197.43 70° 20' 12.768 N 150° 38' 15.239 W 2,400.0 55.42 2,116.0 491.7 -730.5301.24 421,351.175,973,240.19 70° 20' 13.181 N 150° 38' 17.254 W 2,455.3 57.08 2,146.7 515.5 -769.9301.12 421,312.095,973,264.40 70° 20' 13.415 N 150° 38' 18.403 W MCU 2,500.0 58.42 2,170.6 535.0 -802.3301.02 421,279.915,973,284.24 70° 20' 13.607 N 150° 38' 19.349 W 2,600.0 61.41 2,220.7 579.5 -876.5300.82 421,206.175,973,329.46 70° 20' 14.044 N 150° 38' 21.517 W 2,700.0 64.41 2,266.2 625.0 -953.0300.63 421,130.135,973,375.73 70° 20' 14.492 N 150° 38' 23.752 W 2,800.0 67.40 2,307.0 671.4 -1,031.6300.45 421,052.005,973,422.91 70° 20' 14.948 N 150° 38' 26.048 W 2,832.0 68.36 2,319.1 686.4 -1,057.2300.39 421,026.605,973,438.19 70° 20' 15.095 N 150° 38' 26.795 W 2,900.0 68.36 2,344.2 718.3 -1,111.7300.39 420,972.425,973,470.72 70° 20' 15.410 N 150° 38' 28.387 W 2,932.0 68.36 2,356.0 733.4 -1,137.4300.39 420,946.925,973,486.03 70° 20' 15.557 N 150° 38' 29.137 W 3,000.0 70.40 2,379.9 765.5 -1,192.3300.27 420,892.335,973,518.73 70° 20' 15.873 N 150° 38' 30.741 W 3,050.0 71.89 2,396.1 789.3 -1,233.2300.18 420,851.705,973,542.97 70° 20' 16.108 N 150° 38' 31.935 W 13-3/8" Surface Casing 3,100.0 73.39 2,411.0 813.3 -1,274.5300.09 420,810.685,973,567.35 70° 20' 16.343 N 150° 38' 33.141 W 3,159.6 75.18 2,427.1 842.0 -1,324.2299.98 420,761.295,973,596.60 70° 20' 16.626 N 150° 38' 34.593 W Start 12092.6 hold at 3159.6 MD 3,200.0 76.39 2,437.1 861.6 -1,358.1299.91 420,727.595,973,616.48 70° 20' 16.818 N 150° 38' 35.583 W 3,229.2 77.26 2,443.7 875.8 -1,382.7299.87 420,703.065,973,630.92 70° 20' 16.957 N 150° 38' 36.304 W Tuluvak Shale 17/09/2025 15:36:53 COMPASS 5000.17 Build Page 4 Santos Ltd Planning Report - Geographic Well B-34Local 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-34Well: NDBi-034Wellbore: Plan: NDBi-034 Rev M.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) 3,300.0 79.38 2,458.0 910.2 -1,442.9299.75 420,643.305,973,665.98 70° 20' 17.296 N 150° 38' 38.060 W 3,400.0 82.38 2,473.9 959.1 -1,528.7299.58 420,558.045,973,715.73 70° 20' 17.776 N 150° 38' 40.566 W 3,464.4 84.31 2,481.3 990.6 -1,584.3299.48 420,502.765,973,747.80 70° 20' 18.086 N 150° 38' 42.191 W 3,500.0 84.31 2,484.9 1,008.0 -1,615.1299.48 420,472.075,973,765.58 70° 20' 18.257 N 150° 38' 43.093 W 3,600.0 84.31 2,494.8 1,057.0 -1,701.8299.48 420,385.965,973,815.43 70° 20' 18.739 N 150° 38' 45.623 W 3,636.3 84.31 2,498.4 1,074.8 -1,733.2299.48 420,354.685,973,833.55 70° 20' 18.914 N 150° 38' 46.542 W Tuluvak Sand 3,700.0 84.31 2,504.7 1,105.9 -1,788.4299.48 420,299.865,973,865.29 70° 20' 19.220 N 150° 38' 48.154 W 3,800.0 84.31 2,514.6 1,154.9 -1,875.0299.48 420,213.755,973,915.15 70° 20' 19.702 N 150° 38' 50.684 W 3,900.0 84.31 2,524.6 1,203.9 -1,961.6299.48 420,127.655,973,965.00 70° 20' 20.183 N 150° 38' 53.215 W 4,000.0 84.31 2,534.5 1,252.8 -2,048.3299.48 420,041.545,974,014.86 70° 20' 20.664 N 150° 38' 55.745 W 4,100.0 84.31 2,544.4 1,301.8 -2,134.9299.48 419,955.445,974,064.72 70° 20' 21.146 N 150° 38' 58.276 W 4,200.0 84.31 2,554.3 1,350.8 -2,221.5299.48 419,869.335,974,114.58 70° 20' 21.627 N 150° 39' 0.807 W 4,300.0 84.31 2,564.3 1,399.7 -2,308.2299.48 419,783.235,974,164.43 70° 20' 22.108 N 150° 39' 3.337 W 4,400.0 84.31 2,574.2 1,448.7 -2,394.8299.48 419,697.135,974,214.29 70° 20' 22.589 N 150° 39' 5.868 W 4,500.0 84.31 2,584.1 1,497.7 -2,481.4299.48 419,611.025,974,264.15 70° 20' 23.071 N 150° 39' 8.399 W 4,600.0 84.31 2,594.0 1,546.6 -2,568.0299.48 419,524.925,974,314.01 70° 20' 23.552 N 150° 39' 10.930 W 4,700.0 84.31 2,603.9 1,595.6 -2,654.7299.48 419,438.815,974,363.86 70° 20' 24.033 N 150° 39' 13.460 W 4,800.0 84.31 2,613.9 1,644.5 -2,741.3299.48 419,352.715,974,413.72 70° 20' 24.515 N 150° 39' 15.991 W 4,900.0 84.31 2,623.8 1,693.5 -2,827.9299.48 419,266.605,974,463.58 70° 20' 24.996 N 150° 39' 18.522 W 5,000.0 84.31 2,633.7 1,742.5 -2,914.5299.48 419,180.505,974,513.44 70° 20' 25.477 N 150° 39' 21.053 W 5,100.0 84.31 2,643.6 1,791.4 -3,001.2299.48 419,094.395,974,563.29 70° 20' 25.958 N 150° 39' 23.584 W 5,200.0 84.31 2,653.5 1,840.4 -3,087.8299.48 419,008.295,974,613.15 70° 20' 26.439 N 150° 39' 26.115 W 5,300.0 84.31 2,663.5 1,889.4 -3,174.4299.48 418,922.195,974,663.01 70° 20' 26.921 N 150° 39' 28.646 W 5,400.0 84.31 2,673.4 1,938.3 -3,261.0299.48 418,836.085,974,712.86 70° 20' 27.402 N 150° 39' 31.177 W 5,500.0 84.31 2,683.3 1,987.3 -3,347.7299.48 418,749.985,974,762.72 70° 20' 27.883 N 150° 39' 33.708 W 5,600.0 84.31 2,693.2 2,036.3 -3,434.3299.48 418,663.875,974,812.58 70° 20' 28.364 N 150° 39' 36.239 W 5,700.0 84.31 2,703.2 2,085.2 -3,520.9299.48 418,577.775,974,862.44 70° 20' 28.845 N 150° 39' 38.770 W 5,800.0 84.31 2,713.1 2,134.2 -3,607.5299.48 418,491.665,974,912.29 70° 20' 29.327 N 150° 39' 41.302 W 5,900.0 84.31 2,723.0 2,183.2 -3,694.2299.48 418,405.565,974,962.15 70° 20' 29.808 N 150° 39' 43.833 W 6,000.0 84.31 2,732.9 2,232.1 -3,780.8299.48 418,319.455,975,012.01 70° 20' 30.289 N 150° 39' 46.364 W 6,100.0 84.31 2,742.8 2,281.1 -3,867.4299.48 418,233.355,975,061.87 70° 20' 30.770 N 150° 39' 48.895 W 6,200.0 84.31 2,752.8 2,330.1 -3,954.0299.48 418,147.255,975,111.72 70° 20' 31.251 N 150° 39' 51.427 W 6,300.0 84.31 2,762.7 2,379.0 -4,040.7299.48 418,061.145,975,161.58 70° 20' 31.732 N 150° 39' 53.958 W 6,400.0 84.31 2,772.6 2,428.0 -4,127.3299.48 417,975.045,975,211.44 70° 20' 32.213 N 150° 39' 56.489 W 6,500.0 84.31 2,782.5 2,476.9 -4,213.9299.48 417,888.935,975,261.30 70° 20' 32.694 N 150° 39' 59.021 W 6,600.0 84.31 2,792.4 2,525.9 -4,300.5299.48 417,802.835,975,311.15 70° 20' 33.175 N 150° 40' 1.552 W 6,624.3 84.31 2,794.8 2,537.8 -4,321.6299.48 417,781.925,975,323.26 70° 20' 33.292 N 150° 40' 2.167 W TS_790 6,700.0 84.31 2,802.4 2,574.9 -4,387.2299.48 417,716.725,975,361.01 70° 20' 33.656 N 150° 40' 4.084 W 6,800.0 84.31 2,812.3 2,623.8 -4,473.8299.48 417,630.625,975,410.87 70° 20' 34.138 N 150° 40' 6.615 W 6,900.0 84.31 2,822.2 2,672.8 -4,560.4299.48 417,544.515,975,460.72 70° 20' 34.619 N 150° 40' 9.147 W 7,000.0 84.31 2,832.1 2,721.8 -4,647.1299.48 417,458.415,975,510.58 70° 20' 35.100 N 150° 40' 11.678 W 7,100.0 84.31 2,842.0 2,770.7 -4,733.7299.48 417,372.315,975,560.44 70° 20' 35.581 N 150° 40' 14.210 W 7,200.0 84.31 2,852.0 2,819.7 -4,820.3299.48 417,286.205,975,610.30 70° 20' 36.062 N 150° 40' 16.742 W 7,300.0 84.31 2,861.9 2,868.7 -4,906.9299.48 417,200.105,975,660.15 70° 20' 36.543 N 150° 40' 19.273 W 7,400.0 84.31 2,871.8 2,917.6 -4,993.6299.48 417,113.995,975,710.01 70° 20' 37.024 N 150° 40' 21.805 W 7,500.0 84.31 2,881.7 2,966.6 -5,080.2299.48 417,027.895,975,759.87 70° 20' 37.505 N 150° 40' 24.337 W 7,600.0 84.31 2,891.7 3,015.6 -5,166.8299.48 416,941.785,975,809.73 70° 20' 37.986 N 150° 40' 26.869 W 7,700.0 84.31 2,901.6 3,064.5 -5,253.4299.48 416,855.685,975,859.58 70° 20' 38.467 N 150° 40' 29.400 W 7,800.0 84.31 2,911.5 3,113.5 -5,340.1299.48 416,769.575,975,909.44 70° 20' 38.948 N 150° 40' 31.932 W 7,900.0 84.31 2,921.4 3,162.4 -5,426.7299.48 416,683.475,975,959.30 70° 20' 39.429 N 150° 40' 34.464 W 8,000.0 84.31 2,931.3 3,211.4 -5,513.3299.48 416,597.375,976,009.15 70° 20' 39.909 N 150° 40' 36.996 W 8,100.0 84.31 2,941.3 3,260.4 -5,599.9299.48 416,511.265,976,059.01 70° 20' 40.390 N 150° 40' 39.528 W 8,200.0 84.31 2,951.2 3,309.3 -5,686.6299.48 416,425.165,976,108.87 70° 20' 40.871 N 150° 40' 42.060 W 8,300.0 84.31 2,961.1 3,358.3 -5,773.2299.48 416,339.055,976,158.73 70° 20' 41.352 N 150° 40' 44.592 W 8,400.0 84.31 2,971.0 3,407.3 -5,859.8299.48 416,252.955,976,208.58 70° 20' 41.833 N 150° 40' 47.124 W 8,500.0 84.31 2,980.9 3,456.2 -5,946.4299.48 416,166.845,976,258.44 70° 20' 42.314 N 150° 40' 49.656 W 8,600.0 84.31 2,990.9 3,505.2 -6,033.1299.48 416,080.745,976,308.30 70° 20' 42.795 N 150° 40' 52.188 W 17/09/2025 15:36:53 COMPASS 5000.17 Build Page 5 Santos Ltd Planning Report - Geographic Well B-34Local 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-34Well: NDBi-034Wellbore: Plan: NDBi-034 Rev M.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) 8,700.0 84.31 3,000.8 3,554.2 -6,119.7299.48 415,994.635,976,358.16 70° 20' 43.276 N 150° 40' 54.720 W 8,800.0 84.31 3,010.7 3,603.1 -6,206.3299.48 415,908.535,976,408.01 70° 20' 43.757 N 150° 40' 57.253 W 8,900.0 84.31 3,020.6 3,652.1 -6,292.9299.48 415,822.435,976,457.87 70° 20' 44.237 N 150° 40' 59.785 W 9,000.0 84.31 3,030.5 3,701.1 -6,379.6299.48 415,736.325,976,507.73 70° 20' 44.718 N 150° 41' 2.317 W 9,100.0 84.31 3,040.5 3,750.0 -6,466.2299.48 415,650.225,976,557.59 70° 20' 45.199 N 150° 41' 4.849 W 9,200.0 84.31 3,050.4 3,799.0 -6,552.8299.48 415,564.115,976,607.44 70° 20' 45.680 N 150° 41' 7.382 W 9,300.0 84.31 3,060.3 3,848.0 -6,639.4299.48 415,478.015,976,657.30 70° 20' 46.161 N 150° 41' 9.914 W 9,400.0 84.31 3,070.2 3,896.9 -6,726.1299.48 415,391.905,976,707.16 70° 20' 46.642 N 150° 41' 12.446 W 9,500.0 84.31 3,080.2 3,945.9 -6,812.7299.48 415,305.805,976,757.01 70° 20' 47.122 N 150° 41' 14.979 W 9,600.0 84.31 3,090.1 3,994.8 -6,899.3299.48 415,219.695,976,806.87 70° 20' 47.603 N 150° 41' 17.511 W 9,700.0 84.31 3,100.0 4,043.8 -6,985.9299.48 415,133.595,976,856.73 70° 20' 48.084 N 150° 41' 20.044 W 9,800.0 84.31 3,109.9 4,092.8 -7,072.6299.48 415,047.495,976,906.59 70° 20' 48.565 N 150° 41' 22.576 W 9,900.0 84.31 3,119.8 4,141.7 -7,159.2299.48 414,961.385,976,956.44 70° 20' 49.045 N 150° 41' 25.109 W 10,000.0 84.31 3,129.8 4,190.7 -7,245.8299.48 414,875.285,977,006.30 70° 20' 49.526 N 150° 41' 27.641 W 10,100.0 84.31 3,139.7 4,239.7 -7,332.5299.48 414,789.175,977,056.16 70° 20' 50.007 N 150° 41' 30.174 W 10,200.0 84.31 3,149.6 4,288.6 -7,419.1299.48 414,703.075,977,106.02 70° 20' 50.488 N 150° 41' 32.707 W 10,300.0 84.31 3,159.5 4,337.6 -7,505.7299.48 414,616.965,977,155.87 70° 20' 50.968 N 150° 41' 35.239 W 10,400.0 84.31 3,169.4 4,386.6 -7,592.3299.48 414,530.865,977,205.73 70° 20' 51.449 N 150° 41' 37.772 W 10,500.0 84.31 3,179.4 4,435.5 -7,679.0299.48 414,444.755,977,255.59 70° 20' 51.930 N 150° 41' 40.305 W 10,600.0 84.31 3,189.3 4,484.5 -7,765.6299.48 414,358.655,977,305.44 70° 20' 52.410 N 150° 41' 42.837 W 10,700.0 84.31 3,199.2 4,533.5 -7,852.2299.48 414,272.555,977,355.30 70° 20' 52.891 N 150° 41' 45.370 W 10,800.0 84.31 3,209.1 4,582.4 -7,938.8299.48 414,186.445,977,405.16 70° 20' 53.372 N 150° 41' 47.903 W 10,900.0 84.31 3,219.1 4,631.4 -8,025.5299.48 414,100.345,977,455.02 70° 20' 53.852 N 150° 41' 50.436 W 11,000.0 84.31 3,229.0 4,680.3 -8,112.1299.48 414,014.235,977,504.87 70° 20' 54.333 N 150° 41' 52.969 W 11,100.0 84.31 3,238.9 4,729.3 -8,198.7299.48 413,928.135,977,554.73 70° 20' 54.814 N 150° 41' 55.502 W 11,200.0 84.31 3,248.8 4,778.3 -8,285.3299.48 413,842.025,977,604.59 70° 20' 55.294 N 150° 41' 58.035 W 11,300.0 84.31 3,258.7 4,827.2 -8,372.0299.48 413,755.925,977,654.45 70° 20' 55.775 N 150° 42' 0.568 W 11,400.0 84.31 3,268.7 4,876.2 -8,458.6299.48 413,669.815,977,704.30 70° 20' 56.255 N 150° 42' 3.101 W 11,500.0 84.31 3,278.6 4,925.2 -8,545.2299.48 413,583.715,977,754.16 70° 20' 56.736 N 150° 42' 5.634 W 11,600.0 84.31 3,288.5 4,974.1 -8,631.8299.48 413,497.615,977,804.02 70° 20' 57.217 N 150° 42' 8.167 W 11,700.0 84.31 3,298.4 5,023.1 -8,718.5299.48 413,411.505,977,853.88 70° 20' 57.697 N 150° 42' 10.700 W 11,800.0 84.31 3,308.3 5,072.1 -8,805.1299.48 413,325.405,977,903.73 70° 20' 58.178 N 150° 42' 13.233 W 11,900.0 84.31 3,318.3 5,121.0 -8,891.7299.48 413,239.295,977,953.59 70° 20' 58.658 N 150° 42' 15.766 W 12,000.0 84.31 3,328.2 5,170.0 -8,978.3299.48 413,153.195,978,003.45 70° 20' 59.139 N 150° 42' 18.300 W 9-5/8" Intermediate Liner 12,100.0 84.31 3,338.1 5,219.0 -9,065.0299.48 413,067.085,978,053.30 70° 20' 59.619 N 150° 42' 20.833 W 12,200.0 84.31 3,348.0 5,267.9 -9,151.6299.48 412,980.985,978,103.16 70° 21' 0.100 N 150° 42' 23.366 W 12,300.0 84.31 3,357.9 5,316.9 -9,238.2299.48 412,894.875,978,153.02 70° 21' 0.580 N 150° 42' 25.900 W 12,400.0 84.31 3,367.9 5,365.9 -9,324.8299.48 412,808.775,978,202.88 70° 21' 1.061 N 150° 42' 28.433 W 12,500.0 84.31 3,377.8 5,414.8 -9,411.5299.48 412,722.675,978,252.73 70° 21' 1.541 N 150° 42' 30.966 W 12,600.0 84.31 3,387.7 5,463.8 -9,498.1299.48 412,636.565,978,302.59 70° 21' 2.022 N 150° 42' 33.500 W 12,700.0 84.31 3,397.6 5,512.7 -9,584.7299.48 412,550.465,978,352.45 70° 21' 2.502 N 150° 42' 36.033 W 12,800.0 84.31 3,407.6 5,561.7 -9,671.4299.48 412,464.355,978,402.31 70° 21' 2.983 N 150° 42' 38.567 W 12,844.7 84.31 3,412.0 5,583.6 -9,710.1299.48 412,425.845,978,424.60 70° 21' 3.198 N 150° 42' 39.700 W Seabee 12,900.0 84.31 3,417.5 5,610.7 -9,758.0299.48 412,378.255,978,452.16 70° 21' 3.463 N 150° 42' 41.100 W 13,000.0 84.31 3,427.4 5,659.6 -9,844.6299.48 412,292.145,978,502.02 70° 21' 3.944 N 150° 42' 43.634 W 13,100.0 84.31 3,437.3 5,708.6 -9,931.2299.48 412,206.045,978,551.88 70° 21' 4.424 N 150° 42' 46.167 W 13,200.0 84.31 3,447.2 5,757.6 -10,017.9299.48 412,119.935,978,601.73 70° 21' 4.905 N 150° 42' 48.701 W 13,300.0 84.31 3,457.2 5,806.5 -10,104.5299.48 412,033.835,978,651.59 70° 21' 5.385 N 150° 42' 51.235 W 13,400.0 84.31 3,467.1 5,855.5 -10,191.1299.48 411,947.735,978,701.45 70° 21' 5.865 N 150° 42' 53.768 W 13,500.0 84.31 3,477.0 5,904.5 -10,277.7299.48 411,861.625,978,751.31 70° 21' 6.346 N 150° 42' 56.302 W 13,600.0 84.31 3,486.9 5,953.4 -10,364.4299.48 411,775.525,978,801.16 70° 21' 6.826 N 150° 42' 58.836 W 13,700.0 84.31 3,496.8 6,002.4 -10,451.0299.48 411,689.415,978,851.02 70° 21' 7.307 N 150° 43' 1.370 W 13,800.0 84.31 3,506.8 6,051.4 -10,537.6299.48 411,603.315,978,900.88 70° 21' 7.787 N 150° 43' 3.904 W 13,900.0 84.31 3,516.7 6,100.3 -10,624.2299.48 411,517.205,978,950.74 70° 21' 8.267 N 150° 43' 6.437 W 14,000.0 84.31 3,526.6 6,149.3 -10,710.9299.48 411,431.105,979,000.59 70° 21' 8.748 N 150° 43' 8.971 W 14,100.0 84.31 3,536.5 6,198.2 -10,797.5299.48 411,344.995,979,050.45 70° 21' 9.228 N 150° 43' 11.505 W 14,200.0 84.31 3,546.4 6,247.2 -10,884.1299.48 411,258.895,979,100.31 70° 21' 9.708 N 150° 43' 14.039 W 17/09/2025 15:36:53 COMPASS 5000.17 Build Page 6 Santos Ltd Planning Report - Geographic Well B-34Local 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-34Well: NDBi-034Wellbore: Plan: NDBi-034 Rev M.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) 14,300.0 84.31 3,556.4 6,296.2 -10,970.7299.48 411,172.795,979,150.17 70° 21' 10.189 N 150° 43' 16.573 W 14,400.0 84.31 3,566.3 6,345.1 -11,057.4299.48 411,086.685,979,200.02 70° 21' 10.669 N 150° 43' 19.107 W 14,500.0 84.31 3,576.2 6,394.1 -11,144.0299.48 411,000.585,979,249.88 70° 21' 11.149 N 150° 43' 21.641 W 14,600.0 84.31 3,586.1 6,443.1 -11,230.6299.48 410,914.475,979,299.74 70° 21' 11.630 N 150° 43' 24.175 W 14,700.0 84.31 3,596.1 6,492.0 -11,317.2299.48 410,828.375,979,349.59 70° 21' 12.110 N 150° 43' 26.709 W 14,800.0 84.31 3,606.0 6,541.0 -11,403.9299.48 410,742.265,979,399.45 70° 21' 12.590 N 150° 43' 29.244 W 14,900.0 84.31 3,615.9 6,590.0 -11,490.5299.48 410,656.165,979,449.31 70° 21' 13.070 N 150° 43' 31.778 W 15,000.0 84.31 3,625.8 6,638.9 -11,577.1299.48 410,570.055,979,499.17 70° 21' 13.551 N 150° 43' 34.312 W 15,064.9 84.31 3,632.3 6,670.7 -11,633.4299.48 410,514.165,979,531.53 70° 21' 13.862 N 150° 43' 35.957 W 15,100.0 83.76 3,635.9 6,688.1 -11,663.6300.38 410,484.105,979,549.25 70° 21' 14.033 N 150° 43' 36.842 W 15,200.0 82.20 3,648.1 6,740.2 -11,748.1302.96 410,400.205,979,602.22 70° 21' 14.544 N 150° 43' 39.313 W 15,252.2 81.39 3,655.6 6,768.8 -11,791.1304.32 410,357.495,979,631.28 70° 21' 14.825 N 150° 43' 40.571 W Start DLS 3.00 TFO 112.90 15,300.0 80.65 3,663.1 6,795.9 -11,829.8305.56 410,319.075,979,658.72 70° 21' 15.090 N 150° 43' 41.704 W 15,400.0 79.13 3,680.6 6,854.9 -11,908.5308.19 410,240.955,979,718.59 70° 21' 15.670 N 150° 43' 44.009 W 15,500.0 77.62 3,700.8 6,917.3 -11,984.1310.84 410,166.055,979,781.68 70° 21' 16.282 N 150° 43' 46.220 W 15,600.0 76.15 3,723.5 6,982.6 -12,056.3313.52 410,094.575,979,847.80 70° 21' 16.923 N 150° 43' 48.333 W 15,700.0 74.70 3,748.6 7,050.9 -12,124.8316.24 410,026.715,979,916.77 70° 21' 17.594 N 150° 43' 50.341 W 15,800.0 73.29 3,776.2 7,121.9 -12,189.6318.99 409,962.665,979,988.42 70° 21' 18.291 N 150° 43' 52.238 W 15,900.0 71.91 3,806.1 7,195.4 -12,250.5321.78 409,902.595,980,062.53 70° 21' 19.013 N 150° 43' 54.020 W 15,908.5 71.79 3,808.8 7,201.8 -12,255.5322.02 409,897.655,980,068.97 70° 21' 19.075 N 150° 43' 54.167 W Nanushuk 16,000.0 70.57 3,838.3 7,271.2 -12,307.2324.62 409,846.665,980,138.91 70° 21' 19.757 N 150° 43' 55.682 W 16,073.3 69.62 3,863.2 7,328.1 -12,346.0326.73 409,808.415,980,196.19 70° 21' 20.316 N 150° 43' 56.820 W NT8 MFS 16,100.0 69.28 3,872.6 7,349.1 -12,359.6327.50 409,795.045,980,217.35 70° 21' 20.523 N 150° 43' 57.219 W 16,200.0 68.04 3,909.0 7,428.9 -12,407.7330.43 409,747.855,980,297.63 70° 21' 21.307 N 150° 43' 58.626 W 16,201.9 68.02 3,909.7 7,430.4 -12,408.5330.49 409,747.025,980,299.14 70° 21' 21.321 N 150° 43' 58.651 W NT7 MFS 16,267.2 67.24 3,934.6 7,483.5 -12,437.4332.43 409,718.695,980,352.54 70° 21' 21.843 N 150° 43' 59.498 W Start Build 4.00 16,300.0 66.85 3,947.3 7,510.4 -12,451.1333.42 409,705.245,980,379.54 70° 21' 22.107 N 150° 43' 59.901 W 16,315.5 66.67 3,953.5 7,523.1 -12,457.4333.88 409,699.055,980,392.38 70° 21' 22.233 N 150° 44' 0.086 W NT6 MFS 16,392.4 65.80 3,984.4 7,586.9 -12,487.1336.22 409,670.035,980,456.46 70° 21' 22.859 N 150° 44' 0.957 W NT5 MFS 16,400.0 65.72 3,987.6 7,593.3 -12,489.9336.45 409,667.315,980,462.85 70° 21' 22.922 N 150° 44' 1.039 W 16,453.9 65.13 4,010.0 7,638.5 -12,508.9338.11 409,648.855,980,508.26 70° 21' 23.366 N 150° 44' 1.595 W 16,500.0 66.98 4,028.7 7,677.6 -12,524.6338.11 409,633.555,980,547.50 70° 21' 23.750 N 150° 44' 2.056 W 16,512.7 67.48 4,033.6 7,688.4 -12,528.9338.11 409,629.315,980,558.38 70° 21' 23.857 N 150° 44' 2.184 W NT4 MFS 16,600.0 70.98 4,064.6 7,764.2 -12,559.4338.11 409,599.665,980,634.44 70° 21' 24.602 N 150° 44' 3.077 W 16,660.0 73.38 4,082.9 7,817.2 -12,580.6338.11 409,578.925,980,687.65 70° 21' 25.122 N 150° 44' 3.702 W 7" Intermediate Liner 16,674.1 73.94 4,086.9 7,829.7 -12,585.7338.11 409,574.015,980,700.24 70° 21' 25.246 N 150° 44' 3.850 W NT3 MFS 16,687.9 74.49 4,090.7 7,842.1 -12,590.7338.11 409,569.175,980,712.67 70° 21' 25.367 N 150° 44' 3.996 W NT3.2 Top Reservoir 16,700.0 74.98 4,093.8 7,852.9 -12,595.0338.11 409,564.945,980,723.50 70° 21' 25.473 N 150° 44' 4.124 W 16,708.0 75.30 4,095.9 7,860.0 -12,597.9338.11 409,562.145,980,730.68 70° 21' 25.544 N 150° 44' 4.208 W Start 8578.3 hold at 16708.0 MD 16,800.0 78.98 4,116.4 7,943.3 -12,631.3338.11 409,529.575,980,814.25 70° 21' 26.362 N 150° 44' 5.190 W 16,900.0 82.98 4,132.0 8,034.9 -12,668.1338.11 409,493.715,980,906.24 70° 21' 27.262 N 150° 44' 6.271 W 17,000.0 86.98 4,140.8 8,127.3 -12,705.3338.11 409,457.545,980,999.03 70° 21' 28.170 N 150° 44' 7.361 W 17,075.6 90.00 4,142.8 8,197.4 -12,733.4338.11 409,430.115,981,069.40 70° 21' 28.859 N 150° 44' 8.188 W 17,100.0 90.00 4,142.8 8,220.0 -12,742.5338.11 409,421.235,981,092.16 70° 21' 29.082 N 150° 44' 8.455 W 17,200.0 90.00 4,142.8 8,312.8 -12,779.8338.11 409,384.925,981,185.32 70° 21' 29.994 N 150° 44' 9.550 W 17,300.0 90.00 4,142.8 8,405.6 -12,817.1338.11 409,348.605,981,278.48 70° 21' 30.906 N 150° 44' 10.645 W 17/09/2025 15:36:53 COMPASS 5000.17 Build Page 7 Santos Ltd Planning Report - Geographic Well B-34Local 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-34Well: NDBi-034Wellbore: Plan: NDBi-034 Rev M.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) 17,400.0 90.00 4,142.8 8,498.4 -12,854.4338.11 409,312.295,981,371.65 70° 21' 31.818 N 150° 44' 11.739 W 17,500.0 90.00 4,142.8 8,591.2 -12,891.7338.11 409,275.975,981,464.81 70° 21' 32.730 N 150° 44' 12.834 W 17,600.0 90.00 4,142.8 8,684.0 -12,929.0338.11 409,239.665,981,557.97 70° 21' 33.642 N 150° 44' 13.929 W 17,700.0 90.00 4,142.8 8,776.8 -12,966.2338.11 409,203.355,981,651.14 70° 21' 34.554 N 150° 44' 15.024 W 17,800.0 90.00 4,142.8 8,869.6 -13,003.5338.11 409,167.045,981,744.30 70° 21' 35.466 N 150° 44' 16.118 W 17,900.0 90.00 4,142.8 8,962.4 -13,040.8338.11 409,130.725,981,837.47 70° 21' 36.378 N 150° 44' 17.213 W 18,000.0 90.00 4,142.8 9,055.2 -13,078.1338.11 409,094.415,981,930.63 70° 21' 37.289 N 150° 44' 18.308 W 18,100.0 90.00 4,142.8 9,147.9 -13,115.4338.11 409,058.105,982,023.80 70° 21' 38.201 N 150° 44' 19.403 W 18,200.0 90.00 4,142.8 9,240.7 -13,152.6338.11 409,021.795,982,116.96 70° 21' 39.113 N 150° 44' 20.497 W 18,300.0 90.00 4,142.8 9,333.5 -13,189.9338.11 408,985.485,982,210.13 70° 21' 40.025 N 150° 44' 21.592 W 18,400.0 90.00 4,142.8 9,426.3 -13,227.2338.11 408,949.185,982,303.29 70° 21' 40.937 N 150° 44' 22.687 W 18,500.0 90.00 4,142.8 9,519.1 -13,264.5338.11 408,912.875,982,396.46 70° 21' 41.849 N 150° 44' 23.782 W 18,600.0 90.00 4,142.8 9,611.9 -13,301.8338.11 408,876.565,982,489.62 70° 21' 42.761 N 150° 44' 24.877 W 18,700.0 90.00 4,142.8 9,704.7 -13,339.0338.11 408,840.255,982,582.79 70° 21' 43.673 N 150° 44' 25.971 W 18,800.0 90.00 4,142.8 9,797.5 -13,376.3338.11 408,803.955,982,675.96 70° 21' 44.585 N 150° 44' 27.066 W 18,900.0 90.00 4,142.8 9,890.3 -13,413.6338.11 408,767.645,982,769.12 70° 21' 45.497 N 150° 44' 28.161 W 19,000.0 90.00 4,142.8 9,983.1 -13,450.9338.12 408,731.345,982,862.29 70° 21' 46.409 N 150° 44' 29.256 W 19,100.0 90.00 4,142.8 10,075.9 -13,488.1338.12 408,695.035,982,955.46 70° 21' 47.321 N 150° 44' 30.351 W 19,200.0 90.00 4,142.8 10,168.7 -13,525.4338.12 408,658.735,983,048.63 70° 21' 48.233 N 150° 44' 31.446 W 19,300.0 90.00 4,142.8 10,261.5 -13,562.7338.12 408,622.435,983,141.79 70° 21' 49.145 N 150° 44' 32.541 W 19,400.0 90.00 4,142.8 10,354.3 -13,599.9338.12 408,586.135,983,234.96 70° 21' 50.057 N 150° 44' 33.635 W 19,458.1 90.00 4,142.8 10,408.2 -13,621.6338.12 408,565.025,983,289.12 70° 21' 50.587 N 150° 44' 34.272 W 19,500.0 90.03 4,142.8 10,446.9 -13,637.5337.28 408,549.545,983,328.02 70° 21' 50.968 N 150° 44' 34.739 W 19,600.0 90.09 4,142.7 10,538.5 -13,677.7335.28 408,510.275,983,419.97 70° 21' 51.867 N 150° 44' 35.920 W 19,700.0 90.15 4,142.5 10,628.6 -13,721.1333.28 408,467.825,983,510.50 70° 21' 52.752 N 150° 44' 37.194 W 19,800.0 90.21 4,142.2 10,717.1 -13,767.6331.28 408,422.245,983,599.49 70° 21' 53.622 N 150° 44' 38.559 W 19,840.1 90.23 4,142.0 10,752.1 -13,787.1330.48 408,403.115,983,634.69 70° 21' 53.966 N 150° 44' 39.131 W 19,900.0 90.23 4,141.8 10,804.2 -13,816.7330.48 408,374.135,983,687.14 70° 21' 54.478 N 150° 44' 39.997 W 20,000.0 90.23 4,141.4 10,891.3 -13,865.9330.48 408,325.775,983,774.66 70° 21' 55.333 N 150° 44' 41.443 W 20,100.0 90.23 4,141.0 10,978.3 -13,915.2330.48 408,277.415,983,862.18 70° 21' 56.188 N 150° 44' 42.888 W 20,200.0 90.23 4,140.6 11,065.3 -13,964.5330.48 408,229.055,983,949.69 70° 21' 57.043 N 150° 44' 44.334 W 20,300.0 90.23 4,140.2 11,152.3 -14,013.7330.48 408,180.695,984,037.21 70° 21' 57.898 N 150° 44' 45.780 W 20,400.0 90.23 4,139.8 11,239.3 -14,063.0330.48 408,132.345,984,124.73 70° 21' 58.753 N 150° 44' 47.226 W 20,500.0 90.23 4,139.4 11,326.4 -14,112.3330.48 408,083.985,984,212.25 70° 21' 59.608 N 150° 44' 48.671 W 20,600.0 90.23 4,139.0 11,413.4 -14,161.5330.48 408,035.625,984,299.77 70° 22' 0.463 N 150° 44' 50.117 W 20,700.0 90.23 4,138.5 11,500.4 -14,210.8330.48 407,987.265,984,387.29 70° 22' 1.318 N 150° 44' 51.563 W 20,800.0 90.23 4,138.1 11,587.4 -14,260.1330.48 407,938.905,984,474.80 70° 22' 2.173 N 150° 44' 53.009 W 20,900.0 90.23 4,137.7 11,674.4 -14,309.4330.48 407,890.545,984,562.32 70° 22' 3.028 N 150° 44' 54.455 W 21,000.0 90.23 4,137.3 11,761.5 -14,358.6330.48 407,842.195,984,649.84 70° 22' 3.882 N 150° 44' 55.901 W 21,100.0 90.23 4,136.9 11,848.5 -14,407.9330.48 407,793.835,984,737.36 70° 22' 4.737 N 150° 44' 57.347 W 21,200.0 90.23 4,136.5 11,935.5 -14,457.2330.48 407,745.475,984,824.88 70° 22' 5.592 N 150° 44' 58.793 W 21,300.0 90.23 4,136.1 12,022.5 -14,506.4330.48 407,697.115,984,912.40 70° 22' 6.447 N 150° 45' 0.239 W 21,400.0 90.23 4,135.7 12,109.5 -14,555.7330.48 407,648.755,984,999.91 70° 22' 7.302 N 150° 45' 1.685 W 21,500.0 90.23 4,135.3 12,196.6 -14,605.0330.48 407,600.395,985,087.43 70° 22' 8.157 N 150° 45' 3.131 W 21,600.0 90.23 4,134.9 12,283.6 -14,654.2330.48 407,552.045,985,174.95 70° 22' 9.012 N 150° 45' 4.578 W 21,700.0 90.23 4,134.5 12,370.6 -14,703.5330.48 407,503.685,985,262.47 70° 22' 9.867 N 150° 45' 6.024 W 21,800.0 90.23 4,134.1 12,457.6 -14,752.8330.48 407,455.325,985,349.99 70° 22' 10.721 N 150° 45' 7.470 W 21,900.0 90.23 4,133.7 12,544.6 -14,802.0330.48 407,406.965,985,437.51 70° 22' 11.576 N 150° 45' 8.916 W 22,000.0 90.23 4,133.3 12,631.6 -14,851.3330.48 407,358.605,985,525.02 70° 22' 12.431 N 150° 45' 10.363 W 22,100.0 90.23 4,132.9 12,718.7 -14,900.6330.48 407,310.245,985,612.54 70° 22' 13.286 N 150° 45' 11.809 W 22,200.0 90.23 4,132.5 12,805.7 -14,949.9330.48 407,261.895,985,700.06 70° 22' 14.141 N 150° 45' 13.255 W 22,300.0 90.23 4,132.1 12,892.7 -14,999.1330.48 407,213.535,985,787.58 70° 22' 14.996 N 150° 45' 14.702 W 22,400.0 90.23 4,131.7 12,979.7 -15,048.4330.48 407,165.175,985,875.10 70° 22' 15.851 N 150° 45' 16.148 W 22,500.0 90.23 4,131.3 13,066.7 -15,097.7330.48 407,116.815,985,962.62 70° 22' 16.705 N 150° 45' 17.595 W 22,600.0 90.23 4,130.9 13,153.8 -15,146.9330.48 407,068.455,986,050.13 70° 22' 17.560 N 150° 45' 19.041 W 22,700.0 90.23 4,130.5 13,240.8 -15,196.2330.48 407,020.095,986,137.65 70° 22' 18.415 N 150° 45' 20.488 W 22,800.0 90.23 4,130.1 13,327.8 -15,245.5330.48 406,971.745,986,225.17 70° 22' 19.270 N 150° 45' 21.934 W 22,900.0 90.23 4,129.7 13,414.8 -15,294.7330.48 406,923.385,986,312.69 70° 22' 20.125 N 150° 45' 23.381 W 23,000.0 90.23 4,129.3 13,501.8 -15,344.0330.48 406,875.025,986,400.21 70° 22' 20.980 N 150° 45' 24.828 W 23,100.0 90.23 4,128.9 13,588.9 -15,393.3330.48 406,826.665,986,487.72 70° 22' 21.834 N 150° 45' 26.274 W 17/09/2025 15:36:53 COMPASS 5000.17 Build Page 8 Santos Ltd Planning Report - Geographic Well B-34Local 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-34Well: NDBi-034Wellbore: Plan: NDBi-034 Rev M.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) 23,200.0 90.23 4,128.5 13,675.9 -15,442.6330.48 406,778.305,986,575.24 70° 22' 22.689 N 150° 45' 27.721 W 23,300.0 90.23 4,128.1 13,762.9 -15,491.8330.48 406,729.945,986,662.76 70° 22' 23.544 N 150° 45' 29.168 W 23,400.0 90.23 4,127.7 13,849.9 -15,541.1330.48 406,681.595,986,750.28 70° 22' 24.399 N 150° 45' 30.614 W 23,500.0 90.23 4,127.3 13,936.9 -15,590.4330.48 406,633.235,986,837.80 70° 22' 25.254 N 150° 45' 32.061 W 23,600.0 90.23 4,126.9 14,024.0 -15,639.6330.48 406,584.875,986,925.32 70° 22' 26.108 N 150° 45' 33.508 W 23,700.0 90.23 4,126.4 14,111.0 -15,688.9330.48 406,536.515,987,012.83 70° 22' 26.963 N 150° 45' 34.955 W 23,800.0 90.23 4,126.0 14,198.0 -15,738.2330.48 406,488.155,987,100.35 70° 22' 27.818 N 150° 45' 36.402 W 23,900.0 90.23 4,125.6 14,285.0 -15,787.4330.48 406,439.795,987,187.87 70° 22' 28.673 N 150° 45' 37.849 W 24,000.0 90.23 4,125.2 14,372.0 -15,836.7330.48 406,391.445,987,275.39 70° 22' 29.528 N 150° 45' 39.296 W 24,100.0 90.23 4,124.8 14,459.1 -15,886.0330.48 406,343.085,987,362.91 70° 22' 30.382 N 150° 45' 40.743 W 24,200.0 90.23 4,124.4 14,546.1 -15,935.3330.48 406,294.725,987,450.43 70° 22' 31.237 N 150° 45' 42.190 W 24,300.0 90.23 4,124.0 14,633.1 -15,984.5330.48 406,246.365,987,537.94 70° 22' 32.092 N 150° 45' 43.637 W 24,400.0 90.23 4,123.6 14,720.1 -16,033.8330.48 406,198.005,987,625.46 70° 22' 32.947 N 150° 45' 45.084 W 24,500.0 90.23 4,123.2 14,807.1 -16,083.1330.48 406,149.645,987,712.98 70° 22' 33.801 N 150° 45' 46.531 W 24,600.0 90.23 4,122.8 14,894.1 -16,132.3330.48 406,101.295,987,800.50 70° 22' 34.656 N 150° 45' 47.979 W 24,700.0 90.23 4,122.4 14,981.2 -16,181.6330.48 406,052.935,987,888.02 70° 22' 35.511 N 150° 45' 49.426 W 24,800.0 90.23 4,122.0 15,068.2 -16,230.9330.48 406,004.575,987,975.54 70° 22' 36.366 N 150° 45' 50.873 W 24,900.0 90.23 4,121.6 15,155.2 -16,280.1330.48 405,956.215,988,063.05 70° 22' 37.221 N 150° 45' 52.320 W 25,000.0 90.23 4,121.2 15,242.2 -16,329.4330.48 405,907.855,988,150.57 70° 22' 38.075 N 150° 45' 53.768 W 25,100.0 90.23 4,120.8 15,329.2 -16,378.7330.48 405,859.495,988,238.09 70° 22' 38.930 N 150° 45' 55.215 W 25,200.0 90.23 4,120.4 15,416.3 -16,427.9330.48 405,811.145,988,325.61 70° 22' 39.785 N 150° 45' 56.662 W 25,286.3 90.23 4,120.1 15,491.3 -16,470.5330.48 405,769.415,988,401.12 70° 22' 40.522 N 150° 45' 57.911 W TD at 25286.3 25,300.0 90.23 4,120.0 15,503.3 -16,477.2330.48 405,762.785,988,413.13 70° 22' 40.640 N 150° 45' 58.110 W 25,400.0 90.23 4,119.6 15,590.3 -16,526.5330.48 405,714.425,988,500.64 70° 22' 41.494 N 150° 45' 59.557 W 25,500.0 90.23 4,119.2 15,677.3 -16,575.8330.48 405,666.065,988,588.16 70° 22' 42.349 N 150° 46' 1.005 W 25,600.0 90.23 4,118.8 15,764.3 -16,625.0330.48 405,617.705,988,675.68 70° 22' 43.204 N 150° 46' 2.452 W 25,700.0 90.23 4,118.4 15,851.4 -16,674.3330.48 405,569.345,988,763.20 70° 22' 44.059 N 150° 46' 3.900 W 25,800.0 90.23 4,118.0 15,938.4 -16,723.6330.48 405,520.995,988,850.72 70° 22' 44.913 N 150° 46' 5.347 W 25,846.9 90.23 4,117.8 15,979.2 -16,746.7330.48 405,498.305,988,891.78 70° 22' 45.314 N 150° 46' 6.027 W 25,900.0 91.55 4,117.0 16,025.4 -16,772.8330.49 405,472.635,988,938.23 70° 22' 45.768 N 150° 46' 6.795 W 26,000.0 94.04 4,112.1 16,112.3 -16,822.0330.51 405,424.375,989,025.66 70° 22' 46.622 N 150° 46' 8.240 W 26,100.0 96.53 4,102.9 16,199.0 -16,871.0330.53 405,376.295,989,112.83 70° 22' 47.473 N 150° 46' 9.679 W 26,200.0 99.02 4,089.3 16,285.3 -16,919.7330.56 405,328.475,989,199.59 70° 22' 48.321 N 150° 46' 11.111 W 26,300.0 101.51 4,071.5 16,371.0 -16,968.1330.58 405,281.025,989,285.78 70° 22' 49.162 N 150° 46' 12.532 W 26,321.0 102.03 4,067.2 16,388.9 -16,978.2330.58 405,271.115,989,303.79 70° 22' 49.338 N 150° 46' 12.828 W NT3 MFS Toe Up 26,348.0 102.70 4,061.5 16,411.8 -16,991.1330.59 405,258.405,989,326.89 70° 22' 49.564 N 150° 46' 13.209 W NT3.2 Top Res. Toe Up 26,400.0 104.00 4,049.5 16,455.9 -17,016.0330.60 405,234.025,989,371.22 70° 22' 49.997 N 150° 46' 13.939 W 26,460.0 105.49 4,034.2 16,506.5 -17,044.4330.61 405,206.075,989,422.05 70° 22' 50.493 N 150° 46' 14.776 W 17/09/2025 15:36:53 COMPASS 5000.17 Build Page 9 Santos Ltd Planning Report - Geographic Well B-34Local 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-34Well: NDBi-034Wellbore: Plan: NDBi-034 Rev M.0Design: Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Design Targets LongitudeLatitude Dip Angle (°) Dip Dir. (°) NDbi-034 Alt Toe up R 4,034.2 5,989,422.05 405,206.0716,506.5 -17,044.40.00 0.00 70° 22' 50.493 N 150° 46' 14.776 W - plan hits target center - Point Initiation Point of the T 4,117.8 5,988,891.78 405,498.3015,979.2 -16,746.70.00 0.00 70° 22' 45.314 N 150° 46' 6.027 W - plan hits target center - Point NDBi-034 Alt Heel Re 4,142.8 5,981,069.40 409,430.118,197.4 -12,733.40.00 0.00 70° 21' 28.859 N 150° 44' 8.188 W - plan hits target center - Polygon -84.5Point 1 5,980,980.95 409,810.474,142.8 381.3 True 8,668.4Point 2 5,989,779.75 405,359.984,142.8 -4,160.8 True 8,392.7Point 3 5,989,509.63 404,823.994,142.8 -4,694.0 True -360.1Point 4 5,980,710.93 409,274.494,142.8 -151.9 True NDBi-034 Alt Mid Poin 4,142.8 5,983,289.12 408,565.0210,408.2 -13,621.60.00 0.00 70° 21' 50.587 N 150° 44' 34.272 W - plan hits target center - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 20" Conductor Casing128.0128.0 20 20 13-3/8" Surface Casing2,396.13,050.0 13-3/8 16 9-5/8" Intermediate Liner3,328.212,000.0 9-5/8 12-1/4 7" Intermediate Liner4,082.916,660.0 7 8-1/2 4-1/2" x 6-1/8"4,034.226,460.0 4-1/2 6-1/8 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 1,059.1 Upper Schrader Bluff1,045.6 1,433.8 Base Permafrost Transition1,394.1 1,845.5 Middle Schrader Bluff1,740.0 2,455.3 MCU2,146.7 3,229.2 Tuluvak Shale2,443.7 3,636.3 Tuluvak Sand2,498.4 6,624.3 TS_7902,794.8 12,844.7 Seabee3,412.0 15,908.5 Nanushuk3,808.8 16,073.3 NT8 MFS3,863.2 16,201.9 NT7 MFS3,909.7 16,315.5 NT6 MFS3,953.5 16,392.4 NT5 MFS3,984.4 16,512.7 NT4 MFS4,033.6 26,348.0 NT3.2 Top Res. Toe Up 0.004,061.5 26,321.0 NT3 MFS Toe Up 0.004,067.2 16,674.1 NT3 MFS4,086.9 16,687.9 NT3.2 Top Reservoir4,090.7 17/09/2025 15:36:53 COMPASS 5000.17 Build Page 10 Santos Ltd Planning Report - Geographic Well B-34Local 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-34Well: NDBi-034Wellbore: Plan: NDBi-034 Rev M.0Design: Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 347.0 347.0 0.0 0.0 Start Build 3.00 547.0 546.7 5.4 -6.9 Start DLS 3.00 TFO -45.70 3,159.6 2,427.1 842.0 -1,324.2 Start 12092.6 hold at 3159.6 MD 15,252.2 3,655.6 6,768.8 -11,791.1 Start DLS 3.00 TFO 112.90 16,267.2 3,934.6 7,483.5 -12,437.4 Start Build 4.00 16,708.0 4,095.9 7,860.0 -12,597.9 Start 8578.3 hold at 16708.0 MD 25,286.3 4,120.1 15,491.3 -16,470.5 TD at 25286.3 17/09/2025 15:36:53 COMPASS 5000.17 Build Page 11 03000600090001200015000South(-)/North(+)-21000 -18000 -15000 -12000 -9000 -6000 -3000 0 3000West(-)/East(+)NDbi-034 Alt Toe up Rev 5.0Initiation Point of the Toe-UpNDBi-034 Alt Mid Point Rev 1.0NDBi-034 Alt Heel Rev 5.0_650ft95%20" Conductor Casing13-3/8" Surface Casing9-5/8" Intermediate Liner7" Intermediate Liner4-1/2" x 6-1/8"Plan: NDBi-034 Rev M.015:04, September 17 2025 01500300045006000True Vertical Depth0 3000 6000 9000 12000 15000 18000 21000 24000Vertical Section at 314.08°20" Conductor Casing13-3/8" Surface Casing9-5/8" Intermediate Liner7" Intermediate Liner4-1/2" x 6-1/8"4000500060007000800090001000011000120001300014000150001700018000 19000 20000 21000 22000 23000 24000 25000 2 6 0 0 026460 0°84°90°90° 90° P la n : N D B i-0 3 4 R e v M .0 Upper Schrader BluffBase Permafrost TransitionMiddle Schrader BluffMCUTuluvak ShaleTuluvak SandTS_790SeabeeNanushukNT8 MFS NT7 MFS NT6 MFS NT5 MFS NT4 MFS NT3 MFS NT3.2 Top ReservoirNT3 MFS Toe UpNT3.2 Top Res. Toe UpPlan: NDBi-034 Rev M.015:00, September 17 2025 17 September, 2025 Anticollision Summary Report Santos Pikka NDB B-34 NDBi-034 Plan: NDBi-034 Rev M.0 Santos Ltd Anticollision Summary Report Well B-34 - Slot B-34Local 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-34Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-034 Database:EDM Offset DatumReference Design:Plan: NDBi-034 Rev M.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 2,841.3usft Plan: NDBi-034 Rev M.0 Results Limited by: SigmaWarning Levels Evaluated at:2.79 ISCWSA TESTCasing Method: From (usft) Survey Tool Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 17/09/2025 SDI_URSA+SAG SDI URSA gyroMWD + SAG47.0 1,000.0 Plan: NDBi-034 Rev M.0 (NDBi-034) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag1,000.0 3,050.0 Plan: NDBi-034 Rev M.0 (NDBi-034) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag3,050.0 12,000.0 Plan: NDBi-034 Rev M.0 (NDBi-034) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag12,000.0 16,660.0 Plan: NDBi-034 Rev M.0 (NDBi-034) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag16,660.0 26,460.2 Plan: NDBi-034 Rev M.0 (NDBi-034) 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 Fiord 3 SFFiord 2 - Fiord 2 - Fiord 2 23,425.0 5,021.6 1,057.8 577.9 2.762 ESFiord 2 - Fiord 2 - Fiord 2 23,525.0 5,086.3 1,049.5 576.0 2.778 CCFiord 2 - Fiord 2 - Fiord 2 23,616.7 5,141.7 1,047.0 581.9 2.822 SFFiord 3 - Fiord 3 - Fiord 3 20,675.0 4,092.8 1,302.3 855.2 3.651 ESFiord 3 - Fiord 3 - Fiord 3 20,825.0 4,093.0 1,279.8 846.0 3.699 CCFiord 3 - Fiord 3 - Fiord 3 20,943.7 4,093.1 1,274.3 855.1 3.812 Normal Operations, ES, SFiord 3 - Fiord 3A - Fiord 3A 19,325.0 5,118.3 441.1 109.7 1.668 Normal Operations, CCFiord 3 - Fiord 3A - Fiord 3A 19,342.2 5,105.5 440.9 110.0 1.669 NDB CCB-22 - NDB-022 - Plan NDB-022 Rev A.0 325.0 325.2 239.5 229.6 43.295 ESB-22 - NDB-022 - Plan NDB-022 Rev A.0 350.0 350.2 239.5 229.6 42.834 SFB-22 - NDB-022 - Plan NDB-022 Rev A.0 8,125.0 7,573.6 2,836.8 2,569.2 13.367 CCB-23 - NDB-023 - NDB-023 Slot Saver 325.0 325.2 219.4 209.8 40.765 ESB-23 - NDB-023 - NDB-023 Slot Saver 350.0 350.2 219.4 209.8 40.481 SFB-23 - NDB-023 - NDB-023 Slot Saver 900.0 894.0 267.5 254.7 33.541 CCB-24 - NDB-024 - NDB-024 189.2 188.9 200.2 191.3 39.887 ESB-24 - NDB-024 - NDB-024 350.0 349.5 200.4 190.9 36.185 SFB-24 - NDB-024 - NDB-024 9,300.0 8,817.4 2,816.2 2,491.8 10.927 CCB-24 - NDB-024PB1 - NDB-024PB1 189.2 188.9 200.2 191.1 39.855 ESB-24 - NDB-024PB1 - NDB-024PB1 350.0 349.5 200.4 190.7 36.156 SFB-24 - NDB-024PB1 - NDB-024PB1 3,100.0 3,009.5 705.2 635.1 13.049 CCB-25 - NDB-025 - NDB-025 367.2 367.8 179.2 169.5 32.669 ESB-25 - NDB-025 - NDB-025 375.0 375.7 179.2 169.5 32.586 SFB-25 - NDB-025 - NDB-025 9,875.0 13,886.0 1,701.4 1,419.0 7.584 CCB-26 - NDBi-026 - Plan: NDBi-026 Rev A.0 325.0 325.0 160.1 150.3 28.808 ESB-26 - NDBi-026 - Plan: NDBi-026 Rev A.0 350.0 350.0 160.1 150.2 28.502 SFB-26 - NDBi-026 - Plan: NDBi-026 Rev A.0 10,900.0 10,489.7 2,836.1 2,416.9 8.503 CCB-27 - NDB-027 - NDB-027 47.0 47.0 140.2 131.1 29.700 ESB-27 - NDB-027 - NDB-027 353.7 354.0 140.8 131.2 25.709 SFB-27 - NDB-027 - NDB-027 18,175.0 17,284.6 1,569.1 1,010.4 3.519 CCB-27 - NDB-027 - Plan: NDB-027 Rev F.0 406.8 409.0 139.8 130.0 24.926 ESB-27 - NDB-027 - Plan: NDB-027 Rev F.0 450.0 453.0 139.9 129.9 24.159 SFB-27 - NDB-027 - Plan: NDB-027 Rev F.0 26,460.2 25,577.9 1,219.1 468.6 2.033 CCB-27 - NDB-027 PB1 - NDB-027 PB1 47.0 47.0 140.2 131.1 29.700 ESB-27 - NDB-027 PB1 - NDB-027 PB1 353.7 354.0 140.8 131.2 25.709 SFB-27 - NDB-027 PB1 - NDB-027 PB1 11,975.0 11,955.1 1,857.6 1,350.5 4.597 CCB-27 - NDB-027 PB1 - Plan: NDB-027 Rev G.0 47.0 47.0 140.2 131.1 29.700 17/09/2025 14:59:21 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-34 - Slot B-34Local 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-34Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-034 Database:EDM Offset DatumReference Design:Plan: NDBi-034 Rev M.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 ESB-27 - NDB-027 PB1 - Plan: NDB-027 Rev G.0 353.7 354.0 140.8 131.2 25.709 Normal Operations, SFB-27 - NDB-027 PB1 - Plan: NDB-027 Rev G.0 26,460.2 25,572.2 1,217.2 261.7 1.594 CCB-28 - NDBi-028 - Plan NDBi-028 Rev A.0 325.0 325.2 119.3 109.5 21.460 ESB-28 - NDBi-028 - Plan NDBi-028 Rev A.0 350.0 350.2 119.3 109.4 21.241 SFB-28 - NDBi-028 - Plan NDBi-028 Rev A.0 750.0 753.3 146.5 133.7 18.284 CCB-29 - NDB-029 - NDB-29 Slot Saver 325.0 325.2 99.2 89.7 18.167 ESB-29 - NDB-029 - NDB-29 Slot Saver 350.0 350.2 99.2 89.6 18.038 SFB-29 - NDB-029 - NDB-29 Slot Saver 700.0 698.7 117.9 106.4 16.751 CCB-30 - NDBi-030 - NDBi-030 47.0 46.4 80.1 71.0 16.721 ESB-30 - NDBi-030 - NDBi-030 225.0 224.2 80.2 71.0 15.358 SFB-30 - NDBi-030 - NDBi-030 10,275.0 10,351.4 1,424.9 1,059.7 4.903 CCB-31 - NDB-031 - NDB-031 483.2 485.7 58.0 47.8 9.501 ESB-31 - NDB-031 - NDB-031 500.0 502.6 58.0 47.7 9.358 SFB-31 - NDB-031 - NDB-031 575.0 577.7 59.7 48.9 9.086 CCB-31 - NDB-031 - Plan: NDB-031 Rev E.1 325.0 325.0 60.3 50.7 10.814 ESB-31 - NDB-031 - Plan: NDB-031 Rev E.1 450.0 451.4 60.4 50.4 10.183 SFB-31 - NDB-031 - Plan: NDB-031 Rev E.1 575.0 577.2 62.8 52.1 9.631 CCB-32 - NDB-032 - NDB-032 47.0 47.0 40.2 31.1 8.152 ESB-32 - NDB-032 - NDB-032 325.0 324.9 40.4 30.7 6.979 SFB-32 - NDB-032 - NDB-032 450.0 449.7 42.4 32.2 6.817 CCB-33 - NDB-033 - Plan: NDB-033 Rev A.0 325.0 325.2 19.2 9.5 3.145 ESB-33 - NDB-033 - Plan: NDB-033 Rev A.0 350.0 350.2 19.2 9.5 3.124 SFB-33 - NDB-033 - Plan: NDB-033 Rev A.0 375.0 375.2 19.3 9.5 3.117 CC, ESB-35 - NDB-035 - NDB-035 Slot Saver 581.7 581.5 17.1 6.7 2.461 SFB-35 - NDB-035 - NDB-035 Slot Saver 600.0 599.7 17.2 6.7 2.460 CCB-36 - NDBi-036 - NDBi-036 47.0 47.3 39.9 30.8 8.048 ESB-36 - NDBi-036 - NDBi-036 125.0 125.2 40.0 30.8 7.858 SFB-36 - NDBi-036 - NDBi-036 500.0 498.0 44.3 34.1 7.183 CCB-36 - NDBi-036 - Plan: NDBi-036 Rev E.0 348.0 348.0 39.9 30.3 6.970 ESB-36 - NDBi-036 - Plan: NDBi-036 Rev E.0 425.0 424.1 40.0 30.1 6.747 SFB-36 - NDBi-036 - Plan: NDBi-036 Rev E.0 500.0 498.0 40.8 30.5 6.568 CCB-37 - NDB-037 - NDB-037 1,355.8 1,345.0 26.9 12.9 2.760 ESB-37 - NDB-037 - NDB-037 1,375.0 1,364.1 26.9 12.7 2.721 SFB-37 - NDB-037 - NDB-037 1,400.0 1,388.9 27.3 12.8 2.699 CC, ESB-38 - NDBi-038 - Plan: NDBi-038 Rev A.0 561.0 558.7 77.9 67.4 12.545 SFB-38 - NDBi-038 - Plan: NDBi-038 Rev A.0 575.0 571.9 78.0 67.4 12.491 CC, ESB-39 - NDB-039 - Plan: NDB-039 Rev A.0 1,001.1 983.2 83.5 69.6 9.288 SFB-39 - NDB-039 - Plan: NDB-039 Rev A.0 24,275.0 24,993.2 2,387.1 1,681.1 4.235 CCB-40 - NDB-040 - Plan: NDB-040 Rev D.1 346.8 346.8 120.0 110.4 21.827 ESB-40 - NDB-040 - Plan: NDB-040 Rev D.1 375.0 373.9 120.0 110.3 21.632 SFB-40 - NDB-040 - Plan: NDB-040 Rev D.1 675.0 658.1 128.6 117.7 19.614 CC, ESB-41 - NDBi-041 - Plan: NDBi-041 Rev A.0 916.3 894.3 125.1 112.3 15.512 SFB-41 - NDBi-041 - Plan: NDBi-041 Rev A.0 10,075.0 9,390.5 2,838.5 2,438.1 8.910 CC, ESB-42 - NDB-042 - NDB-042 Slot Saver 985.7 976.1 129.9 117.9 17.393 SFB-42 - NDB-042 - NDB-042 Slot Saver 1,000.0 989.7 130.0 117.9 17.329 CC, ESB-43 - NDBi-043 - NDBi-043 785.3 773.5 161.4 149.8 22.808 SFB-43 - NDBi-043 - NDBi-043 9,050.0 10,947.0 1,110.2 1,003.5 13.300 CC, ESB-43 - NDBi-043A - NDBi-043A 785.3 773.5 161.4 149.8 22.808 SFB-43 - NDBi-043A - NDBi-043A 11,425.0 13,201.7 1,813.7 1,491.6 7.079 CCB-44 - NDBi-044 - NDBi-044 1,260.9 1,226.2 156.8 143.9 19.256 Caution - Monitor Closely,B-44 - NDBi-044 - NDBi-044 16,450.0 17,839.0 272.8 14.1 1.321 Caution - Monitor Closely,B-44 - NDBi-044 - NDBi-044 16,475.0 17,839.0 287.0 12.0 1.307 CCB-45 - NDB-045 - Plan: NDB-045 Rev A.0 672.1 658.1 213.5 201.9 30.589 ESB-45 - NDB-045 - Plan: NDB-045 Rev A.0 675.0 660.6 213.5 201.9 30.522 SFB-45 - NDB-045 - Plan: NDB-045 Rev A.0 850.0 812.2 222.0 209.5 28.810 CCB-46 - NDBi-046 - NDBi-046 47.0 46.8 239.8 230.7 51.211 ESB-46 - NDBi-046 - NDBi-046 300.0 298.8 240.3 230.7 44.825 SFB-46 - NDBi-046 - NDBi-046 3,025.0 2,587.1 772.2 715.1 17.752 17/09/2025 14:59:21 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-34 - Slot B-34Local 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-34Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-034 Database:EDM Offset DatumReference Design:Plan: NDBi-034 Rev M.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 CCB-46 - NDBi-046 L1 - NDBi-046 L1 47.0 46.8 239.8 230.7 51.211 ESB-46 - NDBi-046 L1 - NDBi-046 L1 300.0 298.8 240.3 230.7 44.825 SFB-46 - NDBi-046 L1 - NDBi-046 L1 3,025.0 2,587.1 772.2 715.1 17.752 CC, ESB-47 - NDB-047 - NDB-047 Slot Saver 734.7 717.7 252.5 241.2 37.437 SFB-47 - NDB-047 - NDB-047 Slot Saver 900.0 858.8 259.5 247.7 35.838 CCB-48 - NDB-048 - NDB-048 489.5 479.0 279.7 269.5 47.412 ESB-48 - NDB-048 - NDB-048 500.0 488.3 279.7 269.5 47.072 SFB-48 - NDB-048 - NDB-048 3,000.0 2,529.4 868.9 819.3 23.193 Wildcat CC, ES, SFFiord 2 - Fiord 2 - Fiord 2 26,460.2 3,436.6 1,829.9 1,491.6 6.799 SFFiord 3 - Fiord 3 - Fiord 3 20,850.0 4,122.6 898.8 449.2 2.506 ESFiord 3 - Fiord 3 - Fiord 3 20,925.0 4,122.7 886.5 446.4 2.526 CCFiord 3 - Fiord 3 - Fiord 3 21,033.2 4,122.8 879.9 458.9 2.621 Stop Drilling, ES, SFFiord 3 - Fiord 3A - Fiord 3A 19,550.0 4,859.2 72.6 -271.9 0.259 Stop Drilling, CCFiord 3 - Fiord 3A - Fiord 3A 19,555.7 4,855.1 72.5 -270.8 0.259 17/09/2025 14:59:21 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-34 - Slot B-34Local 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-34Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-034 Database:EDM Offset DatumReference Design:Plan: NDBi-034 Rev M.0 Offset TVD Reference: 0 700 1400 2100 2800 0 4500 9000 13500 18000 22500 27000 Measured Depth Ladder Plot Fiord 2, Fiord 2, Fiord 2 V0 Fiord 3, Fiord 3, Fiord 3 V0 Fiord 3, Fiord 3A, Fiord 3A V0 B-24, NDB-024, NDB-024 V0 B-24, NDB-024PB1, NDB-024PB1 V0 B-25, NDB-025, NDB-025 V0 B-27, NDB-027, NDB-027 V0 B-27, NDB-027 PB1, NDB-027 PB1 V0 B-30, NDBi-030, NDBi-030 V0 B-31, NDB-031, NDB-031 V0 B-32, NDB-032, NDB-032 V0 B-36, NDBi-036, NDBi-036 V0 B-37, NDB-037, NDB-037 V0 B-43, NDBi-043, NDBi-043 V0 B-43, NDBi-043A, NDBi-043A V0 B-44, NDBi-044, NDBi-044 V0 B-46, NDBi-046, NDBi-046 V0 B-46, NDBi-046 L1, NDBi-046 L1 V0 B-48, NDB-048, NDB-048 V0 Fiord 2, Fiord 2, Fiord 2 V0 Fiord 3, Fiord 3, Fiord 3 V0 Fiord 3, Fiord 3A, Fiord 3A V0 B-22, NDB-022, Plan NDB-022 Rev A.0 V0 B-23, NDB-023, NDB-023 Slot Saver V0 B-26, NDBi-026, Plan: NDBi-026 Rev A.0 V0 B-27, NDB-027, Plan: NDB-027 Rev F.0 V0 B-27, NDB-027 PB1, Plan: NDB-027 Rev G.0 V0 B-28, NDBi-028, Plan NDBi-028 Rev A.0 V0 B-29, NDB-029, NDB-29 Slot Saver V0 B-31, NDB-031, Plan: NDB-031 Rev E.1 V0 B-33, NDB-033, Plan: NDB-033 Rev A.0 V0 B-35, NDB-035, NDB-035 Slot Saver V0 B-36, NDBi-036, Plan: NDBi-036 Rev E.0 V0 B-38, NDBi-038, Plan: NDBi-038 Rev A.0 V0 B-39, NDB-039, Plan: NDB-039 Rev A.0 V0 B-40, NDB-040, Plan: NDB-040 Rev D.1 V0 B-41, NDBi-041, Plan: NDBi-041 Rev A.0 V0 B-42, NDB-042, NDB-042 Slot Saver V0 B-45, NDB-045, Plan: NDB-045 Rev A.0 V0 B-47, NDB-047, NDB-047 Slot Saver V0 L E G E N D Coordinates are relative to: B-34 - Slot B-34 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.60°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to Parker 272 @ 69.8usft 17/09/2025 14:59:21 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 5 Santos Ltd Anticollision Summary Report Well B-34 - Slot B-34Local 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-34Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDBi-034 Database:EDM Offset DatumReference Design:Plan: NDBi-034 Rev M.0 Offset TVD Reference: 0.00 3.00 6.00 9.00 0 4500 9000 13500 18000 22500 27000 Measured Depth Stop Drilling Caution - Monitor Closely Normal Operations Separation Factor Plot Fiord 2, Fiord 2, Fiord 2 V0 Fiord 3, Fiord 3, Fiord 3 V0 Fiord 3, Fiord 3A, Fiord 3A V0 B-24, NDB-024, NDB-024 V0 B-24, NDB-024PB1, NDB-024PB1 V0 B-25, NDB-025, NDB-025 V0 B-27, NDB-027, NDB-027 V0 B-27, NDB-027 PB1, NDB-027 PB1 V0 B-30, NDBi-030, NDBi-030 V0 B-31, NDB-031, NDB-031 V0 B-32, NDB-032, NDB-032 V0 B-36, NDBi-036, NDBi-036 V0 B-37, NDB-037, NDB-037 V0 B-43, NDBi-043, NDBi-043 V0 B-43, NDBi-043A, NDBi-043A V0 B-44, NDBi-044, NDBi-044 V0 B-46, NDBi-046, NDBi-046 V0 B-46, NDBi-046 L1, NDBi-046 L1 V0 B-48, NDB-048, NDB-048 V0 Fiord 2, Fiord 2, Fiord 2 V0 Fiord 3, Fiord 3, Fiord 3 V0 Fiord 3, Fiord 3A, Fiord 3A V0 B-22, NDB-022, Plan NDB-022 Rev A.0 V0 B-23, NDB-023, NDB-023 Slot Saver V0 B-26, NDBi-026, Plan: NDBi-026 Rev A.0 V0 B-27, NDB-027, Plan: NDB-027 Rev F.0 V0 B-27, NDB-027 PB1, Plan: NDB-027 Rev G.0 V0 B-28, NDBi-028, Plan NDBi-028 Rev A.0 V0 B-29, NDB-029, NDB-29 Slot Saver V0 B-31, NDB-031, Plan: NDB-031 Rev E.1 V0 B-33, NDB-033, Plan: NDB-033 Rev A.0 V0 B-35, NDB-035, NDB-035 Slot Saver V0 B-36, NDBi-036, Plan: NDBi-036 Rev E.0 V0 B-38, NDBi-038, Plan: NDBi-038 Rev A.0 V0 B-39, NDB-039, Plan: NDB-039 Rev A.0 V0 B-40, NDB-040, Plan: NDB-040 Rev D.1 V0 B-41, NDBi-041, Plan: NDBi-041 Rev A.0 V0 B-42, NDB-042, NDB-042 Slot Saver V0 B-45, NDB-045, Plan: NDB-045 Rev A.0 V0 B-47, NDB-047, NDB-047 Slot Saver V0 L E G E N D Coordinates are relative to: B-34 - Slot B-34 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.60°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to Parker 272 @ 69.8usft 17/09/2025 14:59:21 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 6 Northing (5000 usft/in)Easting (5000 usft/in)Northing (5000 usft/in)Easting (5000 usft/in)NDbi-034 Alt Toe up Rev 5.0Initiation Point of the Toe-UpFiord 3APlan NDB-022 Rev A.0NDB-023 Slot SaverNDB-024NDB-024PB1NDB-025Plan: NDBi-026 Rev A.0NDB-027NDB-027 PB1Plan: NDB-027 Rev G.0Plan NDBi-028 Rev A.0NDB-29 Slot SaverNDBi-030NDB-031NDB-032Plan: NDB-033 Rev A.0NDB-035 Slot SaverNDBi-036NDB-037Plan: NDBi-038 Rev A.0Plan: NDB-039 Rev A.0Plan: NDB-040 Rev D.1Plan: NDBi-041 Rev A.0NDB-042 Slot SaverNDBi-043NDBi-043ANDBi-044Plan: NDB-045 Rev A.0NDBi-046NDBi-046 L1NDB-047 Slot SaverNDB-048Fiord 2Fiord 3Plan: NDBi-034 Rev M.0NDANDBNPF15:13, September 17 2025 Plan: NDBi-034 Rev M.0AC FlipbookSURVEY PROGRAMDepth From Depth To Tool47.0 1000.0 SDI_URSA+SAG1000.0 3050.0 3_MWD+IFR2+MS+Sag3050.0 12000.0 3_MWD+IFR2+MS+Sag12000.0 16660.0 3_MWD+IFR2+MS+Sag16660.0 26460.2 3_MWD+IFR2+MS+SagCASING DETAILSTVD MD Name128.0 128.0 20" Conductor Casing2396.1 3050.013-3/8" Surface Casing3328.1 12000.09-5/8" Intermediate Liner4082.8 16660.0 7" Intermediate Liner4034.2 26460.0 4-1/2" x 6-1/8"50501001001501502002002502503003000901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [100 usft/in]4750751001251501752002252502753003253503733974204444674915145385615876086316546787007247477707948178408638869099339569791002102710521076110111261150117411961219124212641287131013321355137714001423144514681491Plan NDB-022 Rev A.0475075100125150175200225250275300325350373397421444468491515538562587608631654677700723745768790813835857879900922944NDB-023 Slot Saver4750751001251501752002252502753003253503743984214454694935165405645886116346586817057287527758008228468698939169409649871012103610611086111111361160118412071230125412771300132413471370139414171440146414871511153415571581160416281651167416981721174517681792NDB-0244750751001251501752002252502753003253503743984214454694935165405645886116346586817057287527758008228468698939169409649871012103610611086111111361160118412071230125412771300132413471370139414171440146414871511153415571581160416281651167416981721174517681792NDB-024PB1475075100125150175200225250275300325350374398422445469493517540564587610633655678700723745767789810832853874900916936956977100010191041106410871109113111541174NDB-025475075100125150175200225250275300325350374398422446470494518542566590613637661685708732756780803827851875900922946970993101810431068109311171142116711901213123712601284130713311354137814001425144814721495151915421566158916131637166016841708173117551779180218261850187418971921194519691993201620402064Plan: NDBi-026 Rev A.0475075100125150175200225250275300325350374398422446471495519543567591615639663687711735759783807831855879903927951975100010231048107310981123114711721195121912431266129013131337136113841408143114551479150015261549157315961620164416671691171417381761178518081831185518781900192519491972199520192042206520892112213621592182220622292252227623002323234623702393241724402464248725112535255825822605262926532676270027242747NDB-027475075100125150175200225250275300325350374398422446471495519543567591615639663687711735759783807831855879903927951975100010241049107410981123114811721196122012431267129013141337136113841408143114551478150015251549157215961619164316661689171317361760178318071830185318771900192419471970199420172041206420872111213421582181220522282251227523002322234523692392241524392462248625092533255625802603262726502674270027212745Plan: NDB-027 Rev F.0475075100125150175200225250275300325350374398422446471495519543567591615639663687711735759783807831855879903927951975100010231048107310981123114711721195121912431266129013131337136113841408143114551479150015261549157315961620164416671691171417381761178518081831185518781900192519491972199520192042206520892112213621592182220622292252227623002323234623702393241724402464248725112535255825822605262926532676270027242747NDB-027 PB1475075100125150175200225250275300325350374398422446471495519543567591615639663687711735759783807831855879903927951975100010231048107310981123114711721195121912431266129013131337136113841408143114551479150015261549157315961620164416671691171417381761178518081831185518781900192519491972199520192042206520892112213621592182220622292252227623002323234623702393241724402464248725112535255825822605262926532676270027242747Plan: NDB-027 Rev G.070751001251501752002252502753003253503743984224464714955185425665896136366596817047277497717938158378588799009219429629821003102510471069109111131134115611751194121312311249Plan NDBi-028 Rev A.0475075100125150175200225250275300325350374398423447471496520544568592616640664688711735758781804827850873896918941963NDB-29 Slot Saver475176101126151176201226251276301326351375400424448473497522546571595619644668692717741765789813837862886910934958981100610301055108011051129115411781200122512491272129513191342136613891412143614591483150615291552157616001622164616691692171517391762178518081831185418771900192419471970199320162039206220852109213221552178220022242247227022932316233923612384240724302453247625002522254525672590261326362658268127002727274927722794281728402865289029152939296129843006302930523074310031193142316531883210323332563279NDBi-0304750751001251501752002252502753003253503753994244484734975215465705946186416656887127357587818038268488708929139359569771000102010431065108811111133115611771197121712361256127512941313NDB-03147507510012515017520022525027530032535037539942444947449852354757259662164567069471874276679081483886288690993395798010041028105310771102112611511175119812211244126712901313133613591382140414271450147315001519154215651588161116331656167917001725174817711794181718391862188519081931195419772000202420472070209321162139216321862209223222562279230023252349237223952418244124642487251025322555257826002623264526672689271127332754277628002818284028642887291129322955297529953015303530543073NDB-032707510012515017520022525027530032535037540042444947449952354857259662064466869171573876178480783085287589791994196298410051028105110741096111911411163118412001224124412641283130013221341Plan: NDB-033 Rev A.0475075100125150175200225250275300325350375400425450475500525550575600625650674699723747772796820843867891914937960983NDB-035 Slot Saver475075100125150175200225250275300325350375400425451476501526551576601626651675700724748772796820843866889912934956978100010221044106710891112113511571179120012201241126212821300132213421362NDBi-03647507510012515017520022525027530032535037640142745247850352855457960563065668170773275878380983485988591093596198610111036106110861111113611611186121112361261128613111336136113861410143514601485150915341559158316081633165716821706173117551780180418281853187719011926195019741998202220472071209521192143216721902214223822622286231023332357238124052428245224762500252325472571259426182642266526892712273627602783280728302855288029052930295429773000302430483071309531183142316531893212323632593283330633293353337634003423344634703494351935443568359336183642366736913716374137653790381438393863388839123937396239864011403540604084NDB-0374750751001251501752002252502753003253503754014264524775025275525776026276516767007247487727968198438668899129349579791001102410471070109311151138116011821203122412451266128713071328Plan: NDBi-038 Rev A.04750751001251501752002252502753003253503764014274534785045305555816076326586847107357617878138388648909169419679931018104310681093111811431168119412201246127112971323134913751401142714531479150515311557158316101636166216881714174017661792181918451871189719231950197620022028205520812107213321602186221222382265229123172344237023962423244924752501252825542580260726332659268627122738276427912817284328672892291629412968299430203047307331003126315231793205Plan: NDB-039 Rev A.04750751001251501752002252502753003253503764024274534795045305555816066316576827067317557808048278518748979209439659871009103110531075109811201142116411851207122812481269Plan: NDB-040 Rev D.1475075100125150175200225250275300325350376402428454480506532557583609635662688714740766792818844870896922948974100010251050107511001125115011751201122812541280130613321358138414111437146314891515154115671593162016461672169817241750177618021828185418801906193219581984201020362062208721132139216521912216224222682294231923452371239624222447Plan: NDBi-041 Rev A.04750751001251501752002252502753003253503764024284544805065325585846106366616877137387647898148398638889129379619851008NDB-042 Slot Saver47507510012515017520022525027530032535137740342945548150853456058561163766368871373876278781183585988290592895197499710191042106510881112113511581181120312261248127012921314133513571378NDBi-04347507510012515017520022525027530032535137740342945548150853456058561163766368871373876278781183585988290592895197499710191042106510881112113511581181120312261248127012921314133513571378NDBi-043A4750751001251501752002252502753003253503774034304564825095355615886146416686947217477748008278538799059329589841009103410581083110811321157118312081234126012851311133613621387141214371462148715121537156215861611163516601684170917331757178118051829185218761900192319471970199420172040206420872110213421572180220322262249227122942317159491597516001160271605316078161041612916155161801620516230162551628016294NDBi-044475075100125150175200225250275300325350376403429456482508535561586612638664689715740765790815840864888912936960984100710301053107610991122114511681191121412371259Plan: NDB-045 Rev A.04750751001251501752002252502753003253503774044304574845105375645906176446716987257527798068338608879149419679941020104510701094111911441170119712241251127913051332135913861413143914661492151815441570159716221648167417001725175117761802NDBi-0464750751001251501752002252502753003253503774044304574845105375645906176446716987257527798068338608879149419679941020104510701094111911441170119712241251127913051332135913861413143914661492151815441570159716221648167417001725175117761802NDBi-046 L147507510012515017520022525027530032535037740343045648350953556158761464066569171774276879381884386889391794296699110151038106210861093NDB-047 Slot Saver4750751001251501752002252502753003253513784044314584855125395665936206476747027297567838108378648919189459729991024104910731098112311481174120112291256128313091336136313891415144114671493151915451571NDB-0481985419837198221980619790197741975819742197261971019693196771966119644196281961119594195771955919542195241950719489194711945419436194181940119383193651934819330193121929519277192601924219224Fiord 3A47 500500 10001000 15001500 20002000 25002500 30003000 50005000 60006000 70007000 80008000 90009000 1000010000 1200012000 1400014000 1600016000 1800018000 2000020000 25000From Colour To MD47.0 To 26460.2MD Azi TFace47.0 0.00 0.00347.0 0.00 0.00587.0 308.00 308.001000.3 308.00 0.001160.3 308.00 0.002832.0 300.39 -9.232932.0 300.39 0.003464.4 299.47 -3.3215065.1 299.47 0.0016454.2 338.11 121.5717075.9 338.11 0.0019458.4 338.11 0.0019840.1 330.48 -88.2625847.1 330.48 0.0026460.2 330.61 0.48 0 30 60 0 450 900 1350 1800 2250 Partial Measured Depth Equivalent Magnetic Distance Plan: NDBi-034 Rev M.0 Ladder View 0 150 300 0 4000 8000 12000 16000 20000 24000 Measured Depth Equivalent Magnetic Distance SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 47.0 1000.0 Plan: NDBi-034 Rev M.0 (NDBi-034)SDI_URSA+SAG 1000.0 3050.0 Plan: NDBi-034 Rev M.0 (NDBi-034)3_MWD+IFR2+MS+Sag 3050.0 12000.0 Plan: NDBi-034 Rev M.0 (NDBi-034)3_MWD+IFR2+MS+Sag 12000.0 16660.0 Plan: NDBi-034 Rev M.0 (NDBi-034)3_MWD+IFR2+MS+Sag 16660.0 26460.2 Plan: NDBi-034 Rev M.0 (NDBi-034)3_MWD+IFR2+MS+Sag 15:40, September 17 2025 CASING DETAILS TVD MD Name 128.0 128.020" Conductor Casing 2396.1 3050.013-3/8" Surface Casing 3328.1 12000.09-5/8" Intermediate Liner 4082.8 16660.0 7" Intermediate Liner 4034.2 26460.0 4-1/2" x 6-1/8" 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 and 8-1/2 Intermediate Hole Sections Hazard Mitigations Lost Returns Optimal drillpipe sizing. MPD to be used to manage ECD loads (8- 1/2 hole only). Monitor ECD with MWD tools. Pump LCM as required, slow pump rates and RPM, reduce ROP or trip speed when necessary. ECD modelling for optimized 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. Hole Cleaning in 83° Sail 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. 6-1/8 Production Hole Section Hazard Mitigations Lost Returns Optimal drillpipe sizing. MPD to be used to control ECD loading. Monitor ECD with MWD tools. Pump LCM as required, slow pump rates and RPM, reduce ROP or trip speed when necessary. Well Control MPD utilized with 7.5-8.0ppg MW to provide adequate dynamic and static overbalance. Normal BOP well control procedures. 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 / back- pressure to hold back formations. Wellbore Instability Maintain adequate mud weight / back-pressure for wellbore stability. Monitor cuttings returns, LWD logs, and drilling parameters for signs of washout. MPD to minimize pressure cycles on formation. Challenging liner run The production liner run requires relatively low OH friction factor to run to TD (hole cleaning and lubricants). Ability to rotate while RIH to overcome drag. * Note that no H2S has been encountered on nearby offset wells, and 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 9. 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: 385 bbls, 2164 cuft, 854 sks ArcticCem, Yield: 2.53 cuft/sk Tail 15.3ppg Tail: 68 bbls, 382 cuft, 308 sks HalCem Type I/II 1.24 cuft/sk Temp BHST 61° F (2.25°/100 TVD below PermaFrost) Verification Method Cement returns to surface Notes Job will be mixed on the fly NDBi-034 13-3/8in Surface Casing Cement Job Well Details Casing Stick Up on Rig Floor -4 ft MD 16.000 " Float Collar Depth 2970 ft MD 13.375 " Casing Shoe Depth 3050 ft MD 12.415 " TD Hole Depth 3050 ft MD 19.250 " Base Permafrost 1433 ft MD Previous Casing Shoe 128 ft MD Top of Previous Casing/Surface 46 ft MD Tail Cement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 13-3/8" Shoe Track 2970 3050 80 12.415 0.1497 12.0 0% 0 12.0 16" Open Hole x 13-3/8" Casing below base Permafrost 2550 3050 500 16.000 13.375 0.0749 37.5 50% 18.7 56.2 68.2 Lead Cement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 16" Open Hole x 13-3/8" Casing below base Permafrost 1433 2550 1117 16.000 13.375 0.0749 83.7 50% 41.8 125.5 16" Open Hole x 13-3/8" Casing above base Permafrost 128 1433 1305 16.000 13.375 0.0749 97.8 150% 146.6 244.4 Conductor x 13-3/8" Cased Hole 46 128 82 19.250 13.375 0.1862 15.3 0% 0.0 15.3 385.2 Displacement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 13-3/8 68# L-80 BTC/TXP-BTC Surface Casing to Float Colla -4 2970 2974 12.415 0.1497 445.3 445.3 445.3 Previous Casing ID Casing ID Casing OD Hole Size Verified cement calcs. -bjm Intermediate #1 Liner Cement Casing Size 9-5/8 47# L-80 Hydril 563 Intermediate Liner #1 Basis Tail Open hole volume + excess + 85 ft shoe track Tail TOC Stage 1: 1000 MD above the shoe Stage 2: Top of the 9-5/8 Liner Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Tail Stage 1: 30% Open Hole Excess 15.3ppg Tail: 79 bbls, 442cuft, 357sks VersaCem Type I/II 1.24 cuft/sk Stage 2: 100% Open Hole Excess 15.3ppg Tail: 413 bbls, 2318cuft, 1869sks VersaCem Type I/II 1.24 cuft/sk Temp Stage 1 - BHST 80° 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 - 1 st Stage Cement Job will not be logged, assuming job parameters are as expected (no losses, good lift pressures, FIT / LOT results). - 2 nd 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: - 1 st stage is only designed to provide adequate cement integrity around the shoe (i.e. Nanushuk will be isolated with 7 shoe) - Stage tool allows for precise placement of base cement column at base Tuluvak hydrocarbon. - Bond log not required for 2 nd Stage per Regulation 20 AAC 25.030(d)(5) - 2 nd Stage bond evaluation does not affect 1st Stage bond evaluation and frac decision. - 2 nd 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. - Tuluvak isolation has been achieved on all historical Pikka development wells. - Seeking to simplify an already complicated operation, saving time/money. NDBi-034 9-5/8in Intermediate #1 Liner - Stage 1 Cement Job Well Details Stick Up on Rig Floor -4 ft MD 12.250 " HWDP Length 2176 ft MD Top of Liner 2900 ft MD 9.625 " DP Length 728 ft MD Cflex Depth 6675 ft MD 8.681 "HWDP Capacity 0.0155 bbl/ft Landing Collar Depth N/A ft MD 12.415 " DP Capacity 0.0241 bbl/ft Float Collar Depth 11915 ft MD Casing Shoe Depth 12000 ft MD TD Hole Depth 12000 ft MD Previous Casing Shoe 3050 ft MD Tail Cement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 9-5/8" Shoe Track 11915 12000 85 8.681 0.0732 6.2 0% 0 6.2 12-1/4" Open Hole x 9-5/8" Casing 11000 12000 1000 12.250 9.625 0.0558 55.8 30% 16.7 72.5 78.7 Lead Cement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 0.0 Displacement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 5-7/8" 23.4# S135 Delta576 DP -4 724 728 0.0241 17.5 17.5 5-7/8" x 4" 130ksi Delta576 HWDP 724 2900 2176 0.0155 33.7 33.7 Liner Running Tools 2900 2945 45 2.5 0.0061 0.3 0.3 9-5/8 47# L-80 Hydril 563 Casing to Float/Landing Collar 2945 11915 8970 8.681 0.0732 656.7 656.7 708.2 Hole Size Casing OD Casing ID Previous Casing ID NDBi-034 9-5/8in Intermediate #1 Liner - Stage 2 Cement Job Well Details Stick Up on Rig Floor -4 ft MD 12.250 " HWDP Length 2176 ft MD Top of Liner 2900 ft MD 9.625 " DP Length 728 ft MD Cflex Depth 6675 ft MD 8.681 "HWDP Capacity 0.0155 bbl/ft Landing Collar Depth N/A ft MD 12.415 " DP Capacity 0.0241 bbl/ft Float Collar Depth 11915 ft MD Casing Shoe Depth 12000 ft MD TD Hole Depth 12000 ft MD Previous Casing Shoe 3050 ft MD Tail Cement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 12-1/4" Open Hole x 9-5/8" Casing 3050 6675 3625 12.250 9.625 0.0558 202.2 100% 202.2 404.4 13-3/8" Cased Hole x 9-5/8" Casing 2900 3050 150 12.415 9.625 0.0597 9.0 0% 0.0 9.0 413.4 Lead Cement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 0.0 Displacement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 5-7/8" 23.4# S135 Delta576 DP -4 724 728 0.0241 17.5 17.5 5-7/8" x 4" 130ksi Delta576 HWDP 724 2900 2176 0.0155 33.7 33.7 5-7/8" 23.4# S135 Delta576 DP 2900 6675 3775 0.0241 91.0 91.0 142.3 Hole Size Casing OD Casing ID Previous Casing ID Verified cement calcs. -bjm Intermediate #2 Liner Cement Casing Size 7 26# L-80 Hydril 563 Intermediate Liner #2 Basis Lead No Lead Planned Lead TOC No Lead Planned Tail Open hole volume + 30% excess + 120 ft shoe track Tail TOC 200 TVD above the top Nanushuk Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Lead No Lead Planned Tail 15.3ppg Tail: 122 bbls, 685cuft, 552sks VersaCem Type I/II 1.24 cuft/sk Temp BHST 99° 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 cement job. Justification: - Future hydraulic fracture operations will only be done in the Nanushuk formation. Log verification of the cement job will verify proper isolation has been achieved for frac operations. NDBi-034 7in Intermediate #2 Liner Cement Job Well Details Stick Up on Rig Floor -4 ft MD 9.875 " HWDP Length 1000 ft MD Top of Liner 11850 ft MD 7.000 " DP Length 10854 ft MD Landing Collar Depth 16540 ft MD 6.276 "HWDP Capacity 0.0087 bbl/ft Float Collar Depth n/a ft MD 8.681 " DP Capacity 0.0177 bbl/ft Casing Shoe Depth 16660 ft MD TD Hole Depth 16660 ft MD Previous Casing Shoe 12000 ft MD Tail Cement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 7" Shoe Track 16540 16660 120 6.276 0.0383 4.6 0% 0 4.6 9-7/8" Open Hole x 7" Casing 14750 16660 1910 9.875 7.000 0.0471 90.0 30% 27.0 117.0 121.6 Lead Cement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 0.0 Displacement Calculations Description Top Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excess ft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl 5" 19.5# S135 Delta544 DP -4 10850 10854 0.0177 192.1 192.1 5" x 3" Delta544 HWDP 10850 11850 1000 0.0087 8.7 8.7 Liner Running Tools 11850 11895 45 2.5 0.0061 0.3 0.3 7 26# L-80 Hydril 563 Casing to Float/Landing Collar 11895 16540 4645 6.276 0.0383 177.7 177.7 378.8 Hole Size Casing OD Casing ID Previous Casing ID Verified cement calcs. -bjm Attachment 7: Prognosed Formation Tops NDBi-034 Prognosed Tops Formation MD (ft) TVD KB (ft) TVDss (ft) Pore Pressure (ppg) Upper Schrader Bluff 1059 1045 975 7.20 Permafrost Base Transition 1433 1394 1324 7.30 Middle Schrader Bluff 1845 1740 1670 7.60 MCU (Lower Schrader Bluff)2455 2147 2077 7.80 Tuluvak Shale 3229 2443 2374 7.90 Tuluvak Sand 3636 2498 2428 10.2 TS 790 6624 2794 2725 9.40 Seabee 12845 3412 3342 9.10 Nanushuk 15908 3808 3739 8.90 NT8 MFS 16073 3863 3793 8.90 NT7 MFS 16202 3909 3840 8.90 NT6 MFS 16315 3953 3883 8.90 NT5 MFS 16392 3984 3914 8.80 NT4 MFS 16513 4033 3963 8.80 NT3 MFS 16674 4086 4017 8.80 Nanushuk 3.2 (NT3)16688 4090 4020 8.80 Attachment 8: Well Schematic 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 x 9-7/8 Intermediate Hole #2 LWD Gamma Ray Resistivity 6-1/8 Production Hole LWD Gamma Ray Resistivity Density Neutron Deep Resistivity Sonic (7 Liner Cement Evaluation Only) Mudlogging No mudlogging is planned for NDBi-034 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: Injector Area of Review Wells within ¼ mile of proposed injection well. Distance Annulus integrity Area of Review Information Fjord 3 ~890P&Ad Vertical Exploration well with 9-5/8 Surface Casing set at 1805 MD. 8-1/2 hole drilled to TD at 7030 in the Nuiqsut Formation (directly under Kuparuk formation). The well was P&Ad after running open hole wireline logs. Plug and Abandon Cement Plug #1 -Open hole cement plug set from TD (7030 MD) to 6090 MD to isolate the Kuparuk and Nuiqsut hydrocarbon zones with 81 bbls (400sx) balanced cement plug. Cement Plug #2 - Spot 20 bbls high vis pill and place open hole cement plug from 2300 to 2650 MD to isolate the Tuluvak hydrocarbon zone with 33 bbls (170sx) of cement. - Tag cement plug #2 with 20K lbs weight using drillpipe. TOC at 2315 MD. Cement Plug #3 - Spot 10 bbls high vis pill and place open hole cement plug from 1700 to 2100 MD with 37 bbls (210sx) of cement as a kick off plug for Fjord 3A sidetrack. -Tag cement plug #3 with drillpipe at 1659 MD and 9- 5/8 casing pressure tested to 1500 psi. Fjord 3A ~126 P&Ad Deviated Exploration well kicking out of 9-5/8 Surface Casing set at 1805 MD from Fjord 3 wellbore. 8-1/2 hole drilled to TD at 9147 in the Nuiqsut Formation. The well was P&Ad after drilling to TD. Plug and Abandon Cement Plug #1 -Open hole cement plug set from TD (9147 MD) to 8430 MD with 54.5 bbls (275sx) balanced cement plug across Nuiqsut formation. Cement Plug #2 - Place balanced open hole cement plug on top of Cement Plug #1 from 8420 to 8010 MD with 49.7 bbls (242sx) of cement across Kuparuk formation. - Tag cement plug #2 with 20K lbs weight using drillpipe. TOC at 2315 MD. Cement Plug #3 - Spot 20 bbls high vis pill and place open hole cement plug from 2750 to 2290 MD with 54.3 bbls (265sx) of cement across Tuluvak hydrocarbon zone. -Tag cement plug #3 with drillpipe at 2391 MD with 15K lbs weight. Cement Plug #4 -Set cement retainer at 1730 MD with drillpipe and set down 15K lbs. Sting into cement retainer pump 28 bbls (138sx 15.8ppg) cement. Downsqueeze 20 bbls below retainer and lay 8 bbls on top. Estimated TOC 1619 MD. -Pressure test cement plug #4 and 9-5/8 casing to 500 psi. Cement Plug #5 -Set bridge plug at 300 MD with drillpipe and set down maximum available weight. Pump 16.7 bbls (115sx) Arctic Set I cement on top of bridge plug. Reverse out excess cement from 37 MD in preparation for final P&A casing cut. NDBi-044 470Pre-frac: Passing MIT TxIA to 4,200 psi on 1/30/24 Post-frac: Passing MIT TxIA to 2,900 psi on 8/11/25 9-5/8 x 13-3/8 Primary cement job - Pump 80 bbls 12.5 ppg tuned spacer, 131 bbls 13.0 ppg 400 sxs 1.84 cuft/sx EconoCem Type I-II lead cement, and 80 bbls of 15.3 ppg 1.24 cuft/sx Versacem Type I-II Tail. Planned TOC was ~8,350 MD. - No returns while displacing cement job. Wiper dart #2 was lodged in the liner running tool when it was recovered. The follow liner wiper plug was then found just below the 9-5/8 x 13-3/8 Liner. A cleanout run was required to push the follow liner wiper plug to bottom and the shoe track was drilled out. Dynamic losses were encountered while drilling the float equipment. - A cement retainer was run in the hole and set at 11,010 MD and a second cement job was pumped through the shoe - 15bbls 12.0 ppg tuned spacer and 95 bbls of 15.3 ppg 1.24 cuft/sx Versacem Type I-II Tail were circulated through the retainer, and 5 bbls were placed on top of the retainer. Cement Evaluation Results: - HES Cast tool was run in the hole on a welltec tractor. The 9-5/8 cement was logged with the below results. Only able to tractor down to 10,839 MD. -The Nanushuk is isolated with 307 of Fair cement across the lower interval, and 363 of poor cement. -1714 of poor-quality cement above the Nanushuk from the primary job. NDB-027 1300Pending Completion of NDB-027 operations 7 Intermediate 2 Primary cement job - Pump 160 bbls LVT and 80 bbls 12.5 ppg Tuned Spacer at 3bpm, release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II, pump total of 215 bbls at 3 bpm, release top pump down plug, chase with 20 bbls of water from Halliburton. Perform displacement with rig pumps, displace at 3 bpm. ICP 495 psi with losses, FCP 1068 psi. On plug bump pressured up to 1800 psi. Held 5 min, bled off checked floats. Floats held. CIP @ 03:24 hrs. - Total losses from cement exit shoe to cement in place: 61 bbls. Cement Evaluation Results: TOC log indicates a transition zone from 13,350 to 13,886 MD, with the TOC at 13,886 MD, and good cement bond below this depth down to the 7 shoe. This placed cement ~224 TVD above the top of the Nanushuk. Attachment 14: Managed Pressure Drilling Managed Pressure Drilling (MPD) will be implemented on NDBi-034 in both the Intermediate #2 and Production sections 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 x 9-7/8 Intermediate hole will be to drill with a reduced 9.5 - 11.0ppg mud weight and utilize MPD to trap back-pressure in order to manage ECD for losses as well as providing adequate pressures to maintain wellbore stability through the Seabee and Nanushuk formations. Weighted trip fluids will be utilized to maintain downhole pressures for the final trip out and running of the 7 liner without MPD. The plan in the 6-1/8 Production hole will be to drill with a reduced 7.5 8.0ppg mud weight with MPD utilized to trap back-pressure in order to maintain adequate overbalance for pore pressure and wellbore stability and manage ECD for losses 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. The production hole will remain statically and dynamically overbalanced at all times using MPD. See below for a schematic of the BOP/MPD stack with the choke flow diagram. Attachment 15: As Built Survey NDB Well 34 Conductor Final NDB-CISUV-000026 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. PIKKA NDBi-034 225-108 NANUSHUK OILPIKKA WELL PERMIT CHECKLISTCompanyOil Search (Alaska), LLCWell Name:PIKKA NDBi-034Initial Class/TypeSER / PENDGeoArea890Unit11580On/Off ShoreOnProgramSERWell bore segAnnular DisposalPTD#:2251080Field & Pool:PIKKA, NANUSHUK OIL - 600100NA1 Permit fee attachedYes ADL393020, ADL393019, ADL392991, ADL392970, ADL392968, ADL392984, ADL3914452 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 boundaryYes 500' reported in PTD.6 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 44, issued 21 August, 202414 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 job with gap in between cement stages. All hc zones to be covered in cement.21 CMT vol adequate to tie-in long string to surf csgYes Production liner is uncemented in the Nan3, typical of Pikka wells.22 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 granted27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 1481 psi, BOP rated to 5000 psi (BOP test to 3600 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 probableYes34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticiapted in this well.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.374 to 0.53 psi/ft (7.2 to 10.2 ppg EMW). Tuluvak over-pressure. MPD in lateral.36 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]ApprTCSDate10/27/2025ApprBJMDate11/4/2025ApprTCSDate10/24/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 11/5/2025