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225-066
LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION Baker Hughes has provided us with LithTrak Azimuthal Caliper data for all 22 previous wells. Details are provided on following pages with well name and API table as reference. 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: 11/18/2025 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: Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.19 08:30:05 -09'00' LETTER OF TRANSMITTAL Well API NDB-010 50103209200000 NDB-011 50103209160000 NDBi-014 50103208690000 NDBi-016 50103208920000 NDBi-018 50103208880000 NDB-024 50103208620000 NDB-025 50103208770000 NDB-027 50103209220000 NDBi-030 50103208730000 NDB-031 50103209120000 NDB-032 50103208600000 NDBi-036 50103209080000 NDB-037 50103208950000 NDBi-043 50103208590000 NDBi-044 50103208650000 NDBi-046 50103208830000 NDB-048 50103209020000 NDBi-049 50103208940000 NDBi-050 50103209040000 NDB-051 50103208800000 DW-02 50103208550000 PWD-02 50103208790000 جؐؐؐDW-02 Lithotrak Caliper data ؒ SANTOS_DW-02_BHP_8_5_2384_7459ft_RUN5.dlis ؒ SANTOS_DW-02_BHP_8_5_2384_7459ft_RUN5.las ؒ جؐؐؐNDB-010 Lithotrak Caliper data ؒ SANTOS_NDB-010_BHP_8_5_9620_19462ft_Run3.dlis ؒ SANTOS_NDB-010_BHP_8_5_9620_19462ft_Run3.las ؒ جؐؐؐNDB-011 Lithotrak Caliper data ؒ جؐؐؐ12.25 in ؒ ؒ SANTOS_NDB-011_BHP_12_25in_2755_12365ft_RUN2.dlis ؒ ؒ SANTOS_NDB-011_BHP_12_25in_2755_12365ft_RUN2.las ؒ ؒ ؒ ؤؐؐؐ8.5 in ؒ SANTOS_NDB-011_BHP_8_5in_2755_12365ft_RUN3.dlis 223-039 T41107 225-061 T41108 225-048 T41109 NDB-027 50103209220000 LETTER OF TRANSMITTAL ؒ SANTOS_NDB-011_BHP_8_5in_2755_12365ft_RUN3.las ؒ جؐؐؐNDB-024 Lithotrak Caliper data ؒ جؐؐؐRun 6 ؒ ؒ Santos_NDB-024_BHP_12_25_2443_6175ft_Run6.dlis ؒ ؒ Santos_NDB-024_BHP_12_25_2443_6175ft_Run6.las ؒ ؒ ؒ ؤؐؐؐRun 7 ؒ SANTOS_NDB-024_BHP_8_5_11466_17969ft_RUN7.dlis ؒ SANTOS_NDB-024_BHP_8_5_11466_17969ft_RUN7.las ؒ جؐؐؐNDB-025 Lithotrak Caliper data ؒ SANTOS_NDB-025_BHP_8_5_8437_13838ft_Run3.dlis ؒ SANTOS_NDB-025_BHP_8_5_8437_13838ft_Run3.las ؒ جؐؐؐNDB-027 Lithotrak Caliper data ؒ SANTOS_NDB-027_BHP_6_125in_17280_12862ft_RUN6.dlis ؒ SANTOS_NDB-027_BHP_6_125in_17280_12862ft_RUN6.las ؒ جؐؐؐNDB-031 Lithotrak Caliper data ؒ SANTOS_NDB-031_BHP_6_125_18706_24362ft_Run4.dlis ؒ SANTOS_NDB-031_BHP_6_125_18706_24362ft_Run4.las ؒ جؐؐؐNDB-032 Lithotrak Caliper data ؒ جؐؐؐRun 3 ؒ ؒ SANTOS_NDB-032_BHP_12_25_2598_6224ft_Run3.las ؒ ؒ SANTOS_NDB_032_BHP_12_25_2598_6224ft_Run3.dlis ؒ ؒ ؒ ؤؐؐؐRun 4 ؒ SANTOS_NDB-032_BHP_8_5_6285_12280ft_Run4.dlis ؒ SANTOS_NDB-032_BHP_8_5_6285_12280ft_Run4.las ؒ جؐؐؐNDB-037 Lithotrak Caliper data ؒ SANTOS_NDB-037_BHP_8_25_10871_17793_RUN3.dlis ؒ SANTOS_NDB-037_BHP_8_25_10871_17793_RUN3.las ؒ جؐؐؐNDB-048 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDB-048_BHP_12_25_2252_12112ft_Run2.dlis ؒ ؒ SANTOS_NDB-048_BHP_12_25_2252_12112ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 3 223-076 T41110 224-006 T41111 225-066 T41112 225-028 T41113 223-060 T41114 224-124 T41115 224-143 T41116 NDB-027 Lithotrak Caliper data LETTER OF TRANSMITTAL ؒ SANTOS_NDB-048_BHP_8_5in_12168_21225ft_Run3.dlis ؒ SANTOS_NDB-048_BHP_8_5in_12168_21225ft_Run3.las ؒ جؐؐؐNDB-051 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDB-051_BHP_12_25_3258_11502_RUN2.dlis ؒ ؒ SANTOS_NDB-051_BHP_12_25_3258_11502_RUN2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDB-051_BHP_8_5_11565_17429.dlis ؒ SANTOS_NDB-051_BHP_8_5_11565_17429.las ؒ جؐؐؐNDBi-014 Lithotrak Caliper data ؒ SANTOS_NDBi-014_BHP_8_5_10448_15362_RUN3.dlis ؒ SANTOS_NDBi-014_BHP_8_5_10448_15362_RUN3.las ؒ جؐؐؐNDBi-016 Lithotrak Caliper data ؒ SANTOS_NDBi-016_BHP_8_5in_12860_18610ft_RUN4.las ؒ SANTOS_NDBi-016_BHP_8_5in_12860_18610ft_RUN4_1.dlis ؒ جؐؐؐNDBi-018 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDBi-018_BHP_12_25_2580_8193_RUN2.dlis ؒ ؒ SANTOS_NDBi-018_BHP_12_25_2580_8193_RUN2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDBi-018_BHP_8_5_8225_13060_RUN3.dlis ؒ SANTOS_NDBi-018_BHP_8_5_8225_13060_RUN3.las ؒ جؐؐؐNDBi-030 Lithotrak Caliper data ؒ SANTOS_NDBi-030_BHP_8_5in_11200_1743.6ft_Run6.dlis ؒ SANTOS_NDBi-030_BHP_8_5in_11200_1743.6ft_Run6.las ؒ جؐؐؐNDBi-036 Lithotrak Caliper data ؒ جؐؐؐRun 4 ؒ ؒ SANTOS_NDBi-036_BHP_8_5in_10990_16780ft_Run4.dlis ؒ ؒ SANTOS_NDBi-036_BHP_8_5in_10990_16780ft_Run4.las ؒ ؒ ؒ ؤؐؐؐRun 6 ؒ SANTOS_NDBi-036_BHP_6.125in_16813_22680ft_Run6.dlis ؒ SANTOS_NDBi-036_BHP_6.125in_16813_22680ft_Run6.las ؒ 224-013 T41117 223-105 T41118 224-105 T41119 224-085 T41120 223-120 T41121 225-012 T41122 LETTER OF TRANSMITTAL جؐؐؐNDBi-043 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ Santos_NDBi-043_BHP_12_25_2443_6175ft_Run2.dlis ؒ ؒ Santos_NDBi-043_BHP_12_25_2443_6175ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 4 ؒ Santos_NDBi-043_BHP_8_5_6240_13105ft_Run4.dlis ؒ Santos_NDBi-043_BHP_8_5_6240_13105ft_Run4.las ؒ جؐؐؐNDBi-044 Lithotrak Caliper data ؒ SANTOS_NDBi-044_BHP_8_5in_11114_17783ft_RUN5.dlis ؒ SANTOS_NDBi-044_BHP_8_5in_11114_17783ft_RUN5.las ؒ جؐؐؐNDBi-046 Lithotrak Caliper data ؒ SANTOS_NDBi-046_BHP_12_25_3758_12514_RUN2.dlis ؒ SANTOS_NDBi-046_BHP_12_25_3758_12514_RUN2.las ؒ جؐؐؐNDBi-049 Lithotrak Caliper data ؒ جؐؐؐRun 2 ؒ ؒ SANTOS_NDBi-049_BHP_12_25_2645_115572ft_Run2.dlis ؒ ؒ SANTOS_NDBi-049_BHP_12_25_2645_115572ft_Run2.las ؒ ؒ ؒ ؤؐؐؐRun 3 ؒ SANTOS_NDBi-049_BHP_8_5_11642_19250_RUN3.dlis ؒ SANTOS_NDBi-049_BHP_8_5_11642_19250_RUN3.las ؒ جؐؐؐNDBi-050 Lithotrak Caliper data ؒ SANTOS_NDBi-050_BHP_6_125_15145_22525ft_Run9.dlis ؒ SANTOS_NDBi-050_BHP_6_125_15145_22525ft_Run9.las ؒ ؤؐؐؐPWD-02 Lithotrak Caliper data SANTOS_PWD-02_BHP_8_5_6818_9461_Run_4_5_6.dlis SANTOS_PWD-02_BHP_8_5_6818_9461_Run_4_5_6.las 223-051 T41123 223-087 T41124 224-028 T41125 224-119 T41126 224-154 T41127 224-009 T41128 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 Cleanup 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?Pikka NDB-027 Yes No 9. Property Designation (Lease Number): 10. Field: Pikka Nanushuk Oil Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 26,914 4,095' 26,907' 4,095' N/A N/A Casing Collapse Conductor Surface 2260 Intermediate 4750 Tie-Back 4750 Intermediate 2 5410 Production 9210 Liner 9210 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Scott Leahy 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 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 11590 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, 393018, 392970 225-066 601 W 5th Avenue, Suite 600, Anchorage, AK 99501 50-103-20922-00-00 Oil Search Alaska, LLC Length Size Proposed Pools: 128' 128' P-110S TVD Burst 17,056' 11590 MD 6870 5020 6870 2,376' 3,401' 2,311' 3,997' 2,935' 11,995' 4-1/2" 128' 20"x34" 13-3/8" 9-5/8" 2,935' Tieback2,780' 9,215' 17,056' Perforation Depth MD (ft): 2,780' 17,056' 4-1/2" 5,443' 7"17,275' 4,065' 7240 11/8/2025 26,907'9,851' 4-1/2" 12.6ppf 4,095' See attached packer report m n P 2 6 5 6 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-648 By Grace Christianson at 11:01 am, Oct 20, 2025 DSR-10/30/25 , 392968 SFD 10-404 CDW 10/21/2025 Fracture Stimulate 11/8/2025 SFD 10/29/2025BJM 10/31/25JLC 10/31/2025 11/03/25 Page 1 of 1 Packer Set Depths - NDB-027 Wellbore Name Item Des Btm (ftKB) Btm (TVD) (ftKB) Sidetrack 1 ZXP Liner Top Hanger Packer W/HRD-E Profile 17,089.6 4,008.4 Sidetrack 1 HES Zoneguard OH Packer #20 17,425.5 4,100.0 Sidetrack 1 HES Zoneguard OH Packer #19 17,491.2 4,112.0 Sidetrack 1 HES Zoneguard OH Packer #18 17,910.4 4,141.6 Sidetrack 1 HES Zoneguard OH Packer #17 18,369.4 4,141.1 Sidetrack 1 HES Zoneguard OH Packer #16 18,871.8 4,139.1 Sidetrack 1 HES Zoneguard OH Packer #15 19,499.0 4,136.8 Sidetrack 1 HES Zoneguard OH Packer #14 20,126.6 4,134.5 Sidetrack 1 HES Zoneguard OH Packer #13 20,628.1 4,132.2 Sidetrack 1 HES Zoneguard OH Packer #12 21,131.2 4,128.2 Sidetrack 1 HES Zoneguard OH Packer #11 21,676.3 4,123.7 Sidetrack 1 HES Zoneguard OH Packer #10 22,259.5 4,119.7 Sidetrack 1 HES Zoneguard OH Packer #9 22,762.9 4,117.7 Sidetrack 1 HES Zoneguard OH Packer #8 23,308.5 4,115.6 Sidetrack 1 HES Zoneguard OH Packer #7 23,850.8 4,113.5 Sidetrack 1 HES Zoneguard OH Packer #6 24,393.0 4,110.6 Sidetrack 1 HES Zoneguard OH Packer #5 24,934.6 4,106.5 Sidetrack 1 HES Zoneguard OH Packer #4 25,476.5 4,102.3 Sidetrack 1 HES Zoneguard OH Packer #3 25,979.0 4,099.1 Sidetrack 1 HES Zoneguard OH Packer #2 26,438.4 4,097.5 Sidetrack 1 HES Zoneguard OH Packer #1 26,775.9 4,096.0 Page 1 of 20 NDB-027 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 NBD-027. At the NDB-027 location, the Permafrost interval extends down to approximately 1000-1400 ft and therefore, no shallow aquifer (typically found down to 400 ft depth) are located at the NDB-027 location. 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 971 feet (ft) total vertical depth subsea (TVDSS)/ 971 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: 971 to 2,379 ft TVDSS/1,408 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: 2,379 to 2,982 ft TVDSS/ 603 ft thick Hydrocarbon Zone: 2,724 to 2,982 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: 2,982 to 3,731ft TVDSS/ 749 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: 3,731 to 4,685 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: 4,685 to 5,584 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 1-18 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 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 26,665 4,097 214 260 40 7,719 8 2 26,205 4,098 231 315 40 7,728 8 3 25,744 4,100 344 452 40 7,495 8 4 25,201 4,105 353 469 40 7,358 8 5 24,659 4,109 355 499 40 7,784 10 6 24,118 4,112 355 499 40 7,619 10 7 23,575 4,115 354 498 40 7,488 10 8 23,032 4,117 350 489 40 7,320 10 9 22,486 4,119 350 467 40 7,145 10 10 21,944 4,122 350 487 40 7,014 10 11 21,399 4,126 349 486 40 6,846 10 12 20,855 4,131 352 492 40 6,672 10 13 20,312 4,134 224 448 40 6,587 10 14 19,768 4,136 210 416 40 6,692 11 15 19,223 4,138 190 356 40 6,589 11 16 18,678 4,140 215 427 40 6,660 12 17 18,137 4,141 241 388 40 6,480 12 18 17,634 4,130 218 412 40 6,316 12 7,784 Mechanical condition of wells transecting the confining zones NDBi-030, NDB- 037, Fiord 3, Fiord 3A, and Fiord 2 are within 1/2-mile radius of NDB-027. Please see Attachment B as reference. 11.Suspected fault or fracture that may transect the confining zones: There is one known fault within the ½ mile radius of NDB-027. The fault is described as: Fault SM_NDB_004 falls within the ½ mile radius of the B-27 well and is oriented obliquely to the wellbore orientation. The fault is associated with the Fiord fault system and is mapped to tip out around 2000 from the B-27 well. This fault has throw estimated to be around 25 at the NDB-022 intersection and throw increases to the north from there. 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 , 2025 Owners, Landowners, Surface Owners and Operators See Distribution List Colville River Area North Slope Basin, Alaska Re: Notice of Operations under 20 AAC 25.283 of Oil Search (Alaska), LLCs Sundry Application for a Fracture Stimulation for the Proposed NDB-0 Well Dear Owner, Landowner, Surface Owner and/or Operator, Oil Search (Alaska), LLC (OSA) is applying for a Sundry Application under 20 AAC 25.283 to perform a fracture stimulation of the proposed NDB-0 well. This Notice is being sent by certified mail to meet the notification requirements under 20 AAC 25.283(a)(1)(A) and 20 AAC 25.283(a)(1)(B). The complete application is available for review upon request. If you wish to review the application, please contact Tim Jones, Land Manager, at the following: Tim Jones Land Manager Oil Search (Alaska), LLC 601 W 5th Ave Anchorage, AK 99501 Direct: 907-375-4624 tim.jones3@santos.com OSA, through a search of the public record, has identified you as an Owner, Landowner, Surface Owner or Operator (as defined in AOGCC regulations) within ½ mile of the proposed NDB-0 well trajectory and fracture stimulation. Please contact Tim Jones should you require additional information. Sincerely, Jacob Owens Commercial Analyst Distribution List: Alaska Division of Oil and Gas Arctic Slope Regional Corp. Kuukpik Corp. Oil Search (Alaska), LLC Repsol E&P USA LLC ConocoPhillips Alaska, Inc. Sincerely, Jacob Owens 2/2 Contact Information: State of Alaska CERTIFIED MAIL Department of Natural Resources Alaska Division of Oil and Gas 550 W 7th Avenue, Suite 1100 Anchorage, AK 99501-3560 Arctic Slope Regional Corp. CERTIFIED MAIL Attn: David Knutson 3900 C Street, Suite 801 Anchorage, AK 99503-5963 Kuukpik Corp CERTIFIED MAIL 582 E. 36th Avenue Anchorage, AK 99503 Oil Search (Alaska), LLC CERTIFIED MAIL 601 W 5th Ave Anchorage, AK 99501 Repsol E&P USA LLC CERTIFIED MAIL 2455 Technology Forest Blvd. The Woodlands, TX 77381 ConocoPhillips Alaska, Inc. CERTIFIED MAIL Attn: Land Manager PO Box 100360 Anchorage AK 99510 ADL 392991 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.58% DNR - 58.42% ADL 392984 Surface Owners: Kuu OIL SEARCH - 51%, R 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 e Owners: State %, REPSOL - 49% SUBS.OWNERS: 0% DNR - 100% ADL 392970 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 40.29% DNR - 59.71% 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: Ku OIL SEARCH - 51%, R SUBS.OWNERS: ASRC - 31.69% DNR ADL 393016 Surface Owners: Kuu OIL SEARCH - 51%, R SUBS.OWNERS: ASRC - 33.17% DNR ADL 39 Surface Owne OIL SEARCH - 51% SUBS.OW ASRC - 28.11% D ADL 393007 Surface Owners: Ku OIL SEARCH - 51%, R SUBS.OWNERS: ASRC - 34.35% DNR ADL 391445 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 41.98% DNR - 58.02% ADL 391454 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 36.61% DNR - 63.39% ADL 391455 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 46.4% DNR - 53.6% ADL 393009 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 40.59% DNR - 59.41% ADL 393011 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 25.71% DNR - 74.29% ADL 393010 Surface Owners: Kuukpik OIL SEARCH - 51%, REPSOL - 49% SUBS.OWNERS: ASRC - 38.54% DNR - 61.46% C o noco AD L 372106OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD NDB-027 BOTTOM HOLE NDB-027 SURFACE LOCATION PRODUCTION INTERVAL 0.5-MILE BUFFER NDB-027 TRAJECTORY CPAI LEASES SECTIONS SANTOS LEASES DATE: 9/29/2025. By: JB 0 0.1 0.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-PE-M_NDB27_well_ownership Map Frame: AP-DRL-PE-M_NDB-027_well_ownership GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 0.2 0.4 Kilometers PIKKA DEVELOPMENT NDB-027 WELL AREA Attachment B ADL 392991 ADL 392984 ADL 392968 ADL 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 393011ADL 393010 Conoco ADL 372106 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-014 NDBi-016 NDBi-018 NDBi-030 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 PRODUCTION INTERVAL NDB-027 TRAJECTORY OTHER DRILLED NDB WELLS EXPLORATION WELLS NDB-027 BOTTOM HOLE BOTTOM HOLES WELL TRAJECTORIES BY OTHERS NDB-027 SURFACE LOCATION SECTIONS CPAI LEASES FAULT LINE DATE: 9/29/2025. By: JN 0 0.1 0.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDB27_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 0 0.2 0.4 Kilometers PIKKA DEVELOPMENT NDB-027 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 IntegrityNDBi-030 ACTIVE 9-5/8" 47ppf 9653 (Nanushuk) 3,796 (Nanushuk) 9950 3,831 log open hole liner for productionTOC 9,950' & packer @ 11,014'9-5/8 x 13-3/8 Primary cement jobPump 80 bbls 12.5 ppg tuned spacer, 206bbls 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail. Planned TOC was ~8,450 MD. Liner wiper plug system failure. When lower liner wiper plug landed on landing collar, plug bumped leaving all cement inside 9-5/8" liner. A cleanout run was required to drill out all cement and the landing collar was drilled out. A cement retainer was run in the hole and set at 11,160 MD and a second cement job was pumped through the shoe. Difficulty establishing good circulation due to 80 bbls of water based 12.5ppg spacer left against formation from initial cement job.78bbls 12.5 ppg tuned spacer and 205 bbls of 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail was circulated through the retainer, and 3 bbls were placed on top of the retainer. Lost 110 bbls after cement entered annulus. 9-5/8 2nd Stage Cement JobRIH and open up the Archer Cflex cement tool. Establish circulation and pump 80 bbls 12.5 ppg Mudflush Spacer, 78 bbls 13.5 ppg Tuned spacer 252 bbls 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail. No losses pumping cement and 26 bbls were lost while displacing. The LTP was set and 50 bbls of cement was circulated to surface while circulating with the Cflex running tool. 9-5/8 Cement Evaluation LogBaker SoundTrak CBL tool was used to log cement after drilling out cement retainer and float shoe. The 9-5/81st stage cement was logged showing the TOC of the primary job at 9,950' MD. Top of hydrocarbon bearing zone in the Nanushuk was in the NT7 at 10,240' MD.03/26/24, 9-5/8" casing pressure tested to 4150 psi for 30 minutesFiord 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. Fiord 3A: P&A'd - Cement plugs above and below the Nanush uk, which is covered by 10.6 ppg mud and should provide some barrier to cross- flow. Torok is wet. Monitor ing or remedia tion not possible . SFD NDB- 030: WAGI N - Nanu shuk isolati on provi ded by first stage of inter medi ate liner ceme nt job. CBL indica tes mostl y partia l to poor bond qualit y with a few areas of good bondi ng. SFD NDB- 037: Prod ucer - Nanu shuk is isolat ed by ceme nt displ aying consi stent, excell ent bond - qualit y liner ceme nt. SFD. Fiord 3: P&A'd - Cement plugs above and below the Nanushu k, which is covered by 10.5 ppg mud and should provide some barrier to cross- flow. Torok is wet. Monitori ng or remediat ion not possible. SFD Fiord 2: P&A'd - Cement plugs above and below the Nanush uk, which is covered by 11.2 ppg mud and should provide some barrier to cross- flow. Torok is wet. Monitor ing or remedia tion not possible . SFD 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 2,780 MD 13-3/8 Casing Shoe at 2,935 MD 9-5/8 Archer Cflex Mechanical Stage tool: 5,979 MD 9-5/8 Shoe at 11,995 MD 7 Intermediate 2 Liner 7 Liner Top at 11,832 MD Shoe at 17,275 MD Geology Top of Tuluvak Sand Top at 3,311 MD Top of Tuluvak TS 790 formation at 5,901 MD. Top of the Nanushuk picked at 15,992 MD. Cement Job Planning/Execution See attached cementing reports starting on the next page for a summary of the work performed. 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. Page 1 of 1 Cement - NDB-027 Intermediate #2 Casing Cement Page 1 of 1 Cement - NDB-027 Surface Casing Cement Page 1 of 2 Cement - NDB-027 Intermediate #1 Casing Cement Page 2 of 2 Cement - NDB-027 Intermediate #1 Casing Cement Attachment D Attachment E Attachment F Well NameNDB-02710/14/25 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 264.05050210021005050c Pump Check WF26 4042547517850199504254750475d DFITWF26 40250725 10500 30450 250 7250 725 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 401680 16800 0 40 76520Drop Stage 1 Ball/Collet FP 018343 43126 18060 0CSG-IV3 76830Stage 1 PADXL 2640 375418 41815750 175560 0 375 114340Slow for Seat XL 261850468 4682100 196560 0 50 119350Resume PadXL 2640 1469 46942 196980 0 1 119461Flat; Add Patina Tracer to PODXL 2640 125594 5945250 249485027 5027CSG-IV120 131472FlatXL 2640 140734 7345880 3082810801 15828CSG-IV129 144283FlatXL 2640 170904 9047140 3796818902 34730CSG-IV150 159294FlatXL 2640 1701074 10747140 4510824252 58982CSG-IV144 1737105FlatXL 2640 1701244 12447140 5224829214 88196CSG-IV139 1876116FlatXL 2640 1701414 14147140 5938833827 122023CSG-IV134 2010127FlatXL 2640 1401554 15545880 6526831400 153423CSG-IV107 2117138FlatXL 2640 1251679 16795250 7051830991 184414CSG-IV92 2209140Clear Surface LinesXL 2640 151694 1694630 711480 184414 15 2224150Spacer XL 2640151709 1709630 717780 184414 15 2239160Drop Stage 2 Ball/Collet FP 04031712 1712126 719040 184414 3 2242170Stage 2 PADXL 2640 3682080 208015456 873600 184414 368 2610180Slow for Seat XL 2618502130 21302100 894600 184414 50 2660190Resume PadXL 2640 322162 21621344 908040 184414 32 2692201FlatXL 2640 1652327 23276930 977346635 191049CSG-IV158 2850212FlatXL 2640 1802507 25077560 10529413887 204936CSG-IV165 3015223FlatXL 2640 1952702 27028190 11348421682 226617CSG-IV172 3187234FlatXL 2640 1952897 28978190 12167427819 254436CSG-IV166 3353245FlatXL 2640 1953092 30928190 12986433510 287946CSG-IV160 3513256FlatXL 2640 1953287 32878190 13805438802 326748CSG-IV154 3667267FlatXL 2640 1853472 34727770 14582441493 368241CSG-IV141 3808278FlatXL 2640 1703642 36427140 15296442148 410388CSG-IV125 3933280Clear Surface LinesXL 2640 153657 3657630 1535940 410388 15 3948290Spacer XL 2640153672 3672630 1542240 410388 15 3963300Drop Stage 3 Ball/Collet FP 04033675 3675126 1543500 410388 3 3966310Stage 3 PADXL 2640 3614036 403615162 1695120 410388 361 4327320Slow for Seat XL 2618504086 40862100 1716120 410388 50 4377HSD- ~60 minFLUID Neat WaterCOMMENTSHSD- 30 minEnsure Stage 1 ball/collet is loaded Prime and Pressure TestOpen well- Displace PT Well NameNDB-02710/14/25 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 Water330Resume PadXL 2640 394125 41251638 1732500 410388 39 4416341FlatXL 2640 1654290 42906930 1801806635 417024CSG-IV158 4574352FlatXL 2640 1804470 44707560 18774013887 430910CSG-IV165 4739363FlatXL 2640 1954665 46658190 19593021682 452592CSG-IV172 4911374FlatXL 2640 1954860 48608190 20412027819 480411CSG-IV166 5077385FlatXL 2640 1955055 50558190 21231033510 513921CSG-IV160 5237396FlatXL 2640 1955250 52508190 22050038802 552723CSG-IV154 5391407FlatXL 2640 1855435 54357770 22827041493 594216CSG-IV141 5532418FlatXL 2640 1705605 56057140 23541042148 636363CSG-IV125 5657420Clear Surface LinesXL 2640 155620 5620630 2360400 636363 15 5672430Spacer XL 2640155635 5635630 2366700 636363 15 5687440Drop Stage 4 Ball/Collet FP 04035638 5638126 2367960 636363 3 5690450Stage 4 PADXL 2640 3535991 599114826 2516220 636363 353 6043460Slow for Seat XL 2618506041 60412100 2537220 636363 50 6093470Resume PadXL 2640 476088 60881974 2556960 636363 47 6140481FlatXL 2640 1656253 62536930 2626266635 642998CSG-IV158 6298492FlatXL 2640 1806433 64337560 27018613887 656885CSG-IV165 6464503FlatXL 2640 1956628 66288190 27837621682 678567CSG-IV172 6636514FlatXL 2640 1956823 68238190 28656627819 706386CSG-IV166 6801525FlatXL 2640 1957018 70188190 29475633510 739896CSG-IV160 6961536FlatXL 2640 1957213 72138190 30294638802 778698CSG-IV154 7115547FlatXL 2640 1857398 73987770 31071641493 820190CSG-IV141 7256558FlatXL 2640 1707568 75687140 31785642148 862338CSG-IV125 7381560Clear Surface LinesXL 2640 157583 7583630 3184860 862338 15 7396570Spacer XL 2640157598 7598630 3191160 862338 15 7411580Drop Stage 5 Ball/Collet FP 04037601 7601126 3192420 862338 3 7414590Stage 5 PADXL 2640 3457946 794614490 3337320 862338 345 7759600Slow for Seat XL 2618507996 79962100 3358320 862338 50 7809610Resume PadXL 2640 17997 799742 3358740 862338 1 7810621ScourXL 2640 608057 80572520 3383942413 86475140/70-CL57 7868633ScourXL 2640 1208177 81775040 34343413348 87809940/70-CL106 7974640FlatXL 2640 508227 82272100 3455340 878099 50 8024651FlatXL 2640 2008427 84278400 3539348043 886142CSG-IV191 8215662FlatXL 2640 2258652 86529450 36338417358 903500CSG-IV207 8422674FlatXL 2640 2758927 892711550 37493439232 942732CSG-IV234 8655686FlatXL 2640 2609187 918710920 38585451736 994468CSG-IV205 8861698FlatXL 2640 2409427 942710080 39593459502 1053970CSG-IV177 90387010FlatXL 2640 2009627 96278400 40433458170 1112140CSG-IV138 9176710Clear Surface LinesXL 2640 159642 9642630 4049640 1112140 15 9191720Spacer XL 2640159657 9657630 4055940 1112140 15 9206730Drop Stage 6 Ball/Collet FP 04039660 9660126 4057200 1112140 3 9209740Stage 6 PADXL 2640 3379997 999714154 4198740 1112140 337 9546750Slow for Seat XL 26185010047 100472100 4219740 1112140 50 9596 Well NameNDB-02710/14/25 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 Water760Resume PadXL 2640 110048 1004842 4220160 1112140 1 9597771ScourXL 2640 6010108 101082520 4245362413 111455340/70-CL57 9655783ScourXL 2640 12010228 102285040 42957613348 112790240/70-CL106 9761790FlatXL 2640 5010278 102782100 4316760 1127902 50 9811801FlatXL 2640 20010478 104788400 4400768043 1135944CSG-IV191 10002812FlatXL 2640 22510703 107039450 44952617358 1153303CSG-IV207 10209824FlatXL 2640 27510978 1097811550 46107639232 1192534CSG-IV234 10442836FlatXL 2640 26011238 1123810920 47199651736 1244270CSG-IV205 10648848FlatXL 2640 24011478 1147810080 48207659502 1303773CSG-IV177 108258510FlatXL 2640 20011678 116788400 49047658170 1361943CSG-IV138 10963860Clear Surface LinesXL 2640 1511693 11693630 4911060 1361943 15 10978870Spacer XL 26401511708 11708630 4917360 1361943 15 10993880Drop Stage 7 Ball/Collet FP 040311711 11711126 4918620 1361943 3 10996890XL Flush (DFIT)XL 2640 32812039 1203913776 5056380 1361943 328 11324900Slow for seat (LG DFIT) WF 26185012089 120892100 5077380 1361943 50 1137491DFIT FlushWF 2640235 12324 123249870 548058235 11609923000 feet MD + Surface EqmtFP20 7012394 123942949 551007TOTALS13119 5510071361943 Well NameNDB-02710/14/25 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)aFPbWF3.5404016801680cWF 261.000168000dWF26 3.5360360 15120 16800 360 360e Pump CheckWF26 40100460 4200 21000 100 4600 460 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 5001680 226800 0 40 50020Stage 7 PADXL 2640 300340 80012600 352800 0CSG-IV300 80031ScourXL 2640 60400 8602520 378002413 241340/70-CL57 85743ScourXL 2640 120520 9805040 4284013348 1576140/70-CL106 96350FlatXL 2640 50570 10302100 449400 15761 50 101361FlatXL 2640 200770 12308400 533408043 23804CSG-IV191 120572FlatXL 2640 225995 14559450 6279017358 41163CSG-IV207 141284FlatXL 2640 2751270 173011550 7434039232 80394CSG-IV234 164596FlatXL 2640 2601530 199010920 8526051736 132130CSG-IV205 1850108FlatXL 2640 2401770 223010080 9534059502 191633CSG-IV177 20271110FlatXL 2640 2001970 24308400 10374058170 249802CSG-IV138 2166120Clear Surface LinesXL 2640 151985 2445630 1043700 249802 15 2181130Spacer XL 2640152000 2460630 1050000 249802 15 2196140Drop Stage 8 Ball/Collet FP 04032003 2463126 1051260 249802 3 2199150Stage 8 PADXL 2640 3202323 278313440 1185660 249802 320 2519160Slow for Seat XL 2618502373 28332100 1206660 249802 50 2569170Resume PadXL 2640 12374 283442 1207080 249802 1 2570181ScourXL 2640 402414 28741680 1223881609 25141140/70-CL38 2608193ScourXL 2640 802494 29543360 1257488899 26031040/70-CL71 2679200Resume PadXL 2640 502544 30042100 1278480 260310 50 2729211FlatXL 2640 2002744 32048400 1362488043 268353CSG-IV191 2920222FlatXL 2640 2252969 34299450 14569817358 285711CSG-IV207 3127234FlatXL 2640 2753244 370411550 15724839232 324943CSG-IV234 3361246FlatXL 2640 2603504 396410920 16816851736 376679CSG-IV205 3566258FlatXL 2640 2403744 420410080 17824859502 436181CSG-IV177 37432610FlatXL 2640 2003944 44048400 18664858170 494351CSG-IV138 3881270Clear Surface LinesXL 2640 153959 4419630 1872780 494351 15 3896280Spacer XL 2640153974 4434630 1879080 494351 15 3911290Drop Stage 9 Ball/Collet FP 04033977 4437126 1880340 494351 3 3914300Stage 9 PADXL 2640 3124289 474913104 2011380 494351 312 4226310Slow for Seat XL 2618504339 47992100 2032380 494351 50 4276320Resume PadXL 2640 14340 480042 2032800 494351 1 4277Stage to "Line out XL"Ensure Stage 8 ball/collet is loaded COMMENTSFLUID Neat WaterPrime and Pressure TestOpen well- Displace PTDrop BallPump Ball to Seat Well NameNDB-02710/14/25 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 Water331ScourXL 2640 404380 48401680 2049601609 49596040/70-CL38 4316343ScourXL 2640 804460 49203360 2083208899 50485940/70-CL71 4386350Resume PadXL 2640 504510 49702100 2104200 504859 50 4436361FlatXL 2640 2004710 51708400 2188208043 512901CSG-IV191 4628372FlatXL 2640 2254935 53959450 22827017358 530260CSG-IV207 4835384FlatXL 2640 2755210 567011550 23982039232 569492CSG-IV234 5068396FlatXL 2640 2605470 593010920 25074051736 621227CSG-IV205 5273408FlatXL 2640 2405710 617010080 26082059502 680730CSG-IV177 54504110FlatXL 2640 2005910 63708400 26922058170 738900CSG-IV138 5589420Clear Surface LinesXL 2640 155925 6385630 2698500 738900 15 5604430Spacer XL 2640155940 6400630 2704800 738900 15 5619440Drop Stage 10 Ball/Collet FP 04035943 6403126 2706060 738900 3 5622450Stage 10 PADXL 2640 3036246 670612726 2833320 738900 303 5925460Slow for Seat XL 2618506296 67562100 2854320 738900 50 5975470Resume PadXL 2640 16297 675742 2854740 738900 1 5976481ScourXL 2640 406337 67971680 2871541609 74050840/70-CL38 6014493ScourXL 2640 806417 68773360 2905148899 74940740/70-CL71 6085500FlatXL 2640 506467 69272100 2926140 749407 50 6135511FlatXL 2640 2006667 71278400 3010148043 757450CSG-IV191 6326522FlatXL 2640 2256892 73529450 31046417358 774808CSG-IV207 6533534FlatXL 2640 2757167 762711550 32201439232 814040CSG-IV234 6767546FlatXL 2640 2607427 788710920 33293451736 865776CSG-IV205 6972558FlatXL 2640 2407667 812710080 34301459502 925278CSG-IV177 71495610FlatXL 2640 2007867 83278400 35141458170 983448CSG-IV138 7287570Clear Surface LinesXL 2640 157882 8342630 3520440 983448 15 7302580Spacer XL 2640157897 8357630 3526740 983448 15 7317590Drop Stage 11 Ball/Collet FP 04037900 8360126 3528000 983448 3 7320600Stage 11 PADXL 2640 2958195 865512390 3651900 983448 295 7615610Slow for Seat XL 2618508245 87052100 3672900 983448 50 7665620Resume PadXL 2640 18246 870642 3673320 983448 1 7666631ScourXL 2640 408286 87461680 3690121609 98505740/70-CL38 7705643ScourXL 2640 808366 88263360 3723728899 99395640/70-CL71 7775650Resume PadXL 2640 508416 88762100 3744720 993956 50 7825661FlatXL 2640 2008616 90768400 3828728043 1001999CSG-IV191 8017672FlatXL 2640 2258841 93019450 39232217358 1019357CSG-IV207 8223684FlatXL 2640 2759116 957611550 40387239232 1058589CSG-IV234 8457696FlatXL 2640 2609376 983610920 41479251736 1110325CSG-IV205 8662708FlatXL 2640 2409616 1007610080 42487259502 1169827CSG-IV177 88397110FlatXL 2640 2009816 102768400 43327258170 1227997CSG-IV138 8978720Clear Surface LinesXL 2640 159831 10291630 4339020 1227997 15 8993730Spacer XL 2640159846 10306630 4345320 1227997 15 9008740Drop Stage 12 Ball/Collet FP 04039849 10309126 4346580 1227997 3 9011750Stage 12 PADXL 2640 28710136 1059612054 4467120 1227997 287 9298 Well NameNDB-02710/14/25 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 Water760Slow for Seat XL 26185010186 106462100 4488120 1227997 50 9348770Resume PadXL 2640 110187 1064742 4488540 1227997 1 9349781FlatXL 2640 6010247 107072520 4513742413 123041040/70-CL57 9406793FlatXL 2640 12010367 108275040 45641413348 124375840/70-CL106 9512800FlatXL 2640 5010417 108772100 4585140 1243758 50 9562811FlatXL 2640 20010617 110778400 4669148043 1251801CSG-IV191 9754822FlatXL 2640 22510842 113029450 47636417358 1269159CSG-IV207 9960834FlatXL 2640 27511117 1157711550 48791439232 1308391CSG-IV234 10194846FlatXL 2640 26011377 1183710920 49883451736 1360127CSG-IV205 10399858FlatXL 2640 24011617 1207710080 50891459502 1419629CSG-IV177 105768610FlatXL 2640 20011817 122778400 51731458170 1477799CSG-IV138 10715870Clear Surface LinesXL 2640 1511832 12292630 5179440 1477799 15 10730880Spacer XL 26401511847 12307630 5185740 1477799 15 10745890Drop Stage 13 Ball/Collet FP 040311850 12310126 5187000 1477799 3 10748900XL Flush (DFIT)XL 2640 27812128 1258811676 5303760 1477799 278 11026910Slow for seat (DFIT) XL 26185012178 126382100 5324760 1477799 50 1107692DFIT FlushWF 2640233 12411 128719786 540582233 11309933000 feet MD + Surface EqmtFP20 7012481 129412949 543531TOTALS12941 5435311477799 Well NameNDB-02710/14/25 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)aFPbWF3.5404016801680cWF 261.0001680000dWF26 3.5310310 13020 14700 310 310e Pump CheckWF26 40100410 4200 18900 100 4100 410 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 4501680 205800 0 40 45020Stage 13 PADXL 2640 220260 6709240 298200 0CSG-IV220 67031ScourXL 2640 60320 7302520 323402413 241340/70-CL57 72743ScourXL 2640 120440 8505040 3738013348 1576140/70-CL106 83350Resume PadXL 2640 50490 9002100 394800 15761 50 88361FlatXL 2640 200690 11008400 478808043 23804CSG-IV191 107572FlatXL 2640 225915 13259450 5733017358 41163CSG-IV207 128284FlatXL 2640 2751190 160011550 6888039232 80394CSG-IV234 151596FlatXL 2640 2601450 186010920 7980051736 132130CSG-IV205 1720108FlatXL 2640 2401690 210010080 8988059502 191633CSG-IV177 18971110FlatXL 2640 2001890 23008400 9828058170 249802CSG-IV138 2036120Clear Surface LinesXL 2640 151905 2315630 989100 249802 15 2051130Spacer XL 2640151920 2330630 995400 249802 15 2066140Drop Stage 14 Ball/Collet FP 04031923 2333126 996660 249802 3 2069150Stage 14 PADXL 2640 2702193 260311340 1110060 249802 270 2339160Slow for Seat XL 2618502243 26532100 1131060 249802 50 2389170Resume PadXL 2640 602303 27132520 1156260 249802 60 2449181FlatXL 2640 2052508 29188610 1242368244 258046CSG-IV196 2645193FlatXL 2640 2052713 31238610 13284622794 280840CSG-IV181 2826205FlatXL 2640 2352948 33589870 14271640384 321224CSG-IV192 3018217FlatXL 2640 2353183 35939870 15258652707 373931CSG-IV179 3198229FlatXL 2640 2103393 38038820 16140656714 430645CSG-IV150 33482311FlatXL 2640 1803573 39837560 16896655870 486515CSG-IV121 3469240Clear Surface LinesXL 2640 153588 3998630 1695960 486515 15 3484250Spacer XL 2640153603 4013630 1702260 486515 15 3499260Drop Stage 15 Ball/Collet FP 04033606 4016126 1703520 486515 3 3502270Stage 15 PADXL 2640 2623868 427811004 1813560 486515 262 3764280Slow for Seat XL 2618503918 43282100 1834560 486515 50 3814290Resume PadXL 2640 633981 43912646 1861020 486515 63 3877301FlatXL 2640 1904171 45817980 1940827641 494156CSG-IV182 4059313FlatXL 2640 2154386 47969030 20311223905 518061CSG-IV190 4248325FlatXL 2640 2404626 503610080 21319241243 559304CSG-IV196 4445Pump Ball to SeatFLUID Neat WaterCOMMENTSEnsure Stage 14 ball/collet is loaded Prime and Pressure TestOpen well- Displace PTDrop BallStage to "Line out XL" Well NameNDB-02710/14/25 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 Water337FlatXL 2640 2404866 527610080 22327253828 613132CSG-IV183 4628349FlatXL 2640 2205086 54969240 23251259415 672548CSG-IV157 47853511FlatXL 2640 1905276 56867980 24049258974 731521CSG-IV128 4913360Clear Surface LinesXL 2640 155291 5701630 2411220 731521 15 4928370Spacer XL 2640155306 5716630 2417520 731521 15 4943380Drop Stage 16 Ball/Collet FP 04035309 5719126 2418780 731521 3 4946390Stage 16 PADXL 2640 2545563 597310668 2525460 731521 254 5200400Slow for Seat XL 2618505613 60232100 2546460 731521 50 5250410Resume PadXL 2640 965709 61194032 2586780 731521 96 5346421FlatXL 2640 1805889 62997560 2662387239 738760CSG-IV172 5518432FlatXL 2640 2006089 64998400 27463815430 754190CSG-IV184 5702444FlatXL 2640 2206309 67199240 28387831385 785575CSG-IV187 5889456FlatXL 2640 2206529 69399240 29311843777 829352CSG-IV174 6062468FlatXL 2640 2206749 71599240 30235854544 883895CSG-IV162 62254710FlatXL 2640 2006949 73598400 31075858170 942065CSG-IV138 63634812FlatXL 2640 1807129 75397560 31831859183 1001249CSG-IV117 6480490Clear Surface LinesXL 2640 157144 7554630 3189480 1001249 15 6495500Spacer XL 2640157159 7569630 3195780 1001249 15 6510510Drop Stage 17 Ball/Collet FP 04037162 7572126 3197040 1001249 3 6513520Stage 17 PADXL 2640 2457407 781710290 3299940 1001249 245 6758530Slow for Seat XL 2618507457 78672100 3320940 1001249 50 6808540Resume PadXL 2640 1057562 79724410 3365040 1001249 105 6913551FlatXL 2640 1807742 81527560 3440647239 1008487CSG-IV172 7086562FlatXL 2640 2007942 83528400 35246415430 1023917CSG-IV184 7270574FlatXL 2640 2208162 85729240 36170431385 1055302CSG-IV187 7456586FlatXL 2640 2208382 87929240 37094443777 1099079CSG-IV174 7630598FlatXL 2640 2208602 90129240 38018454544 1153623CSG-IV162 77926010FlatXL 2640 2008802 92128400 38858458170 1211793CSG-IV138 79316112FlatXL 2640 1808982 93927560 39614459183 1270976CSG-IV117 8048620Clear Surface LinesXL 2640 158997 9407630 3967740 1270976 15 8063630Spacer XL 2640159012 9422630 3974040 1270976 15 8078640Drop Stage 18 Ball/Collet FP 04039015 9425126 3975300 1270976 3 8081650Stage 18 PADXL 2640 2389253 96639996 4075260 1270976 238 8319660Slow for Seat XL 2618509303 97132100 4096260 1270976 50 8369670Resume PadXL 2640 1129415 98254704 4143300 1270976 112 8481681FlatXL 2640 1809595 100057560 4218907239 1278215CSG-IV172 8654692FlatXL 2640 2009795 102058400 43029015430 1293644CSG-IV184 8837704FlatXL 2640 22010015 104259240 43953031385 1325030CSG-IV187 9024716FlatXL 2640 22010235 106459240 44877043777 1368806CSG-IV174 9198728FlatXL 2640 22010455 108659240 45801054544 1423350CSG-IV162 93607310FlatXL 2640 20010655 110658400 46641058170 1481520CSG-IV138 94997412FlatXL 2640 18010835 112457560 47397059183 1540703CSG-IV117 9616 Well NameNDB-02710/14/25 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 Water75XL FlushXL 264010 10845 11255420 47271010 962676Linear FlushWF 2640187 11032 114427854 480564187 9813773000 feet MD + Surface EqmtFP20 7011102 115122949 483513TOTALS11512 4835131540703 Additive Additive Description D206 Antifoam Agent 0.0 Gal/mGal 10 gal F103 Surfactant 1.0 Gal/mGal 1,344.0 gal J450 Stabilizing Agent 0.4 Gal/mGal 620.0 gal J475 Breaker J475 5.3 lb/mGal 7,434.0 lbm J511 Stabilizing Agent 1.8 lb/mGal 2,478.0 lbm J532 Crosslinker 2.2 Gal/mGal 3,098.0 gal J580 Gel J580 26.0 lb/mGal 34,944.0 lbm J753 Enzyme Breaker J753 0.1 Gal/mGal 93.0 gal M002 Additive 0.0 lb/mGal 1 lbm M117 Clay Control Agent 323.9 lb/mGal 455,593.2 lbm M275 Bactericide 0.3 lb/mGal 427.0 lbm S522-1620 Propping Agent varied concentrations 4,005,045.0 lbm S522-4070 Propping Agent varied concentrations 121,040.0 lbm S901-1620 Proppant with Scale Inhibitor S901- 1620 varied concentrations 127,820.0 lbm S902-1620 Proppant with Scale Inhibitor S902- 16/20 varied concentrations 127,821.0 lbm ~ 69 % ~ 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 1,344,000 gal Proprietary Technology The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. Fluid Name & Volume Concentration Volume Disclosure Type: Pre-Job Well Completed: Date Prepared: 10/17/2025 State: Alaska County/Parish: North Slope Borough Case: Client: Oil Search Alaska Well: PIKKA NDB-027 Basin/Field: Pikka # SLB-Private Page: 1 / 1 Updated 10/03/202510/3/2025TBDAK 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!151.4573940000T-716TracercoChemical Tracer1,3,5-Tribromobenzene626-39-1100#VALUE!0.4409240000T-161BTracercoChemical Tracer4-Iodotoluene624-31-7100#VALUE!0.4409240000T-731TracercoChemical Tracer1-Bromo-3,5-dichlorobenzene19752-55-7100#VALUE!0.4409240000T-718TracercoChemical Tracer4-Chlorobenzophenone134-85-0100#VALUE!0.6613860000T-168ATracercoChemical Tracer1-Chloro-4-iodobenzene637-87-6100#VALUE!0.4409240000T-168CTracercoChemical Tracer1-Bromo-4-iodobenzene589-87-7100#VALUE!0.4409240000T-769TracercoChemical Tracer4-Fluorobenzophenone345-83-5100#VALUE!1.1023100000T-748TracercoChemical Tracer1-Bromo-2-chlorobenzene694-80-4100#VALUE!2.2046200000T-706TracercoChemical Tracer1-Bromo-4-chlorobenzen106-39-8100#VALUE!2.2046200000T-160DTracercoChemical Tracer2,4,5-Tribromotoluene3278-88-4100#VALUE!0.6613860000T-756TracercoChemical Tracer3,5-Difluorobenzophenone179113-89-4100#VALUE!0.6613860000T-163BTracercoChemical Tracer1,2-Diiodobenzene615-42-9100#VALUE!0.4409240000T-165BTracercoChemical Tracer2-Iodobiphenyl2113-51-1100#VALUE!0.4409240000T-165CTracercoChemical Tracer9-Bromophenanthrene573-17-1100#VALUE!0.6613860000T-165GTracercoChemical Tracer2-Bromofluorene1133-80-8100#VALUE!0.8818480000T-166CTracercoChemical Tracer1-Iodo-3,4-dimethylbenzene31599-61-8100#VALUE!1.1023100000T-168BTracercoChemical Tracer1,2-Dichloro-4-iodobenzene20555-91-3100#VALUE!0.4409240000T-169CTracercoChemical Tracer2,4-Dibromomesitylene6942-99-0100#VALUE!0.8818480000T-164CTracercoSolid1-Iodonaphthalene90-14-2100#VALUE!0.4409240000T-729TracercoSolid1,4-Dibromo-2,5-dimethyl benzene1074-24-4100#VALUE!2.2046200000T-160BTracercoSolid3,5-Dibromotoluene1611-92-3100#VALUE!1.1023100000WaterTracercoCarrier FluidWater7732-18-5100#VALUE!110.1372740000T-158dTracercoChemical TracerSodium-3,4-Difluorobenzoate522651-44-1100#VALUE!0.7716170000T-140bTracercoChemical TracerSodium-3-Fluorobenzoate499-57-0100#VALUE!0.7716170000T-158cTracercoChemical TracerSodium-2,6-Difluorobenzoate6185-28-0100#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: NDB-027Hydraulic Fracturing Fluid Product Component Information DisclosureManufacturer Contact Tracerco 4106 New West Dr. Pasadena Texas 77507 Tel: 281-291-7769Fracture DateState: Approved For Tracerco T-190cTracercoChemical TracerSodium-4-(Trifluoromethyl) benzoate25832-58-0100#VALUE!0.7716170000T-190aTracercoChemical TracerSodium-2-(Trifluoromethyl) benzoate2966-44-1100#VALUE!0.7716170000T-158fTracercoChemical TracerSodium-2,3-Difluorobenzoate1604819-08-0100#VALUE!0.7716170000T-910TracercoChemical TracerSodium-2-chloro-3-fluorobenzoate1382106-83-3100#VALUE!0.7716170000T-950TracercoChemical TracerSodium-2-fluoro-3-(Trifluoromethyl)-benzoate1701446-41-4100#VALUE!0.7716170000T-953TracercoChemical TracerSodium-3-fluoro-5-(Trifluoromethyl)-benzoate1535169-59-5100#VALUE!0.7716170000T-190bTracercoChemical TracerSodium-3-(Trifluoromethyl) benzoate69226-41-1100#VALUE!0.7716170000T-176dTracercoChemical TracerSodium-3,4,5-trifluorobenzoate1180493-12-2100#VALUE!0.7716170000T-140aTracercoChemical TracerSodium-2-fluorobenzoate490-97-1100#VALUE!0.7716170000T-257aTracercoChemical TracerSodium-3,5-di(Trifluoromethyl)benzoate87441-96-1100#VALUE!0.7716170000T-914TracercoChemical TracerSodium-2-chloro-4,5-difluorobenzoate1421761-16-1100#VALUE!0.7716170000T-916TracercoChemical TracerSodium-3-chloro-2,4-difluorobenzoate1396762-34-7100#VALUE!0.7716170000T-919TracercoChemical TracerSodium-4-chloro-3-fluorobenzoate1421029-88-0100#VALUE!0.7716170000T-921TracercoChemical TracerSodium-3-chloro-2-fluorobenzoate1421029-89-1100#VALUE!0.7716170000T-925TracercoChemical TracerSodium-4-fluoro-3-methylbenzoate1431868-18-6100#VALUE!0.7716170000 Attachment G NDB-027 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 gasg ( ) , 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. NDB-027 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 H NDB-027 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. Flow check for 10 minutes. 9. POOH with liner hanger running tool. 10.Prepare to run upper completion. NDB-027 4-1/2 Upper Completion Section Summary Procedure: 11.Run 4-1/2 12.6 ppf P110S TSH563 tubing and downhole jewellery. 12.Circulate out the OBM from liner top to surface with 9.2 ppg NaCl Brine. 13.Land tubing hanger. 14.MIT-IA to 4,000 psi for 30 minutes on rig. (Post rig move, pressure tested to 4,300 psi for 30 minutes and passed (09/30/2025)) 15.MIT-T to 3,500 psi for 30 minutes on rig. (Post rig move, pressure tested to 5,500 psi for 30 minutes and passed (09/30/2025)) a. Post rig more pressure test criteria: (8,800 psi MAWP 3,800 psi IA hold) * 1.1 = 5,500 psi tubing 16.Nipple down BOP stack and install 10k frac tree. 17.RDMO 5,500 4,300 psi Attachment I Attachment J Tuluvak Sand @ 3,311' MD Top Nan 3.2 @17,344' MD Top Nanushuk @15,992' NDB-027 Well Schematic (As-Built) 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer 2,780' MD 13-3/8" 68 ppf L-80 Surface Casing 2,935' MD 4-½, 12.6ppf P-110S Production Liner26,907' MD 4-½ Liner Hanger/Top Packer17,056' MD GL 69.74' RKB MSL 09/29/2025 9-5/8" Tieback2,780' MD 9-5/8" Cflex Stage Tool (50' MD below TS790)5,979' MD 7" TOC (224' TVD above top Nanushuk) 13,886' MD 7", 26ppf L-80 Production Liner17,275' MD 9-5/8", 47ppf L-80 Intermediate Liner 11,995' MD 9-5/8" Primary TOC (1000' MD above shoe) 10,995' MD 7" Liner Hanger and Liner Top Packer 11,832' MD 23 29 10 47 48 8-½ Openhole TD26,914' 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 PB1 Sidetrack 12,000' MD 12¼ openhole # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1543 1480 29 3.813 5.201 2 Gaslift Mandrel 1.5" 2308 2080 52 3.865 7.640 3 X Landing Nipple 2379 2120 54 3.813 5.203 4 D/H Psi-Temp Gauge 16717 3900 76 3.864 5.830 5 EGL Valve 16822 3930 74 3.958 5.900 6 Tieback Seal Assy (No-Go) 17056 4000 71 3.860 5.190 7 7" x 4.5" LH/Packer 17103 4010 71 5.000 5.960 8 #20 Openhole Packer 17421 4100 78 3.898 5.755 9 #19 Openhole Packer 17487 4110 81 3.898 5.700 10 Stg 18 - Collet Sleeve 18 17634 4130 84 3.735 5.634 11 #18 Openhole Packer 17906 4140 89 3.898 5.755 12 Stg 17 - Collet Sleeve 17 18137 4141 90 3.735 5.634 13 #17 Openhole Packer 18365 4141 90 3.898 5.755 14 Stg 16 - Collet Sleeve 16 18678 4140 90 3.735 5.634 15 #16 Openhole Packer 18868 4139 90 3.898 5.755 16 Stg 15 - Collet Sleeve 15 19223 4138 90 3.735 5.634 17 #15 Openhole Packer 19495 4137 90 3.898 5.755 18 Stg 14 - Collet Sleeve 14 19768 4136 90 3.735 5.634 19 #14 Openhole Packer 20122 4134 90 3.898 5.755 20 Stg 13 - Collet Sleeve 13 20312 4134 90 3.735 5.634 21 #13 Openhole Packer 20624 4132 90 3.898 5.755 22 Stg 12 - Collet Sleeve 12 20855 4131 90 3.735 5.634 23 #12 Openhole Packer 21127 4128 90 3.898 5.755 24 Stg 11 - Collet Sleeve 11 21399 4126 91 3.735 5.634 25 #11 Openhole Packer 21672 4124 90 3.898 5.755 26 Stg 10 - Collet Sleeve 10 21944 4122 90 3.735 5.634 27 #10 Openhole Packer 22255 4120 90 3.898 5.755 28 Stg 9 - Collet Sleeve 9 22486 4119 90 3.735 5.634 29 #9 Openhole Packer 22759 4118 90 3.898 5.755 30 Stg 8- Collet Sleeve 8 23032 4117 90 3.735 5.634 31 #8 Openhole Packer 23304 4116 90 3.898 5.755 32 Stg 7 - Collet Sleeve 7 23575 4115 90 3.735 5.634 33 #7 Openhole Packer 23847 4113 90 3.898 5.755 34 Stg 6- Collet Sleeve 6 24118 4112 90 3.735 5.634 35 #6 Openhole Packer 24389 4111 90 3.898 5.755 36 Stg 5 - Collet Sleeve 5 24659 4109 90 3.735 5.634 37 #5 Openhole Packer 24930 4107 91 3.898 5.755 38 Stg 4 - Collet Sleeve 4 25201 4105 90 3.735 5.634 39 #4 Openhole Packer 25472 4102 91 3.898 5.755 40 Stg 3 - Collet Sleeve 3 25744 4100 90 3.735 5.634 41 #3 Openhole Packer 25975 4099 90 3.898 5.755 42 Stg 2 - Collet Sleeve 2 26205 4098 90 3.735 5.634 43 #2 Openhole Packer 26434 4098 90 3.898 5.755 44 Stg 1 - Collet Sleeve 1 26665 4097 90 3.735 5.634 45 #1 Openhole Packer 26772 4096 90 3.898 5.755 46 Toe Sleeve 26879 4095 90 3.500 5.750 47 WIV Collar 26892 4095 90 0.875 5.620 48 Eccentric shoe 26905 4095 90 3.840 5.200 Attachment K Kinetix-Frac Completion Report Santos Country: United States Well Name: NDB-027 Operator: Santos Field: Pikka Formation: Nanushuk Prepared By: Maylu Ramones Report Date: October 15th 2025 Table of Contents Well Description ......................................................................................................................................................................................... 5 Stage 1 ....................................................................................................................................................................................................... 6 Zoneset Simulated: ................................................................................................................................................................................ 6 Pumping Schedule Simulated: ............................................................................................................................................................. 10 Simulation Summary: ........................................................................................................................................................................... 11 Stage 2 ..................................................................................................................................................................................................... 12 Zoneset Simulated: .............................................................................................................................................................................. 12 Pumping Schedule Simulated: ............................................................................................................................................................. 16 Simulation Summary: ........................................................................................................................................................................... 17 Stage 3 ..................................................................................................................................................................................................... 18 Zoneset Simulated: .............................................................................................................................................................................. 18 Pumping Schedule Simulated: ............................................................................................................................................................. 22 Simulation Summary: ........................................................................................................................................................................... 23 Stage 4 ..................................................................................................................................................................................................... 24 Zoneset Simulated: .............................................................................................................................................................................. 24 Pumping Schedule Simulated: ............................................................................................................................................................. 28 Simulation Summary: ........................................................................................................................................................................... 29 Stage 5 ..................................................................................................................................................................................................... 30 Zoneset Simulated: .............................................................................................................................................................................. 30 Pumping Schedule Simulated: ............................................................................................................................................................. 34 Simulation Summary: ........................................................................................................................................................................... 35 Stage 6 ..................................................................................................................................................................................................... 36 Zoneset Simulated: .............................................................................................................................................................................. 36 Pumping Schedule Simulated: ............................................................................................................................................................. 40 Stage 7 ..................................................................................................................................................................................................... 42 Zoneset Simulated: .............................................................................................................................................................................. 42 Pumping Schedule Simulated: ............................................................................................................................................................. 46 Simulation Summary: ........................................................................................................................................................................... 47 Stage 8 ..................................................................................................................................................................................................... 48 Zoneset Simulated: .............................................................................................................................................................................. 48 Pumping Schedule Simulated: ............................................................................................................................................................. 52 Simulation Summary: ........................................................................................................................................................................... 53 Stage 9 ..................................................................................................................................................................................................... 54 Attachment K- NDB-027 Page 3 of 113 Zoneset Simulated: .............................................................................................................................................................................. 54 Pumping Schedule Simulated: ............................................................................................................................................................. 58 Simulation Summary: ........................................................................................................................................................................... 59 Stage 10 ................................................................................................................................................................................................... 60 Zoneset Simulated: .............................................................................................................................................................................. 60 Pumping Schedule Simulated: ............................................................................................................................................................. 64 Simulation Summary: ........................................................................................................................................................................... 65 Stage 11 ................................................................................................................................................................................................... 66 Zoneset Simulated: .............................................................................................................................................................................. 66 Pumping Schedule Simulated: ............................................................................................................................................................. 70 Simulation Summary: ........................................................................................................................................................................... 71 Stage 12 ................................................................................................................................................................................................... 72 Zoneset Simulated: .............................................................................................................................................................................. 72 Pumping Schedule Simulated: ............................................................................................................................................................. 76 Simulation Summary: ........................................................................................................................................................................... 77 Stage 13 ................................................................................................................................................................................................... 78 Zoneset Simulated: .............................................................................................................................................................................. 78 Pumping Schedule Simulated: ............................................................................................................................................................. 82 Simulation Summary: ........................................................................................................................................................................... 83 Stage 14 ................................................................................................................................................................................................... 84 Zoneset Simulated: .............................................................................................................................................................................. 84 Pumping Schedule Simulated: ............................................................................................................................................................. 88 Simulation Summary: ........................................................................................................................................................................... 89 Stage 15 ................................................................................................................................................................................................... 90 Zoneset Simulated: .............................................................................................................................................................................. 90 Pumping Schedule Simulated: ............................................................................................................................................................. 94 Simulation Summary: ........................................................................................................................................................................... 95 Stage 16 ................................................................................................................................................................................................... 96 Zoneset Simulated: .............................................................................................................................................................................. 96 Pumping Schedule Simulated: ........................................................................................................................................................... 100 Simulation Summary: ......................................................................................................................................................................... 101 Stage 17 ................................................................................................................................................................................................. 102 Zoneset Simulated: ............................................................................................................................................................................ 102 Pumping Schedule Simulated: ........................................................................................................................................................... 106 Simulation Summary: ......................................................................................................................................................................... 107 Attachment K- NDB-027 Page 4 of 113 Stage 18 ................................................................................................................................................................................................. 108 Zoneset Simulated: ............................................................................................................................................................................ 108 Pumping Schedule Simulated: ........................................................................................................................................................... 112 Simulation Summary: ......................................................................................................................................................................... 113 Attachment K- NDB-027 Page 5 of 113 Well Description Completion Stages and Perforations Stage Perforation Top MD Spacing Perforation Top TVD (ft) (ft) (ft) 18 17634 497 4130.63 17 18137 535 4141.96 16 18678 539 4139.88 15 19223 539 4137.9 14 19768 538 4135.81 13 20312 537 4133.88 12 20855 538 4130.42 11 21399 539 4125.94 10 21944 536 4121.75 9 22486 540 4118.69 8 23032 537 4116.69 7 23575 537 4114.53 6 24118 535 4112.36 5 24659 536 4108.82 4 25201 537 4104.48 3 25744 455 4100.41 2 26205 454 4098.4 1 26665 0 4096.62 Attachment K- NDB-027 Page 6 of 113 Stage 1 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 1 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7718.5 psi 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 29.82 0.7 2816.05 2786554.2 0.25 2500 Shale 4037.8 26.74 0.66 2665.65 2786554.2 0.25 2500 Top 3.2 NAN CS 4064.53 3.6 0.6 2460.13 1159218.9 0.26 600 Siltstone 4068.14 1.8 0.62 2510.6 1629236.3 0.26 1500 CleanSandstone 4069.95 1.8 0.6 2446.64 979798.8 0.26 600 Siltstone 4071.75 3.6 0.61 2468.54 1350455.1 0.26 1500 CleanSandstone 4075.36 3.6 0.61 2487.11 1206390.9 0.26 600 Siltstone 4078.94 3.6 0.61 2476.95 1313860.7 0.26 1500 CleanSandstone 4082.55 7.2 0.61 2480.29 1266403.2 0.26 600 Attachment K- NDB-027 Page 7 of 113 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 4089.73 1.8 0.61 2478.99 1082935.6 0.26 1500 DirtySandstone 4091.54 1.8 0.62 2549.62 1222900.8 0.26 600 Shale 4093.34 1.8 0.62 2554.84 1419038.4 0.26 2500 DirtySandstone 4095.14 1.8 0.62 2519.02 1403385.6 0.26 600 Siltstone 4096.95 9 0.62 2534.68 1402756.3 0.26 1500 Shale 4105.94 3.6 0.66 2690.6 2181052.3 0.25 2500 DirtySandstone 4109.55 5.4 0.62 2553.68 1662780.4 0.26 1500 Siltstone 4114.96 1.8 0.63 2584.72 1963674.5 0.26 2500 DirtySandstone 4116.73 3.7 0.62 2561.8 1742901.7 0.26 1500 Siltstone 4120.44 5.4 0.63 2597.63 1681056.2 0.26 2500 Siltstone 4125.85 1.8 0.62 2566.88 1561073 0.26 1500 DirtySandstone 4127.66 1.8 0.62 2551.5 1262913.1 0.26 2500 Siltstone 4129.46 3.6 0.63 2610.97 1816969.7 0.26 1500 Shale 4133.04 11 0.65 2673.48 2238744.4 0.25 2500 CleanSandstone 4144.06 2 0.61 2516.11 1001510.6 0.26 600 Siltstone 4146.03 4 0.62 2571.81 1571504.2 0.26 1500 Attachment K- NDB-027 Page 8 of 113 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) CleanSandstone 4150.03 2 0.6 2511.33 1267177.7 0.26 600 Shale 4152.03 2 0.66 2728.59 2789765.8 0.25 2500 Siltstone 4154.04 2 0.62 2563.69 1409418.9 0.26 1500 Shale 4156.04 2.1 0.66 2731.21 2789765.8 0.25 2500 DirtySandstone 4158.14 4 0.61 2537.73 1435306.6 0.26 1500 Siltstone 4162.14 4 0.62 2590.08 1765617.4 0.26 2500 DirtySandstone 4166.14 4 0.61 2559.19 1435651.3 0.26 1500 CleanSandstone 4170.14 2.1 0.59 2465.21 935658.3 0.26 2500 Siltstone 4172.24 4 0.62 2596.32 1491142.7 0.26 1500 Shale 4176.25 2 0.66 2744.4 2789765.8 0.25 2500 DirtySandstone 4178.25 11 0.62 2581.38 1462838 0.26 1500 Shale 4189.24 27 0.65 2740.2 2560999.9 0.25 2500 Siltstone 4216.24 2 0.63 2673.77 1857874.8 0.26 1500 Shale 4218.24 10 0.66 2770.51 2552268.6 0.25 2500 Siltstone 4228.25 2 0.63 2651.72 1509543.6 0.26 1500 Shale 4230.25 4.1 0.64 2708.72 2349461.1 0.25 2500 Attachment K- NDB-027 Page 9 of 113 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 4234.35 2 0.64 2693.64 1482677.8 0.25 1500 Shale 4236.35 96.4 0.65 2797.78 2604074 0.25 2500 DirtySandstone 4332.74 2 0.61 2643.6 1153391 0.26 1500 Shale 4334.74 38.2 0.66 2851.73 2733692 0.25 2500 Siltstone 4372.93 2 0.62 2716.27 1526263.4 0.26 1500 Shale 4374.93 46.2 0.66 2880.74 2704369.9 0.25 2500 Siltstone 4421.16 2 0.64 2808.08 1825853.3 0.25 1500 Shale 4423.13 9.84 0.65 2891.47 2657615 0.25 2500 Attachment K- NDB-027 Page 10 of 113 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 125 CarboLite 16/20- SG 1 5027 3.13 3 2 PPA 40 YF126ST 5400.5 140 CarboLite 16/20- SG 2 10801 3.5 4 3 PPA 40 YF126ST 6300.9 170 CarboLite 16/20- SG 3 18902.7 4.25 5 4 PPA 40 YF126ST 6063.6 170 CarboLite 16/20- SG 4 24254.4 4.25 6 5 PPA 40 YF126ST 5843.5 170 CarboLite 16/20- SG 5 29217.5 4.25 7 6 PPA 40 YF126ST 5638.5 170 CarboLite 16/20- SG 6 33831 4.25 8 7 PPA 40 YF126ST 4486.3 140 CarboLite 16/20- SG 7 31404.1 3.5 9 8 PPA 40 YF126ST 3874.4 125 CarboLite 16/20- SG 8 30995.2 3.12 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 28.27 24.84 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 59434.7 184432.9 1610 40.25 Attachment K- NDB-027 Page 11 of 113 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 1 MD: [26665, 26671] 7718.5 214.19 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4027.34 4241.53 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 1 MD: [26665, 26671] 520.05 172.4 0.593 Attachment K- NDB-027 Page 12 of 113 Stage 2 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 2 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 6000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7727.7 psi 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 4000 30.62 0.7 2810.68 2786554.2 0.25 2500 Shale 4030.62 26.74 0.66 2656.9 2786554.2 0.25 2500 Top 3.2 NAN CS 4057.36 3.6 0.6 2455.79 1159218.9 0.26 600 Siltstone 4060.96 1.8 0.62 2506.17 1629236.3 0.26 1500 CleanSandstone 4062.76 1.8 0.6 2442.26 979798.8 0.26 600 Siltstone 4064.56 3.6 0.61 2464.21 1350455.1 0.26 1500 CleanSandstone 4068.16 3.6 0.61 2482.68 1206390.9 0.26 600 Siltstone 4071.76 3.6 0.61 2472.65 1313860.7 0.26 1500 CleanSandstone 4075.36 7.2 0.61 2475.93 1266403.2 0.26 600 Attachment K- NDB-027 Page 13 of 113 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 4082.56 1.8 0.61 2474.58 1082935.6 0.26 1500 DirtySandstone 4084.36 1.8 0.62 2545.12 1222900.8 0.26 600 Shale 4086.16 1.8 0.62 2550.33 1419038.4 0.26 2500 DirtySandstone 4087.96 1.8 0.62 2514.65 1403385.6 0.26 600 Siltstone 4089.76 9 0.62 2530.25 1402756.3 0.26 1500 Shale 4098.76 3.6 0.66 2685.87 2181052.3 0.25 2500 DirtySandstone 4102.36 5.4 0.62 2549.24 1662780.4 0.26 1500 Siltstone 4107.76 1.8 0.63 2580.24 1963674.5 0.26 2500 DirtySandstone 4109.56 3.7 0.62 2557.3 1742901.7 0.26 1500 Siltstone 4113.26 5.4 0.63 2593.05 1681056.2 0.26 2500 Siltstone 4118.66 1.8 0.62 2562.37 1561073 0.26 1500 DirtySandstone 4120.46 1.8 0.62 2547 1262913.1 0.26 2500 Siltstone 4122.26 3.6 0.63 2606.41 1816969.7 0.26 1500 Shale 4125.86 11 0.65 2668.86 2238744.4 0.25 2500 CleanSandstone 4136.86 2 0.61 2511.68 1001510.6 0.26 600 Siltstone 4138.86 4 0.62 2567.33 1571504.2 0.26 1500 Attachment K- NDB-027 Page 14 of 113 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) CleanSandstone 4142.86 2 0.6 2507.04 1267177.7 0.26 600 Shale 4144.86 2 0.66 2723.83 2789765.8 0.25 2500 Siltstone 4146.86 2 0.62 2559.23 1409418.9 0.26 1500 Shale 4148.86 2.1 0.66 2726.49 2789765.8 0.25 2500 DirtySandstone 4150.96 4 0.61 2533.31 1435306.6 0.26 1500 Siltstone 4154.96 4 0.62 2585.63 1765617.4 0.26 2500 DirtySandstone 4158.96 4 0.61 2554.83 1435651.3 0.26 1500 CleanSandstone 4162.96 2.1 0.59 2460.93 935658.3 0.26 2500 Siltstone 4165.06 4 0.62 2591.91 1491142.7 0.26 1500 Shale 4169.06 2 0.66 2739.73 2789765.8 0.25 2500 DirtySandstone 4171.06 11 0.62 2576.94 1462838 0.26 1500 Shale 4182.06 27 0.65 2735.51 2560999.9 0.25 2500 Siltstone 4209.06 2 0.63 2669.18 1857874.8 0.26 1500 Shale 4211.06 10 0.66 2765.74 2552268.6 0.25 2500 Siltstone 4221.06 2 0.63 2647.23 1509543.6 0.26 1500 Shale 4223.06 4.1 0.64 2704.07 2349461.1 0.25 2500 Attachment K- NDB-027 Page 15 of 113 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 4227.16 2 0.64 2689.11 1482677.8 0.25 1500 Shale 4229.16 96.4 0.65 2793.12 2604074 0.25 2500 DirtySandstone 4325.56 2 0.61 2639.2 1153391 0.26 1500 Shale 4327.56 38.2 0.66 2847.06 2733692 0.25 2500 Siltstone 4365.76 2 0.62 2711.76 1526263.4 0.26 1500 Shale 4367.76 46.2 0.66 2876.01 2704369.9 0.25 2500 Siltstone 4413.96 2 0.64 2803.5 1825853.3 0.25 1500 Shale 4415.96 14.04 0.65 2888.21 2657615 0.25 2500 Attachment K- NDB-027 Page 16 of 113 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 6636.3 165.02 CarboLite 16/20- SG 1 6636.3 4.13 3 2 PPA 40 YF126ST 6945 180.03 CarboLite 16/20- SG 2 13890 4.5 4 3 PPA 40 YF126ST 7230.2 195.07 CarboLite 16/20- SG 3 21690.6 4.88 5 4 PPA 40 YF126ST 6958.4 195.09 CarboLite 16/20- SG 4 27833.6 4.88 6 5 PPA 40 YF126ST 6706.3 195.11 CarboLite 16/20- SG 5 33531.5 4.88 7 6 PPA 40 YF126ST 6471.8 195.12 CarboLite 16/20- SG 6 38830.8 4.88 8 7 PPA 40 YF126ST 5932.5 185.13 CarboLite 16/20- SG 7 41527.5 4.63 9 8 PPA 40 YF126ST 5273.3 170.13 CarboLite 16/20- SG 8 42186.4 4.25 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.6 23.31 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71053.8 226126.7 1930.7 48.27 Attachment K- NDB-027 Page 17 of 113 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 2 MD: [26205, 26211] 7727.7 230.68 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4018.4 4249.08 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 2 MD: [26205, 26211] 629.18 177.41 0.54 Attachment K- NDB-027 Page 18 of 113 Stage 3 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 3 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7494.5 psi 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 4000 30.62 0.7 2810.68 2786554.2 0.25 2500 Shale 4030.62 26.74 0.66 2656.9 2786554.2 0.25 2500 Top 3.2 NAN CS 4057.36 3.6 0.6 2455.79 1159218.9 0.26 600 Siltstone 4060.96 1.8 0.62 2506.17 1629236.3 0.26 1500 CleanSandstone 4062.76 1.8 0.6 2442.26 979798.8 0.26 600 Siltstone 4064.56 3.6 0.61 2464.21 1350455.1 0.26 1500 CleanSandstone 4068.16 3.6 0.61 2482.68 1206390.9 0.26 600 Siltstone 4071.76 3.6 0.61 2472.65 1313860.7 0.26 1500 CleanSandstone 4075.36 7.2 0.61 2475.93 1266403.2 0.26 600 Attachment K- NDB-027 Page 19 of 113 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 4082.56 1.8 0.61 2474.58 1082935.6 0.26 1500 DirtySandstone 4084.36 1.8 0.62 2545.12 1222900.8 0.26 600 Shale 4086.16 1.8 0.62 2550.33 1419038.4 0.26 2500 DirtySandstone 4087.96 1.8 0.62 2514.65 1403385.6 0.26 600 Siltstone 4089.76 9 0.62 2530.25 1402756.3 0.26 1500 Shale 4098.76 3.6 0.66 2685.87 2181052.3 0.25 2500 DirtySandstone 4102.36 5.4 0.62 2549.24 1662780.4 0.26 1500 Siltstone 4107.76 1.8 0.63 2580.24 1963674.5 0.26 2500 DirtySandstone 4109.56 3.7 0.62 2557.3 1742901.7 0.26 1500 Siltstone 4113.26 5.4 0.63 2593.05 1681056.2 0.26 2500 Siltstone 4118.66 1.8 0.62 2562.37 1561073 0.26 1500 DirtySandstone 4120.46 1.8 0.62 2547 1262913.1 0.26 2500 Siltstone 4122.26 3.6 0.63 2606.41 1816969.7 0.26 1500 Shale 4125.86 11 0.65 2668.86 2238744.4 0.25 2500 CleanSandstone 4136.86 2 0.61 2511.68 1001510.6 0.26 600 Siltstone 4138.86 4 0.62 2567.33 1571504.2 0.26 1500 Attachment K- NDB-027 Page 20 of 113 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) CleanSandstone 4142.86 2 0.6 2507.04 1267177.7 0.26 600 Shale 4144.86 2 0.66 2723.83 2789765.8 0.25 2500 Siltstone 4146.86 2 0.62 2559.23 1409418.9 0.26 1500 Shale 4148.86 2.1 0.66 2726.49 2789765.8 0.25 2500 DirtySandstone 4150.96 4 0.61 2533.31 1435306.6 0.26 1500 Siltstone 4154.96 4 0.62 2585.63 1765617.4 0.26 2500 DirtySandstone 4158.96 4 0.61 2554.83 1435651.3 0.26 1500 CleanSandstone 4162.96 2.1 0.59 2460.93 935658.3 0.26 2500 Siltstone 4165.06 4 0.62 2591.91 1491142.7 0.26 1500 Shale 4169.06 2 0.66 2739.73 2789765.8 0.25 2500 DirtySandstone 4171.06 11 0.62 2576.94 1462838 0.26 1500 Shale 4182.06 27 0.65 2735.51 2560999.9 0.25 2500 Siltstone 4209.06 2 0.63 2669.18 1857874.8 0.26 1500 Shale 4211.06 10 0.66 2765.74 2552268.6 0.25 2500 Siltstone 4221.06 2 0.63 2647.23 1509543.6 0.26 1500 Shale 4223.06 4.1 0.64 2704.07 2349461.1 0.25 2500 Attachment K- NDB-027 Page 21 of 113 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 4227.16 2 0.64 2689.11 1482677.8 0.25 1500 Shale 4229.16 96.4 0.65 2793.12 2604074 0.25 2500 DirtySandstone 4325.56 2 0.61 2639.2 1153391 0.26 1500 Shale 4327.56 38.2 0.66 2847.06 2733692 0.25 2500 Siltstone 4365.76 2 0.62 2711.76 1526263.4 0.26 1500 Shale 4367.76 46.2 0.66 2876.01 2704369.9 0.25 2500 Siltstone 4413.96 2 0.64 2803.5 1825853.3 0.25 1500 Shale 4415.96 14.04 0.65 2888.21 2657615 0.25 2500 Attachment K- NDB-027 Page 22 of 113 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 6636.3 165.02 CarboLite 16/20- SG 1 6636.3 4.13 3 2 PPA 40 YF126ST 6945 180.03 CarboLite 16/20- SG 2 13890 4.5 4 3 PPA 40 YF126ST 7230.2 195.07 CarboLite 16/20- SG 3 21690.6 4.88 5 4 PPA 40 YF126ST 6958.4 195.09 CarboLite 16/20- SG 4 27833.6 4.88 6 5 PPA 40 YF126ST 6706.3 195.11 CarboLite 16/20- SG 5 33531.5 4.88 7 6 PPA 40 YF126ST 6471.8 195.12 CarboLite 16/20- SG 6 38830.8 4.88 8 7 PPA 40 YF126ST 5932.5 185.13 CarboLite 16/20- SG 7 41527.5 4.63 9 8 PPA 40 YF126ST 5273.3 170.13 CarboLite 16/20- SG 8 42186.4 4.25 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.6 23.31 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71053.8 226126.7 1930.7 48.27 Attachment K- NDB-027 Page 23 of 113 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 3 MD: [25744, 25750] 7494.5 343.83 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 3996.92 4340.75 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 3 MD: [25744, 25750] 903.24 292.18 0.3 Attachment K- NDB-027 Page 24 of 113 Stage 4 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 4 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 6000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7358.1 psi 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 4000 36.02 0.7 2812.61 2786554.2 0.25 2500 Shale 4036.02 26.74 0.66 2660.45 2786554.2 0.25 2500 Top 3.2 NAN CS 4062.76 3.6 0.6 2459.06 1159218.9 0.26 600 Siltstone 4066.36 1.8 0.62 2509.5 1629236.3 0.26 1500 CleanSandstone 4068.16 1.8 0.6 2445.51 979798.8 0.26 600 Siltstone 4069.96 3.6 0.61 2467.49 1350455.1 0.26 1500 CleanSandstone 4073.56 3.6 0.61 2485.97 1206390.9 0.26 600 Attachment K- NDB-027 Page 25 of 113 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 4077.16 3.6 0.61 2475.93 1313860.7 0.26 1500 CleanSandstone 4080.76 7.2 0.61 2479.21 1266403.2 0.26 600 Siltstone 4087.96 1.8 0.61 2477.85 1082935.6 0.26 1500 DirtySandstone 4089.76 1.8 0.62 2548.48 1222900.8 0.26 600 Shale 4091.56 1.8 0.62 2553.7 1419038.4 0.26 2500 DirtySandstone 4093.36 1.8 0.62 2517.97 1403385.6 0.26 600 Siltstone 4095.16 9 0.62 2533.59 1402756.3 0.26 1500 Shale 4104.16 3.6 0.66 2689.4 2181052.3 0.25 2500 DirtySandstone 4107.76 5.4 0.62 2552.6 1662780.4 0.26 1500 Siltstone 4113.16 1.8 0.63 2583.63 1963674.5 0.26 2500 DirtySandstone 4114.96 3.7 0.62 2560.66 1742901.7 0.26 1500 Siltstone 4118.66 5.4 0.63 2596.46 1681056.2 0.26 2500 Siltstone 4124.06 1.8 0.62 2565.73 1561073 0.26 1500 DirtySandstone 4125.86 1.8 0.62 2550.34 1262913.1 0.26 2500 Siltstone 4127.66 3.6 0.63 2609.82 1816969.7 0.26 1500 Shale 4131.26 11 0.65 2672.35 2238744.4 0.25 2500 Attachment K- NDB-027 Page 26 of 113 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) CleanSandstone 4142.26 2 0.61 2514.96 1001510.6 0.26 600 Siltstone 4144.26 4 0.62 2570.68 1571504.2 0.26 1500 CleanSandstone 4148.26 2 0.6 2510.3 1267177.7 0.26 600 Shale 4150.26 2 0.66 2727.38 2789765.8 0.25 2500 Siltstone 4152.26 2 0.62 2562.56 1409418.9 0.26 1500 Shale 4154.26 2.1 0.66 2730.04 2789765.8 0.25 2500 DirtySandstone 4156.36 4 0.61 2536.6 1435306.6 0.26 1500 Siltstone 4160.36 4 0.62 2588.99 1765617.4 0.26 2500 DirtySandstone 4164.36 4 0.61 2558.15 1435651.3 0.26 1500 CleanSandstone 4168.36 2.1 0.59 2464.12 935658.3 0.26 2500 Siltstone 4170.46 4 0.62 2595.27 1491142.7 0.26 1500 Shale 4174.46 2 0.66 2743.28 2789765.8 0.25 2500 DirtySandstone 4176.46 11 0.62 2580.27 1462838 0.26 1500 Shale 4187.46 27 0.65 2739.03 2560999.9 0.25 2500 Siltstone 4214.46 2 0.63 2672.6 1857874.8 0.26 1500 Shale 4216.46 10 0.66 2769.28 2552268.6 0.25 2500 Attachment K- NDB-027 Page 27 of 113 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 4226.46 2 0.63 2650.62 1509543.6 0.26 1500 Shale 4228.46 4.1 0.64 2707.53 2349461.1 0.25 2500 Siltstone 4232.56 2 0.64 2692.54 1482677.8 0.25 1500 Shale 4234.56 96.4 0.65 2796.64 2604074 0.25 2500 DirtySandstone 4330.96 2 0.61 2642.5 1153391 0.26 1500 Shale 4332.96 38.2 0.66 2850.6 2733692 0.25 2500 Siltstone 4371.16 2 0.62 2715.11 1526263.4 0.26 1500 Shale 4373.16 46.2 0.66 2879.55 2704369.9 0.25 2500 Siltstone 4419.36 2 0.64 2806.93 1825853.3 0.25 1500 Shale 4421.36 9.84 0.65 2890.36 2657615 0.25 2500 Attachment K- NDB-027 Page 28 of 113 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 18900 450 11.25 2 1 PPA 40 YF126ST 6636.3 165.02 CarboLite 16/20- SG 1 6636.3 4.13 3 2 PPA 40 YF126ST 6945 180.03 CarboLite 16/20- SG 2 13890 4.5 4 3 PPA 40 YF126ST 7230.2 195.07 CarboLite 16/20- SG 3 21690.6 4.88 5 4 PPA 40 YF126ST 6958.4 195.09 CarboLite 16/20- SG 4 27833.6 4.88 6 5 PPA 40 YF126ST 6706.3 195.11 CarboLite 16/20- SG 5 33531.5 4.88 7 6 PPA 40 YF126ST 6471.8 195.12 CarboLite 16/20- SG 6 38830.8 4.88 8 7 PPA 40 YF126ST 5932.5 185.13 CarboLite 16/20- SG 7 41527.5 4.63 9 8 PPA 40 YF126ST 5273.3 170.13 CarboLite 16/20- SG 8 42186.4 4.25 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.6 23.31 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71053.8 226126.7 1930.7 48.27 Attachment K- NDB-027 Page 29 of 113 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 4 MD: [25201, 25207] 7358.1 352.57 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4001.3 4353.87 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 4 MD: [25201, 25207] 937.04 269.96 0.34 Attachment K- NDB-027 Page 30 of 113 Stage 5 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 5 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 6000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7783.9 psi 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 4000 39.62 0.7 2813.87 2786554.2 0.25 2500 Shale 4039.62 26.74 0.66 2662.81 2786554.2 0.25 2500 Top 3.2 NAN CS 4066.36 3.6 0.6 2461.24 1159218.9 0.26 600 Siltstone 4069.96 1.8 0.62 2511.72 1629236.3 0.26 1500 CleanSandstone 4071.76 1.8 0.6 2447.67 979798.8 0.26 600 Siltstone 4073.56 3.6 0.61 2469.67 1350455.1 0.26 1500 CleanSandstone 4077.16 3.6 0.61 2488.17 1206390.9 0.26 600 Attachment K- NDB-027 Page 31 of 113 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 4080.76 3.6 0.61 2478.11 1313860.7 0.26 1500 CleanSandstone 4084.36 7.2 0.61 2481.39 1266403.2 0.26 600 Siltstone 4091.56 1.8 0.61 2480.03 1082935.6 0.26 1500 DirtySandstone 4093.36 1.8 0.62 2550.72 1222900.8 0.26 600 Shale 4095.16 1.8 0.62 2555.94 1419038.4 0.26 2500 DirtySandstone 4096.96 1.8 0.62 2520.18 1403385.6 0.26 600 Siltstone 4098.76 9 0.62 2535.81 1402756.3 0.26 1500 Shale 4107.76 3.6 0.66 2691.76 2181052.3 0.25 2500 DirtySandstone 4111.36 5.4 0.62 2554.83 1662780.4 0.26 1500 Siltstone 4116.76 1.8 0.63 2585.89 1963674.5 0.26 2500 DirtySandstone 4118.56 3.7 0.62 2562.9 1742901.7 0.26 1500 Siltstone 4122.26 5.4 0.63 2598.72 1681056.2 0.26 2500 Siltstone 4127.66 1.8 0.62 2567.96 1561073 0.26 1500 DirtySandstone 4129.46 1.8 0.62 2552.56 1262913.1 0.26 2500 Siltstone 4131.26 3.6 0.63 2612.09 1816969.7 0.26 1500 Shale 4134.86 11 0.65 2674.67 2238744.4 0.25 2500 Attachment K- NDB-027 Page 32 of 113 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) CleanSandstone 4145.86 2 0.61 2517.14 1001510.6 0.26 600 Siltstone 4147.86 4 0.62 2572.91 1571504.2 0.26 1500 CleanSandstone 4151.86 2 0.6 2512.48 1267177.7 0.26 600 Shale 4153.86 2 0.66 2729.74 2789765.8 0.25 2500 Siltstone 4155.86 2 0.62 2564.78 1409418.9 0.26 1500 Shale 4157.86 2.1 0.66 2732.4 2789765.8 0.25 2500 DirtySandstone 4159.96 4 0.61 2538.8 1435306.6 0.26 1500 Siltstone 4163.96 4 0.62 2591.23 1765617.4 0.26 2500 DirtySandstone 4167.96 4 0.61 2560.36 1435651.3 0.26 1500 CleanSandstone 4171.96 2.1 0.59 2466.25 935658.3 0.26 2500 Siltstone 4174.06 4 0.62 2597.51 1491142.7 0.26 1500 Shale 4178.06 2 0.66 2745.64 2789765.8 0.25 2500 DirtySandstone 4180.06 11 0.62 2582.49 1462838 0.26 1500 Shale 4191.06 27 0.65 2741.37 2560999.9 0.25 2500 Siltstone 4218.06 2 0.63 2674.88 1857874.8 0.26 1500 Shale 4220.06 10 0.66 2771.64 2552268.6 0.25 2500 Attachment K- NDB-027 Page 33 of 113 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 4230.06 2 0.63 2652.87 1509543.6 0.26 1500 Shale 4232.06 4.1 0.64 2709.83 2349461.1 0.25 2500 Siltstone 4236.16 2 0.64 2694.83 1482677.8 0.25 1500 Shale 4238.16 96.4 0.65 2798.99 2604074 0.25 2500 DirtySandstone 4334.56 2 0.61 2644.69 1153391 0.26 1500 Shale 4336.56 38.2 0.66 2852.96 2733692 0.25 2500 Siltstone 4374.76 2 0.62 2717.35 1526263.4 0.26 1500 Shale 4376.76 46.2 0.66 2881.91 2704369.9 0.25 2500 Siltstone 4422.96 2 0.64 2809.21 1825853.3 0.25 1500 Shale 4424.96 9.84 0.65 2892.71 2657615 0.25 2500 Attachment K- NDB-027 Page 34 of 113 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 15960 380 9.5 2 1 PPA Scour 40 YF126ST 2414.7 60 CarboLite 40/70 1 2414.7 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120 CarboLite 40/70 3 13372.5 3 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20- SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20- SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20- SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20- SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20- SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 33.99 29.53 Attachment K- NDB-027 Page 35 of 113 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 73344 249856.8 2010 50.25 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 5 MD: [24659, 24665] 7783.9 psi 355.26 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4005.03 4360.29 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 5 MD: [24659, 24665] 997.39 276.77 0.37 Attachment K- NDB-027 Page 36 of 113 Stage 6 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 6 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7618.8 psi 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 4010 33.62 0.7 2818.77 2786554.2 0.25 2500 Shale 4043.62 26.74 0.66 2665.44 2786554.2 0.25 2500 Top 3.2 NAN CS 4070.36 3.6 0.6 2463.66 1159218.9 0.26 600 Siltstone 4073.96 1.8 0.62 2514.19 1629236.3 0.26 1500 CleanSandstone 4075.76 1.8 0.6 2450.07 979798.8 0.26 600 Siltstone 4077.56 3.6 0.61 2472.09 1350455.1 0.26 1500 CleanSandstone 4081.16 3.6 0.61 2490.61 1206390.9 0.26 600 Attachment K- NDB-027 Page 37 of 113 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 4084.76 3.6 0.61 2480.54 1313860.7 0.26 1500 CleanSandstone 4088.36 7.2 0.61 2483.82 1266403.2 0.26 600 Siltstone 4095.56 1.8 0.61 2482.45 1082935.6 0.26 1500 DirtySandstone 4097.36 1.8 0.62 2553.22 1222900.8 0.26 600 Shale 4099.16 1.8 0.62 2558.44 1419038.4 0.26 2500 DirtySandstone 4100.96 1.8 0.62 2522.64 1403385.6 0.26 600 Siltstone 4102.76 9 0.62 2538.29 1402756.3 0.26 1500 Shale 4111.76 3.6 0.66 2694.38 2181052.3 0.25 2500 DirtySandstone 4115.36 5.4 0.62 2557.32 1662780.4 0.26 1500 Siltstone 4120.76 1.8 0.63 2588.4 1963674.5 0.26 2500 DirtySandstone 4122.56 3.7 0.62 2565.38 1742901.7 0.26 1500 Siltstone 4126.26 5.4 0.63 2601.24 1681056.2 0.26 2500 Siltstone 4131.66 1.8 0.62 2570.45 1561073 0.26 1500 DirtySandstone 4133.46 1.8 0.62 2555.03 1262913.1 0.26 2500 Siltstone 4135.26 3.6 0.63 2614.62 1816969.7 0.26 1500 Shale 4138.86 11 0.65 2677.26 2238744.4 0.25 2500 Attachment K- NDB-027 Page 38 of 113 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) CleanSandstone 4149.86 2 0.61 2519.57 1001510.6 0.26 600 Siltstone 4151.86 4 0.62 2575.39 1571504.2 0.26 1500 CleanSandstone 4155.86 2 0.6 2514.9 1267177.7 0.26 600 Shale 4157.86 2 0.66 2732.37 2789765.8 0.25 2500 Siltstone 4159.86 2 0.62 2567.25 1409418.9 0.26 1500 Shale 4161.86 2.1 0.66 2735.03 2789765.8 0.25 2500 DirtySandstone 4163.96 4 0.61 2541.24 1435306.6 0.26 1500 Siltstone 4167.96 4 0.62 2593.72 1765617.4 0.26 2500 DirtySandstone 4171.96 4 0.61 2562.81 1435651.3 0.26 1500 CleanSandstone 4175.96 2.1 0.59 2468.61 935658.3 0.26 2500 Siltstone 4178.06 4 0.62 2600 1491142.7 0.26 1500 Shale 4182.06 2 0.66 2748.27 2789765.8 0.25 2500 DirtySandstone 4184.06 11 0.62 2584.96 1462838 0.26 1500 Shale 4195.06 27 0.65 2743.98 2560999.9 0.25 2500 Siltstone 4222.06 2 0.63 2677.42 1857874.8 0.26 1500 Shale 4224.06 10 0.66 2774.26 2552268.6 0.25 2500 Attachment K- NDB-027 Page 39 of 113 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 4234.06 2 0.63 2655.38 1509543.6 0.26 1500 Shale 4236.06 4.1 0.64 2712.39 2349461.1 0.25 2500 Siltstone 4240.16 2 0.64 2697.38 1482677.8 0.25 1500 Shale 4242.16 96.4 0.65 2801.61 2604074 0.25 2500 DirtySandstone 4338.56 2 0.61 2647.13 1153391 0.26 1500 Shale 4340.56 38.2 0.66 2855.58 2733692 0.25 2500 Siltstone 4378.76 2 0.62 2719.83 1526263.4 0.26 1500 Shale 4380.76 46.2 0.66 2884.53 2704369.9 0.25 2500 Siltstone 4426.96 2 0.64 2811.75 1825853.3 0.25 1500 Shale 4428.96 9.84 0.65 2895.32 2657615 0.25 2500 Attachment K- NDB-027 Page 40 of 113 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 15750 375 9.38 2 1 PPA Scour 40 YF126ST 2414.7 60 CarboLite 40/70 1 2414.7 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120 CarboLite 40/70 3 13372.5 3 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20- SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20- SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20- SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20- SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20- SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 33.8 29.36 Attachment K- NDB-027 Page 41 of 113 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 73134 249856.8 2005 50.12 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 6 MD: [24118, 24124] 7618.8 psi 354.56 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4008.82 4363.38 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 6 MD: [24118, 24124] 997.79 290.7 0.36 Attachment K- NDB-027 Page 42 of 113 Stage 7 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 7 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7487.8 psi 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 4010 35.72 0.7 2819.5 2786554.2 0.25 2500 Shale 4045.72 26.74 0.66 2666.82 2786554.2 0.25 2500 Top 3.2 NAN CS 4072.46 3.6 0.6 2464.93 1159218.9 0.26 600 Siltstone 4076.06 1.8 0.62 2515.48 1629236.3 0.26 1500 CleanSandstone 4077.86 1.8 0.6 2451.33 979798.8 0.26 600 Siltstone 4079.66 3.6 0.61 2473.36 1350455.1 0.26 1500 CleanSandstone 4083.26 3.6 0.61 2491.89 1206390.9 0.26 600 Siltstone 4086.86 3.6 0.61 2481.82 1313860.7 0.26 1500 CleanSandstone 4090.46 7.2 0.61 2485.09 1266403.2 0.26 600 Attachment K- NDB-027 Page 43 of 113 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 4097.66 1.8 0.61 2483.73 1082935.6 0.26 1500 DirtySandstone 4099.46 1.8 0.62 2554.52 1222900.8 0.26 600 Shale 4101.26 1.8 0.62 2559.75 1419038.4 0.26 2500 DirtySandstone 4103.06 1.8 0.62 2523.94 1403385.6 0.26 600 Siltstone 4104.86 9 0.62 2539.58 1402756.3 0.26 1500 Shale 4113.86 3.6 0.66 2695.76 2181052.3 0.25 2500 DirtySandstone 4117.46 5.4 0.62 2558.62 1662780.4 0.26 1500 Siltstone 4122.86 1.8 0.63 2589.72 1963674.5 0.26 2500 DirtySandstone 4124.66 3.7 0.62 2566.69 1742901.7 0.26 1500 Siltstone 4128.36 5.4 0.63 2602.57 1681056.2 0.26 2500 Siltstone 4133.76 1.8 0.62 2571.76 1561073 0.26 1500 DirtySandstone 4135.56 1.8 0.62 2556.33 1262913.1 0.26 2500 Siltstone 4137.36 3.6 0.63 2615.95 1816969.7 0.26 1500 Shale 4140.96 11 0.65 2678.61 2238744.4 0.25 2500 CleanSandstone 4151.96 2 0.61 2520.85 1001510.6 0.26 600 Siltstone 4153.96 4 0.62 2576.7 1571504.2 0.26 1500 Attachment K- NDB-027 Page 44 of 113 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) CleanSandstone 4157.96 2 0.6 2516.17 1267177.7 0.26 600 Shale 4159.96 2 0.66 2733.75 2789765.8 0.25 2500 Siltstone 4161.96 2 0.62 2568.55 1409418.9 0.26 1500 Shale 4163.96 2.1 0.66 2736.41 2789765.8 0.25 2500 DirtySandstone 4166.06 4 0.61 2542.52 1435306.6 0.26 1500 Siltstone 4170.06 4 0.62 2595.02 1765617.4 0.26 2500 DirtySandstone 4174.06 4 0.61 2564.1 1435651.3 0.26 1500 CleanSandstone 4178.06 2.1 0.59 2469.85 935658.3 0.26 2500 Siltstone 4180.16 4 0.62 2601.3 1491142.7 0.26 1500 Shale 4184.16 2 0.66 2749.65 2789765.8 0.25 2500 DirtySandstone 4186.16 11 0.62 2586.25 1462838 0.26 1500 Shale 4197.16 27 0.65 2745.35 2560999.9 0.25 2500 Siltstone 4224.16 2 0.63 2678.75 1857874.8 0.26 1500 Shale 4226.16 10 0.66 2775.64 2552268.6 0.25 2500 Siltstone 4236.16 2 0.63 2656.7 1509543.6 0.26 1500 Shale 4238.16 4.1 0.64 2713.73 2349461.1 0.25 2500 Attachment K- NDB-027 Page 45 of 113 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 4242.26 2 0.64 2698.71 1482677.8 0.25 1500 Shale 4244.26 96.4 0.65 2802.98 2604074 0.25 2500 DirtySandstone 4340.66 2 0.61 2648.41 1153391 0.26 1500 Shale 4342.66 38.2 0.66 2856.95 2733692 0.25 2500 Siltstone 4380.86 2 0.62 2721.14 1526263.4 0.26 1500 Shale 4382.86 46.2 0.66 2885.9 2704369.9 0.25 2500 Siltstone 4429.06 2 0.64 2813.09 1825853.3 0.25 1500 Shale 4431.06 9.84 0.65 2896.69 2657615 0.25 2500 Attachment K- NDB-027 Page 46 of 113 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 15330 365 9.12 2 1 PPA Scour 40 YF126ST 2414.7 60 CarboLite 40/70 1 2414.7 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120 CarboLite 40/70 3 13372.5 3 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20- SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20- SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20- SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20- SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20- SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 33.42 29 Attachment K- NDB-027 Page 47 of 113 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 72714 249856.8 1995 49.87 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 7 MD: [23575, 23581] 7487.8 psi 354 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 7 MD: [23575, 23581] 996.68 287.4 0.35 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4010.2 4364.2 Attachment K- NDB-027 Page 48 of 113 Stage 8 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 8 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7319.5 psi 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 4020 27.92 0.7 2823.77 2786554.2 0.25 2500 Shale 4047.92 26.74 0.66 2668.27 2786554.2 0.25 2500 Top 3.2 NAN CS 4074.66 3.6 0.6 2466.26 1159218.9 0.26 600 Siltstone 4078.26 1.8 0.62 2516.84 1629236.3 0.26 1500 CleanSandstone 4080.06 1.8 0.6 2452.66 979798.8 0.26 600 Siltstone 4081.86 3.6 0.61 2474.7 1350455.1 0.26 1500 CleanSandstone 4085.46 3.6 0.61 2493.23 1206390.9 0.26 600 Siltstone 4089.06 3.6 0.61 2483.15 1313860.7 0.26 1500 CleanSandstone 4092.66 7.2 0.61 2486.43 1266403.2 0.26 600 Attachment K- NDB-027 Page 49 of 113 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 4099.86 1.8 0.61 2485.06 1082935.6 0.26 1500 DirtySandstone 4101.66 1.8 0.62 2555.89 1222900.8 0.26 600 Shale 4103.46 1.8 0.62 2561.12 1419038.4 0.26 2500 DirtySandstone 4105.26 1.8 0.62 2525.29 1403385.6 0.26 600 Siltstone 4107.06 9 0.62 2540.94 1402756.3 0.26 1500 Shale 4116.06 3.6 0.66 2697.2 2181052.3 0.25 2500 DirtySandstone 4119.66 5.4 0.62 2559.99 1662780.4 0.26 1500 Siltstone 4125.06 1.8 0.63 2591.1 1963674.5 0.26 2500 DirtySandstone 4126.86 3.7 0.62 2568.06 1742901.7 0.26 1500 Siltstone 4130.56 5.4 0.63 2603.95 1681056.2 0.26 2500 Siltstone 4135.96 1.8 0.62 2573.13 1561073 0.26 1500 DirtySandstone 4137.76 1.8 0.62 2557.69 1262913.1 0.26 2500 Siltstone 4139.56 3.6 0.63 2617.34 1816969.7 0.26 1500 Shale 4143.16 11 0.65 2680.03 2238744.4 0.25 2500 CleanSandstone 4154.16 2 0.61 2522.18 1001510.6 0.26 600 Siltstone 4156.16 4 0.62 2578.06 1571504.2 0.26 1500 Attachment K- NDB-027 Page 50 of 113 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) CleanSandstone 4160.16 2 0.6 2517.5 1267177.7 0.26 600 Shale 4162.16 2 0.66 2735.2 2789765.8 0.25 2500 Siltstone 4164.16 2 0.62 2569.9 1409418.9 0.26 1500 Shale 4166.16 2.1 0.66 2737.86 2789765.8 0.25 2500 DirtySandstone 4168.26 4 0.61 2543.86 1435306.6 0.26 1500 Siltstone 4172.26 4 0.62 2596.39 1765617.4 0.26 2500 DirtySandstone 4176.26 4 0.61 2565.45 1435651.3 0.26 1500 CleanSandstone 4180.26 2.1 0.59 2471.15 935658.3 0.26 2500 Siltstone 4182.36 4 0.62 2602.67 1491142.7 0.26 1500 Shale 4186.36 2 0.66 2751.1 2789765.8 0.25 2500 DirtySandstone 4188.36 11 0.62 2587.61 1462838 0.26 1500 Shale 4199.36 27 0.65 2746.78 2560999.9 0.25 2500 Siltstone 4226.36 2 0.63 2680.15 1857874.8 0.26 1500 Shale 4228.36 10 0.66 2777.08 2552268.6 0.25 2500 Siltstone 4238.36 2 0.63 2658.08 1509543.6 0.26 1500 Shale 4240.36 4.1 0.64 2715.14 2349461.1 0.25 2500 Attachment K- NDB-027 Page 51 of 113 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 4244.46 2 0.64 2700.11 1482677.8 0.25 1500 Shale 4246.46 96.4 0.65 2804.41 2604074 0.25 2500 DirtySandstone 4342.86 2 0.61 2649.75 1153391 0.26 1500 Shale 4344.86 38.2 0.66 2858.39 2733692 0.25 2500 Siltstone 4383.06 2 0.62 2722.5 1526263.4 0.26 1500 Shale 4385.06 46.2 0.66 2887.34 2704369.9 0.25 2500 Siltstone 4431.26 2 0.64 2814.49 1825853.3 0.25 1500 Shale 4433.26 9.84 0.65 2898.13 2657615 0.25 2500 Attachment K- NDB-027 Page 52 of 113 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 15120 360 9 2 1 PPA Scour 40 YF126ST 1610 40 CarboLite 40/70 1 1610 1 3 3 PPA Scour 40 YF126ST 2971.6 80 CarboLite 40/70 3 8914.8 2 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20- SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20- SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20- SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20- SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20- SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 31.05 26.9 Attachment K- NDB-027 Page 53 of 113 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 70213.4 244594.4 1930 48.25 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 8 MD: [23032, 23038] 7319.5 349.88 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4013.79 4363.67 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 8 MD: [23032, 23038] 978.39 281.77 0.37 ` Attachment K- NDB-027 Page 54 of 113 Stage 9 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 9 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 6000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7144.5 psi 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 4020 28.92 0.7 2824.12 2786554.2 0.25 2500 Shale 4048.92 26.74 0.66 2668.92 2786554.2 0.25 2500 Top 3.2 NAN CS 4075.66 3.6 0.6 2466.86 1159218.9 0.26 600 Siltstone 4079.26 1.8 0.62 2517.46 1629236.3 0.26 1500 CleanSandstone 4081.06 1.8 0.6 2453.26 979798.8 0.26 600 Siltstone 4082.86 3.6 0.61 2475.3 1350455.1 0.26 1500 CleanSandstone 4086.46 3.6 0.61 2493.84 1206390.9 0.26 600 Siltstone 4090.06 3.6 0.61 2483.76 1313860.7 0.26 1500 CleanSandstone 4093.66 7.2 0.61 2487.04 1266403.2 0.26 600 Attachment K- NDB-027 Page 55 of 113 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 4100.86 1.8 0.61 2485.67 1082935.6 0.26 1500 DirtySandstone 4102.66 1.8 0.62 2556.52 1222900.8 0.26 600 Shale 4104.46 1.8 0.62 2561.74 1419038.4 0.26 2500 DirtySandstone 4106.26 1.8 0.62 2525.9 1403385.6 0.26 600 Siltstone 4108.06 9 0.62 2541.56 1402756.3 0.26 1500 Shale 4117.06 3.6 0.66 2697.85 2181052.3 0.25 2500 DirtySandstone 4120.66 5.4 0.62 2560.61 1662780.4 0.26 1500 Siltstone 4126.06 1.8 0.63 2591.73 1963674.5 0.26 2500 DirtySandstone 4127.86 3.7 0.62 2568.68 1742901.7 0.26 1500 Siltstone 4131.56 5.4 0.63 2604.58 1681056.2 0.26 2500 Siltstone 4136.96 1.8 0.62 2573.75 1561073 0.26 1500 DirtySandstone 4138.76 1.8 0.62 2558.31 1262913.1 0.26 2500 Siltstone 4140.56 3.6 0.63 2617.97 1816969.7 0.26 1500 Shale 4144.16 11 0.65 2680.68 2238744.4 0.25 2500 CleanSandstone 4155.16 2 0.61 2522.79 1001510.6 0.26 600 Siltstone 4157.16 4 0.62 2578.68 1571504.2 0.26 1500 Attachment K- NDB-027 Page 56 of 113 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) CleanSandstone 4161.16 2 0.6 2518.11 1267177.7 0.26 600 Shale 4163.16 2 0.66 2735.85 2789765.8 0.25 2500 Siltstone 4165.16 2 0.62 2570.52 1409418.9 0.26 1500 Shale 4167.16 2.1 0.66 2738.51 2789765.8 0.25 2500 DirtySandstone 4169.26 4 0.61 2544.47 1435306.6 0.26 1500 Siltstone 4173.26 4 0.62 2597.01 1765617.4 0.26 2500 DirtySandstone 4177.26 4 0.61 2566.07 1435651.3 0.26 1500 CleanSandstone 4181.26 2.1 0.59 2471.75 935658.3 0.26 2500 Siltstone 4183.36 4 0.62 2603.29 1491142.7 0.26 1500 Shale 4187.36 2 0.66 2751.75 2789765.8 0.25 2500 DirtySandstone 4189.36 11 0.62 2588.23 1462838 0.26 1500 Shale 4200.36 27 0.65 2747.44 2560999.9 0.25 2500 Siltstone 4227.36 2 0.63 2680.78 1857874.8 0.26 1500 Shale 4229.36 10 0.66 2777.74 2552268.6 0.25 2500 Siltstone 4239.36 2 0.63 2658.71 1509543.6 0.26 1500 Shale 4241.36 4.1 0.64 2715.78 2349461.1 0.25 2500 Attachment K- NDB-027 Page 57 of 113 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 4245.46 2 0.64 2700.75 1482677.8 0.25 1500 Shale 4247.46 96.4 0.65 2805.07 2604074 0.25 2500 DirtySandstone 4343.86 2 0.61 2650.36 1153391 0.26 1500 Shale 4345.86 38.2 0.66 2859.05 2733692 0.25 2500 Siltstone 4384.06 2 0.62 2723.12 1526263.4 0.26 1500 Shale 4386.06 46.2 0.66 2888 2704369.9 0.25 2500 Siltstone 4432.26 2 0.64 2815.12 1825853.3 0.25 1500 Shale 4434.26 9.84 0.65 2898.78 2657615 0.25 2500 Attachment K- NDB-027 Page 58 of 113 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 14700 350 8.75 2 1 PPA Scour 40 YF126ST 1610 40 CarboLite 40/70 1 1610 1 3 3 PPA Scour 40 YF126ST 2971.6 80 CarboLite 40/70 3 8914.8 2 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20- SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20- SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20- SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20- SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20- SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 30.64 26.51 Attachment K- NDB-027 Page 59 of 113 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 69793.4 244594.4 1920 48 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 9 MD: [22486, 22492] 7144.5 psi 349.76 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4014.81 4364.57 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 9 MD: [22486, 22492] 933.42 280.46 0.38 Attachment K- NDB-027 Page 60 of 113 Stage 10 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 10 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 7014 psi 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 4010 42.02 0.7 2821.71 2786554.2 0.25 2500 Shale 4052.02 26.74 0.66 2670.96 2786554.2 0.25 2500 Top 3.2 NAN CS 4078.76 3.6 0.6 2468.74 1159218.9 0.26 600 Siltstone 4082.36 1.8 0.62 2519.37 1629236.3 0.26 1500 CleanSandstone 4084.16 1.8 0.6 2455.12 979798.8 0.26 600 Siltstone 4085.96 3.6 0.61 2477.18 1350455.1 0.26 1500 CleanSandstone 4089.56 3.6 0.61 2495.73 1206390.9 0.26 600 Siltstone 4093.16 3.6 0.61 2485.64 1313860.7 0.26 1500 CleanSandstone 4096.76 7.2 0.61 2488.92 1266403.2 0.26 600 Attachment K- NDB-027 Page 61 of 113 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 4103.96 1.8 0.61 2487.55 1082935.6 0.26 1500 DirtySandstone 4105.76 1.8 0.62 2558.45 1222900.8 0.26 600 Shale 4107.56 1.8 0.62 2563.68 1419038.4 0.26 2500 DirtySandstone 4109.36 1.8 0.62 2527.81 1403385.6 0.26 600 Siltstone 4111.16 9 0.62 2543.48 1402756.3 0.26 1500 Shale 4120.16 3.6 0.66 2699.88 2181052.3 0.25 2500 DirtySandstone 4123.76 5.4 0.62 2562.53 1662780.4 0.26 1500 Siltstone 4129.16 1.8 0.63 2593.68 1963674.5 0.26 2500 DirtySandstone 4130.96 3.7 0.62 2570.61 1742901.7 0.26 1500 Siltstone 4134.66 5.4 0.63 2606.54 1681056.2 0.26 2500 Siltstone 4140.06 1.8 0.62 2575.68 1561073 0.26 1500 DirtySandstone 4141.86 1.8 0.62 2560.23 1262913.1 0.26 2500 Siltstone 4143.66 3.6 0.63 2619.93 1816969.7 0.26 1500 Shale 4147.26 11 0.65 2682.68 2238744.4 0.25 2500 CleanSandstone 4158.26 2 0.61 2524.67 1001510.6 0.26 600 Siltstone 4160.26 4 0.62 2580.6 1571504.2 0.26 1500 Attachment K- NDB-027 Page 62 of 113 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) CleanSandstone 4164.26 2 0.6 2519.98 1267177.7 0.26 600 Shale 4166.26 2 0.66 2737.89 2789765.8 0.25 2500 Siltstone 4168.26 2 0.62 2572.43 1409418.9 0.26 1500 Shale 4170.26 2.1 0.66 2740.55 2789765.8 0.25 2500 DirtySandstone 4172.36 4 0.61 2546.36 1435306.6 0.26 1500 Siltstone 4176.36 4 0.62 2598.94 1765617.4 0.26 2500 DirtySandstone 4180.36 4 0.61 2567.97 1435651.3 0.26 1500 CleanSandstone 4184.36 2.1 0.59 2473.58 935658.3 0.26 2500 Siltstone 4186.46 4 0.62 2605.22 1491142.7 0.26 1500 Shale 4190.46 2 0.66 2753.79 2789765.8 0.25 2500 DirtySandstone 4192.46 11 0.62 2590.14 1462838 0.26 1500 Shale 4203.46 27 0.65 2749.46 2560999.9 0.25 2500 Siltstone 4230.46 2 0.63 2682.75 1857874.8 0.26 1500 Shale 4232.46 10 0.66 2779.77 2552268.6 0.25 2500 Siltstone 4242.46 2 0.63 2660.65 1509543.6 0.26 1500 Shale 4244.46 4.1 0.64 2717.77 2349461.1 0.25 2500 Attachment K- NDB-027 Page 63 of 113 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 4248.56 2 0.64 2702.72 1482677.8 0.25 1500 Shale 4250.56 96.4 0.65 2807.09 2604074 0.25 2500 DirtySandstone 4346.96 2 0.61 2652.26 1153391 0.26 1500 Shale 4348.96 38.2 0.66 2861.08 2733692 0.25 2500 Siltstone 4387.16 2 0.62 2725.05 1526263.4 0.26 1500 Shale 4389.16 46.2 0.66 2890.03 2704369.9 0.25 2500 Siltstone 4435.36 2 0.64 2817.09 1825853.3 0.25 1500 Shale 4437.36 9.84 0.65 2900.81 2657615 0.25 2500 Attachment K- NDB-027 Page 64 of 113 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 14280 340 8.5 2 1 PPA Scour 40 YF126ST 1610 40 CarboLite 40/70 1 1610 1 3 3 PPA Scour 40 YF126ST 2971.6 80 CarboLite 40/70 3 8914.8 2 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20- SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20- SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20- SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20- SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20- SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 30.22 26.13 Attachment K- NDB-027 Page 65 of 113 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 69373.4 244594.4 1910 47.75 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 10 MD: [21944, 21950] 7014 349.7 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4016.99 4366.69 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 10 MD: [21944, 21950] 973.86 289.1 0.37 Attachment K- NDB-027 Page 66 of 113 Stage 11 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 11 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6846.4 psi 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 4020 35.82 0.7 2826.54 2786554.2 0.25 2500 Shale 4055.82 26.74 0.66 2673.46 2786554.2 0.25 2500 Top 3.2 NAN CS 4082.56 3.6 0.6 2471.04 1159218.9 0.26 600 Siltstone 4086.16 1.8 0.62 2521.72 1629236.3 0.26 1500 CleanSandstone 4087.96 1.8 0.6 2457.4 979798.8 0.26 600 Siltstone 4089.76 3.6 0.61 2479.49 1350455.1 0.26 1500 CleanSandstone 4093.36 3.6 0.61 2498.05 1206390.9 0.26 600 Siltstone 4096.96 3.6 0.61 2487.95 1313860.7 0.26 1500 Attachment K- NDB-027 Page 67 of 113 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) CleanSandstone 4100.56 7.2 0.61 2491.23 1266403.2 0.26 600 Siltstone 4107.76 1.8 0.61 2489.85 1082935.6 0.26 1500 DirtySandstone 4109.56 1.8 0.62 2560.82 1222900.8 0.26 600 Shale 4111.36 1.8 0.62 2566.05 1419038.4 0.26 2500 DirtySandstone 4113.16 1.8 0.62 2530.15 1403385.6 0.26 600 Siltstone 4114.96 9 0.62 2545.83 1402756.3 0.26 1500 Shale 4123.96 3.6 0.66 2702.37 2181052.3 0.25 2500 DirtySandstone 4127.56 5.4 0.62 2564.89 1662780.4 0.26 1500 Siltstone 4132.96 1.8 0.63 2596.06 1963674.5 0.26 2500 DirtySandstone 4134.76 3.7 0.62 2572.97 1742901.7 0.26 1500 Siltstone 4138.46 5.4 0.63 2608.93 1681056.2 0.26 2500 Siltstone 4143.86 1.8 0.62 2578.04 1561073 0.26 1500 DirtySandstone 4145.66 1.8 0.62 2562.57 1262913.1 0.26 2500 Siltstone 4147.46 3.6 0.63 2622.33 1816969.7 0.26 1500 Shale 4151.06 11 0.65 2685.14 2238744.4 0.25 2500 CleanSandstone 4162.06 2 0.61 2526.98 1001510.6 0.26 600 Attachment K- NDB-027 Page 68 of 113 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 4164.06 4 0.62 2582.96 1571504.2 0.26 1500 CleanSandstone 4168.06 2 0.6 2522.28 1267177.7 0.26 600 Shale 4170.06 2 0.66 2740.39 2789765.8 0.25 2500 Siltstone 4172.06 2 0.62 2574.78 1409418.9 0.26 1500 Shale 4174.06 2.1 0.66 2743.05 2789765.8 0.25 2500 DirtySandstone 4176.16 4 0.61 2548.68 1435306.6 0.26 1500 Siltstone 4180.16 4 0.62 2601.3 1765617.4 0.26 2500 DirtySandstone 4184.16 4 0.61 2570.3 1435651.3 0.26 1500 CleanSandstone 4188.16 2.1 0.59 2475.82 935658.3 0.26 2500 Siltstone 4190.26 4 0.62 2607.59 1491142.7 0.26 1500 Shale 4194.26 2 0.66 2756.29 2789765.8 0.25 2500 DirtySandstone 4196.26 11 0.62 2592.49 1462838 0.26 1500 Shale 4207.26 27 0.65 2751.94 2560999.9 0.25 2500 Siltstone 4234.26 2 0.63 2685.15 1857874.8 0.26 1500 Shale 4236.26 10 0.66 2782.27 2552268.6 0.25 2500 Siltstone 4246.26 2 0.63 2663.03 1509543.6 0.26 1500 Attachment K- NDB-027 Page 69 of 113 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 4248.26 4.1 0.64 2720.2 2349461.1 0.25 2500 Siltstone 4252.36 2 0.64 2705.14 1482677.8 0.25 1500 Shale 4254.36 96.4 0.65 2809.57 2604074 0.25 2500 DirtySandstone 4350.76 2 0.61 2654.57 1153391 0.26 1500 Shale 4352.76 38.2 0.66 2863.57 2733692 0.25 2500 Siltstone 4390.96 2 0.62 2727.41 1526263.4 0.26 1500 Shale 4392.96 46.2 0.66 2892.52 2704369.9 0.25 2500 Siltstone 4439.16 2 0.64 2819.5 1825853.3 0.25 1500 Shale 4441.16 9.84 0.65 2903.29 2657615 0.25 2500 Attachment K- NDB-027 Page 70 of 113 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 14070 335 8.37 2 1 PPA Scour 40 YF126ST 1610 40 CarboLite 40/70 1 1610 1 3 3 PPA Scour 40 YF126ST 2971.6 80 CarboLite 40/70 3 8914.8 2 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20- SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20- SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20- SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20- SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20- SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 30 25.94 Attachment K- NDB-027 Page 71 of 113 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 69163.4 244594.4 1905 47.63 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 11 MD: [21399, 21405] 6846.4 349.21 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4021.27 4370.48 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 11 MD: [21399, 21405] 971.79 289.96 0.37 Attachment K- NDB-027 Page 72 of 113 Stage 12 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 12 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 6000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6672 psi 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 4020 38.82 0.7 2827.59 2786554.2 0.25 2500 Shale 4058.82 26.74 0.66 2675.43 2786554.2 0.25 2500 Top 3.2 NAN CS 4085.56 3.6 0.6 2472.85 1159218.9 0.26 600 Siltstone 4089.16 1.8 0.62 2523.57 1629236.3 0.26 1500 CleanSandstone 4090.96 1.8 0.6 2459.21 979798.8 0.26 600 Siltstone 4092.76 3.6 0.61 2481.3 1350455.1 0.26 1500 CleanSandstone 4096.36 3.6 0.61 2499.88 1206390.9 0.26 600 Siltstone 4099.96 3.6 0.61 2489.77 1313860.7 0.26 1500 Attachment K- NDB-027 Page 73 of 113 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) CleanSandstone 4103.56 7.2 0.61 2493.05 1266403.2 0.26 600 Siltstone 4110.76 1.8 0.61 2491.67 1082935.6 0.26 1500 DirtySandstone 4112.56 1.8 0.62 2562.69 1222900.8 0.26 600 Shale 4114.36 1.8 0.62 2567.92 1419038.4 0.26 2500 DirtySandstone 4116.16 1.8 0.62 2531.99 1403385.6 0.26 600 Siltstone 4117.96 9 0.62 2547.68 1402756.3 0.26 1500 Shale 4126.96 3.6 0.66 2704.34 2181052.3 0.25 2500 DirtySandstone 4130.56 5.4 0.62 2566.75 1662780.4 0.26 1500 Siltstone 4135.96 1.8 0.63 2597.95 1963674.5 0.26 2500 DirtySandstone 4137.76 3.7 0.62 2574.84 1742901.7 0.26 1500 Siltstone 4141.46 5.4 0.63 2610.82 1681056.2 0.26 2500 Siltstone 4146.86 1.8 0.62 2579.91 1561073 0.26 1500 DirtySandstone 4148.66 1.8 0.62 2564.43 1262913.1 0.26 2500 Siltstone 4150.46 3.6 0.63 2624.23 1816969.7 0.26 1500 Shale 4154.06 11 0.65 2687.08 2238744.4 0.25 2500 CleanSandstone 4165.06 2 0.61 2528.8 1001510.6 0.26 600 Attachment K- NDB-027 Page 74 of 113 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 4167.06 4 0.62 2584.82 1571504.2 0.26 1500 CleanSandstone 4171.06 2 0.6 2524.1 1267177.7 0.26 600 Shale 4173.06 2 0.66 2742.36 2789765.8 0.25 2500 Siltstone 4175.06 2 0.62 2576.63 1409418.9 0.26 1500 Shale 4177.06 2.1 0.66 2745.02 2789765.8 0.25 2500 DirtySandstone 4179.16 4 0.61 2550.51 1435306.6 0.26 1500 Siltstone 4183.16 4 0.62 2603.17 1765617.4 0.26 2500 DirtySandstone 4187.16 4 0.61 2572.14 1435651.3 0.26 1500 CleanSandstone 4191.16 2.1 0.59 2477.6 935658.3 0.26 2500 Siltstone 4193.26 4 0.62 2609.45 1491142.7 0.26 1500 Shale 4197.26 2 0.66 2758.26 2789765.8 0.25 2500 DirtySandstone 4199.26 11 0.62 2594.34 1462838 0.26 1500 Shale 4210.26 27 0.65 2753.89 2560999.9 0.25 2500 Siltstone 4237.26 2 0.63 2687.06 1857874.8 0.26 1500 Shale 4239.26 10 0.66 2784.23 2552268.6 0.25 2500 Siltstone 4249.26 2 0.63 2664.91 1509543.6 0.26 1500 Attachment K- NDB-027 Page 75 of 113 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 4251.26 4.1 0.64 2722.12 2349461.1 0.25 2500 Siltstone 4255.36 2 0.64 2707.04 1482677.8 0.25 1500 Shale 4257.36 96.4 0.65 2811.53 2604074 0.25 2500 DirtySandstone 4353.76 2 0.61 2656.4 1153391 0.26 1500 Shale 4355.76 38.2 0.66 2865.53 2733692 0.25 2500 Siltstone 4393.96 2 0.62 2729.27 1526263.4 0.26 1500 Shale 4395.96 46.2 0.66 2894.48 2704369.9 0.25 2500 Siltstone 4442.16 2 0.64 2821.41 1825853.3 0.25 1500 Shale 4444.16 9.84 0.65 2905.25 2657615 0.25 2500 Attachment K- NDB-027 Page 76 of 113 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 13650 325 8.12 2 1 PPA Scour 40 YF126ST 2414.7 60 CarboLite 40/70 1 2414.7 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120 CarboLite 40/70 3 13372.5 3 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20- SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20- SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20- SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20- SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20- SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 31.85 27.55 Attachment K- NDB-027 Page 77 of 113 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 71034 249856.8 1955 48.87 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 12 MD: [20855, 20861] 6672 352.42 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4023.63 4376.05 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 12 MD: [20855, 20861] 984.29 285.96 0.37 Attachment K- NDB-027 Page 78 of 113 Stage 13 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 13 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6586.7 psi 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 4056.76 10 0.73 2971.97 1461000.3 0.22 2500 Shale 4066.77 15 0.7 2831.57 1762000.5 0.22 2500 Nanushuk 3 SS 4081.76 15.3 0.68 2772.69 1898000.5 0.22 2000 Top Nan 4097.08 6 0.65 2661.15 838900.2 0.27 1000 Shale 4103.08 2 0.7 2891.76 2665000.7 0.23 2500 Nan DS 4105.09 1.5 0.64 2614.6 819400.2 0.27 1500 Nan DS 4106.56 2 0.64 2645.92 1222000.3 0.26 1500 Nan CS 4108.56 13 0.63 2592.26 869100.2 0.27 1000 Attachment K- NDB-027 Page 79 of 113 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 4121.59 1.5 0.61 2526.99 1002000.3 0.27 1000 Nan CS 4123.06 4 0.65 2661.01 706600.2 0.28 1000 Nan CS 4127.07 9 0.61 2507.85 1166000.3 0.27 1000 Nan CS 4136.06 7 0.65 2690.16 769000.2 0.27 1000 Nan CS 4143.08 5.5 0.62 2572.82 1278000.4 0.26 1000 Nan CS 4148.56 13 0.65 2696.11 691700.2 0.28 1000 Nan DS 4161.58 2.5 0.68 2849.85 1748000.4 0.26 1500 Nan DS 4164.07 12.5 0.64 2652.31 1111000.3 0.27 1500 Nan DS 4176.57 4 0.7 2924.54 1692000.4 0.26 1500 Nan DS 4180.58 2.5 0.65 2706.11 822100.2 0.27 1500 Shale 4183.07 2 0.7 2916.27 2665000.7 0.23 2500 Nan DS 4185.07 4 0.65 2713.22 1159000.3 0.27 1500 Nan DS 4189.07 4 0.63 2627.79 838300.2 0.27 1000 Shale 4193.08 4 0.7 2954.85 2665000.7 0.23 2500 Nan DS 4197.08 6 0.65 2712.93 1133000.3 0.27 1500 Shale 4203.08 2 0.7 2930.2 2665000.7 0.23 2500 Attachment K- NDB-027 Page 80 of 113 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4205.09 2 0.63 2644.18 1078000.3 0.27 1500 Nan DS 4207.09 6.5 0.67 2813.01 1694000.4 0.26 1500 Nan DS 4213.58 4 0.62 2605.6 898500.2 0.27 1500 Nan DS 4217.59 3.5 0.65 2742.23 929100.3 0.27 1500 Shale 4221.06 2 0.7 2942.67 2665000.7 0.23 2500 Nan DS 4223.06 12.5 0.65 2728.89 1562000.4 0.26 1500 Nan DS 4235.56 2 0.66 2778.49 1397000.4 0.26 1500 Shale 4237.57 2 0.7 2954.27 2665000.7 0.23 2500 Nan DS 4239.57 2 0.65 2760.65 1242000.3 0.26 1500 Shale 4241.57 8 0.69 2925.12 2665000.7 0.23 2500 Nan DS 4249.57 2 0.64 2720.76 932500.2 0.27 1500 Shale 4251.57 4 0.7 2964.72 2665000.7 0.23 2500 Nan DS 4255.58 6 0.65 2750.93 1427000.4 0.26 1500 Shale 4261.58 8 0.7 2973.13 2665000.7 0.23 2500 Nan DS 4269.59 6.5 0.65 2797.49 1469000.4 0.26 1500 Shale 4276.08 6 0.69 2948.33 2665000.7 0.23 2500 Attachment K- NDB-027 Page 81 of 113 Zone Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Gradient (psi/ft) Min. Stress (psi) Youngs Modulus (psi) Poissons Ratio Toughness (psi.in0.5) Nan DS 4282.09 2 0.64 2756.88 838400.2 0.27 1000 Shale 4284.09 2 0.7 2986.76 2665000.7 0.23 2500 Nan DS 4286.06 4 0.65 2787.34 1469000.4 0.26 1500 Shale 4290.06 2 0.7 2990.82 2665000.7 0.23 2500 Nan DS 4292.06 6 0.67 2881.17 1545000.4 0.26 1500 Shale 4298.06 12 0.7 2999.96 2665000.7 0.23 2500 Nan DS 4310.07 2.5 0.65 2785.01 1214000.3 0.27 1500 Shale 4312.57 20 0.69 2978.2 2665000.7 0.23 2500 Attachment K- NDB-027 Page 82 of 113 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 13440 320 8 2 1 PPA Scour 40 YF126ST 2414.7 60 CarboLite 40/70 1 2414.7 1.5 3 3 PPA Scour 40 YF126ST 4457.5 120 CarboLite 40/70 3 13372.5 3 4 Resume PAD 40 YF126ST 2100 50 1.25 5 1 PPA 40 YF126ST 8043 200 CarboLite 16/20- SG 1 8043 5 6 2 PPA 40 YF126ST 8679.6 225 CarboLite 16/20- SG 2 17359.2 5.63 7 4 PPA 40 YF126ST 9808.7 275 CarboLite 16/20- SG 4 39234.8 6.87 8 6 PPA 40 YF126ST 8623.7 260 CarboLite 16/20- SG 6 51742.2 6.5 9 8 PPA 40 YF126ST 7438.8 240 CarboLite 16/20- SG 8 59510.4 6 10 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 31.64 27.37 Attachment K- NDB-027 Page 83 of 113 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 70824 249856.8 1950 48.75 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 13 MD: [20312, 20318] 6586.7 223.79 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4063.31 4287.1 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 13 MD: [20312, 20318] 896.29 177.58 0.43 Attachment K- NDB-027 Page 84 of 113 Stage 14 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 14 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6692 psi 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 4058.79 10 0.73 2973.42 1461000.3 0.22 2500 Shale 4068.8 15 0.7 2833.02 1762000.5 0.22 2500 Nanushuk 3 SS 4083.79 15.3 0.68 2773.99 1898000.5 0.22 2000 Top Nan 4099.11 6 0.65 2662.46 838900.2 0.27 1000 Shale 4105.12 2 0.7 2893.21 2665000.7 0.23 2500 Nan DS 4107.12 1.5 0.64 2615.9 819400.2 0.27 1500 Nan DS 4108.6 2 0.64 2647.23 1222000.3 0.26 1500 Nan CS 4110.6 13 0.63 2593.56 869100.2 0.27 1000 Attachment K- NDB-027 Page 85 of 113 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 4123.62 1.5 0.61 2528.3 1002000.3 0.27 1000 Nan CS 4125.1 4 0.65 2662.31 706600.2 0.28 1000 Nan CS 4129.1 9 0.61 2509.01 1166000.3 0.27 1000 Nan CS 4138.09 7 0.65 2691.47 769000.2 0.27 1000 Nan CS 4145.11 5.5 0.62 2573.98 1278000.4 0.26 1000 Nan CS 4150.59 13 0.65 2697.41 691700.2 0.28 1000 Nan DS 4163.62 2.5 0.68 2851.3 1748000.4 0.26 1500 Nan DS 4166.11 12.5 0.64 2653.61 1111000.3 0.27 1500 Nan DS 4178.61 4 0.7 2925.99 1692000.4 0.26 1500 Nan DS 4182.61 2.5 0.65 2707.42 822100.2 0.27 1500 Shale 4185.1 2 0.7 2917.72 2665000.7 0.23 2500 Nan DS 4187.11 4 0.65 2714.53 1159000.3 0.27 1500 Nan DS 4191.11 4 0.63 2629.1 838300.2 0.27 1000 Shale 4195.11 4 0.7 2956.16 2665000.7 0.23 2500 Nan DS 4199.11 6 0.65 2714.24 1133000.3 0.27 1500 Shale 4205.12 2 0.7 2931.65 2665000.7 0.23 2500 Attachment K- NDB-027 Page 86 of 113 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 4207.12 2 0.63 2645.49 1078000.3 0.27 1500 Nan DS 4209.12 6.5 0.67 2814.46 1694000.4 0.26 1500 Nan DS 4215.62 4 0.62 2606.91 898500.2 0.27 1500 Nan DS 4219.62 3.5 0.65 2743.53 929100.3 0.27 1500 Shale 4223.1 2 0.7 2944.12 2665000.7 0.23 2500 Nan DS 4225.1 12.5 0.65 2730.19 1562000.4 0.26 1500 Nan DS 4237.6 2 0.66 2779.79 1397000.4 0.26 1500 Shale 4239.6 2 0.7 2955.58 2665000.7 0.23 2500 Nan DS 4241.6 2 0.65 2761.95 1242000.3 0.26 1500 Shale 4243.6 8 0.69 2926.57 2665000.7 0.23 2500 Nan DS 4251.61 2 0.64 2722.07 932500.2 0.27 1500 Shale 4253.61 4 0.7 2966.17 2665000.7 0.23 2500 Nan DS 4257.61 6 0.65 2752.24 1427000.4 0.26 1500 Shale 4263.62 8 0.7 2974.58 2665000.7 0.23 2500 Nan DS 4271.62 6.5 0.65 2798.79 1469000.4 0.26 1500 Shale 4278.12 6 0.69 2949.63 2665000.7 0.23 2500 Attachment K- NDB-027 Page 87 of 113 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 4284.12 2 0.64 2758.18 838400.2 0.27 1000 Shale 4286.12 2 0.7 2988.21 2665000.7 0.23 2500 Nan DS 4288.09 4 0.65 2788.64 1469000.4 0.26 1500 Shale 4292.09 2 0.7 2992.27 2665000.7 0.23 2500 Nan DS 4294.09 6 0.67 2882.48 1545000.4 0.26 1500 Shale 4300.1 12 0.7 3001.41 2665000.7 0.23 2500 Nan DS 4312.11 2.5 0.65 2786.32 1214000.3 0.27 1500 Shale 4314.6 20 0.69 2979.66 2665000.7 0.23 2500 Attachment K- NDB-027 Page 88 of 113 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 15960 380 9.5 2 1 PPA 40 YF126ST 8244 205 CarboLite 16/20- SG 1 8244 5.12 3 3 PPA 40 YF126ST 7598.2 205 CarboLite 16/20- SG 3 22794.6 5.12 4 5 PPA 40 YF126ST 8077.6 235 CarboLite 16/20- SG 5 40388 5.88 5 7 PPA 40 YF126ST 7530.6 235 CarboLite 16/20- SG 7 52714.2 5.88 6 9 PPA 40 YF126ST 6302.5 210 CarboLite 16/20- SG 9 56722.5 5.25 7 11 PPA 40 YF126ST 5079.9 180 CarboLite 16/20- SG 11 55878.9 4.5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 27.15 23.03 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 58792.8 236742.2 1649.99 41.25 Attachment K- NDB-027 Page 89 of 113 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 14 MD: [19768, 19774] 6692 210.34 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4066.12 4276.46 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 14 MD: [19768, 19774] 832.12 163.54 0.46 Attachment K- NDB-027 Page 90 of 113 Stage 15 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 15 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6588.6 psi 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 4060.76 10 0.73 2974.87 1461000.3 0.22 2500 Shale 4070.77 15 0.7 2834.47 1762000.5 0.22 2500 Nanushuk 3 SS 4085.76 15.3 0.68 2775.3 1898000.5 0.22 2000 Top Nan 4101.08 6 0.65 2663.76 838900.2 0.27 1000 Shale 4107.09 2 0.7 2894.66 2665000.7 0.23 2500 Nan DS 4109.09 1.5 0.64 2617.06 819400.2 0.27 1500 Nan DS 4110.56 2 0.64 2648.53 1222000.3 0.26 1500 Nan CS 4112.57 13 0.63 2594.73 869100.2 0.27 1000 Attachment K- NDB-027 Page 91 of 113 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 4125.59 1.5 0.61 2529.46 1002000.3 0.27 1000 Nan CS 4127.07 4 0.65 2663.47 706600.2 0.28 1000 Nan CS 4131.07 9 0.61 2510.31 1166000.3 0.27 1000 Nan CS 4140.06 7 0.65 2692.77 769000.2 0.27 1000 Nan CS 4147.08 5.5 0.62 2575.29 1278000.4 0.26 1000 Nan CS 4152.56 13 0.65 2698.72 691700.2 0.28 1000 Nan DS 4165.58 2.5 0.68 2852.6 1748000.4 0.26 1500 Nan DS 4168.08 12.5 0.64 2654.92 1111000.3 0.27 1500 Nan DS 4180.58 4 0.7 2927.44 1692000.4 0.26 1500 Nan DS 4184.58 2.5 0.65 2708.58 822100.2 0.27 1500 Shale 4187.07 2 0.7 2919.17 2665000.7 0.23 2500 Nan DS 4189.07 4 0.65 2715.83 1159000.3 0.27 1500 Nan DS 4193.08 4 0.63 2630.26 838300.2 0.27 1000 Shale 4197.08 4 0.7 2957.61 2665000.7 0.23 2500 Nan DS 4201.08 6 0.65 2715.54 1133000.3 0.27 1500 Shale 4207.09 2 0.7 2933.1 2665000.7 0.23 2500 Attachment K- NDB-027 Page 92 of 113 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 4209.09 2 0.63 2646.65 1078000.3 0.27 1500 Nan DS 4211.09 6.5 0.67 2815.76 1694000.4 0.26 1500 Nan DS 4217.59 4 0.62 2608.07 898500.2 0.27 1500 Nan DS 4221.59 3.5 0.65 2744.84 929100.3 0.27 1500 Shale 4225.07 2 0.7 2945.57 2665000.7 0.23 2500 Nan DS 4227.07 12.5 0.65 2731.5 1562000.4 0.26 1500 Nan DS 4239.57 2 0.66 2781.1 1397000.4 0.26 1500 Shale 4241.57 2 0.7 2957.03 2665000.7 0.23 2500 Nan DS 4243.57 2 0.65 2763.26 1242000.3 0.26 1500 Shale 4245.57 8 0.69 2927.88 2665000.7 0.23 2500 Nan DS 4253.58 2 0.64 2723.23 932500.2 0.27 1500 Shale 4255.58 4 0.7 2967.47 2665000.7 0.23 2500 Nan DS 4259.58 6 0.65 2753.54 1427000.4 0.26 1500 Shale 4265.58 8 0.7 2975.88 2665000.7 0.23 2500 Nan DS 4273.59 6.5 0.65 2800.1 1469000.4 0.26 1500 Shale 4280.09 6 0.69 2951.08 2665000.7 0.23 2500 Attachment K- NDB-027 Page 93 of 113 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 4286.09 2 0.64 2759.49 838400.2 0.27 1000 Shale 4288.09 2 0.7 2989.52 2665000.7 0.23 2500 Nan DS 4290.06 4 0.65 2789.95 1469000.4 0.26 1500 Shale 4294.06 2 0.7 2993.58 2665000.7 0.23 2500 Nan DS 4296.06 6 0.67 2883.93 1545000.4 0.26 1500 Shale 4302.07 12 0.7 3002.72 2665000.7 0.23 2500 Nan DS 4314.07 2.5 0.65 2787.63 1214000.3 0.27 1500 Shale 4316.57 20 0.69 2980.96 2665000.7 0.23 2500 Attachment K- NDB-027 Page 94 of 113 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 15750 375 9.38 2 1 PPA 40 YF126ST 7641.8 190.02 CarboLite 16/20- SG 1 7641.8 4.75 3 3 PPA 40 YF126ST 7971.7 215.07 CarboLite 16/20- SG 3 23915.1 5.38 4 5 PPA 40 YF126ST 8253.9 240.13 CarboLite 16/20- SG 5 41269.5 6 5 7 PPA 40 YF126ST 7696.2 240.17 CarboLite 16/20- SG 7 53873.4 6 6 9 PPA 40 YF126ST 6608.3 220.19 CarboLite 16/20- SG 9 59474.7 5.5 7 11 PPA 40 YF126ST 5367.5 190.19 CarboLite 16/20- SG 11 59042.5 4.75 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.56 22.44 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 59289.4 245217 1670.77 41.77 Attachment K- NDB-027 Page 95 of 113 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 15 MD: [19223, 19229] 6588.6 190.48 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4063.31 4253.79 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 15 MD: [19223, 19229] 711.25 144.5 0.61 Attachment K- NDB-027 Page 96 of 113 Stage 16 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 16 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6659.9 psi 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 4060.76 10 0.73 2974.87 1461000.3 0.22 2500 Shale 4070.77 15 0.7 2834.47 1762000.5 0.22 2500 Nanushuk 3 SS 4085.76 15.3 0.68 2775.3 1898000.5 0.22 2000 Top Nan 4101.08 6 0.65 2663.76 838900.2 0.27 1000 Shale 4107.09 2 0.7 2894.66 2665000.7 0.23 2500 Nan DS 4109.09 1.5 0.64 2617.06 819400.2 0.27 1500 Nan DS 4110.56 2 0.64 2648.53 1222000.3 0.26 1500 Nan CS 4112.57 13 0.63 2594.73 869100.2 0.27 1000 Attachment K- NDB-027 Page 97 of 113 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 4125.59 1.5 0.61 2529.46 1002000.3 0.27 1000 Nan CS 4127.07 4 0.65 2663.47 706600.2 0.28 1000 Nan CS 4131.07 9 0.61 2510.31 1166000.3 0.27 1000 Nan CS 4140.06 7 0.65 2692.77 769000.2 0.27 1000 Nan CS 4147.08 5.5 0.62 2575.29 1278000.4 0.26 1000 Nan CS 4152.56 13 0.65 2698.72 691700.2 0.28 1000 Nan DS 4165.58 2.5 0.68 2852.6 1748000.4 0.26 1500 Nan DS 4168.08 12.5 0.64 2654.92 1111000.3 0.27 1500 Nan DS 4180.58 4 0.7 2927.44 1692000.4 0.26 1500 Nan DS 4184.58 2.5 0.65 2708.58 822100.2 0.27 1500 Shale 4187.07 2 0.7 2919.17 2665000.7 0.23 2500 Nan DS 4189.07 4 0.65 2715.83 1159000.3 0.27 1500 Nan DS 4193.08 4 0.63 2630.26 838300.2 0.27 1000 Shale 4197.08 4 0.7 2957.61 2665000.7 0.23 2500 Nan DS 4201.08 6 0.65 2715.54 1133000.3 0.27 1500 Shale 4207.09 2 0.7 2933.1 2665000.7 0.23 2500 Attachment K- NDB-027 Page 98 of 113 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 4209.09 2 0.63 2646.65 1078000.3 0.27 1500 Nan DS 4211.09 6.5 0.67 2815.76 1694000.4 0.26 1500 Nan DS 4217.59 4 0.62 2608.07 898500.2 0.27 1500 Nan DS 4221.59 3.5 0.65 2744.84 929100.3 0.27 1500 Shale 4225.07 2 0.7 2945.57 2665000.7 0.23 2500 Nan DS 4227.07 12.5 0.65 2731.5 1562000.4 0.26 1500 Nan DS 4239.57 2 0.66 2781.1 1397000.4 0.26 1500 Shale 4241.57 2 0.7 2957.03 2665000.7 0.23 2500 Nan DS 4243.57 2 0.65 2763.26 1242000.3 0.26 1500 Shale 4245.57 8 0.69 2927.88 2665000.7 0.23 2500 Nan DS 4253.58 2 0.64 2723.23 932500.2 0.27 1500 Shale 4255.58 4 0.7 2967.47 2665000.7 0.23 2500 Nan DS 4259.58 6 0.65 2753.54 1427000.4 0.26 1500 Shale 4265.58 8 0.7 2975.88 2665000.7 0.23 2500 Nan DS 4273.59 6.5 0.65 2800.1 1469000.4 0.26 1500 Shale 4280.09 6 0.69 2951.08 2665000.7 0.23 2500 Attachment K- NDB-027 Page 99 of 113 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 4286.09 2 0.64 2759.49 838400.2 0.27 1000 Shale 4288.09 2 0.7 2989.52 2665000.7 0.23 2500 Nan DS 4290.06 4 0.65 2789.95 1469000.4 0.26 1500 Shale 4294.06 2 0.7 2993.58 2665000.7 0.23 2500 Nan DS 4296.06 6 0.67 2883.93 1545000.4 0.26 1500 Shale 4302.07 12 0.7 3002.72 2665000.7 0.23 2500 Nan DS 4314.07 2.5 0.65 2787.63 1214000.3 0.27 1500 Shale 4316.57 20 0.69 2980.96 2665000.7 0.23 2500 Attachment K- NDB-027 Page 100 of 113 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 16800 400 10 2 1 PPA 40 YF126ST 7238.8 180 CarboLite 16/20- SG 1 7238.8 4.5 3 2 PPA 40 YF126ST 7715.2 200 CarboLite 16/20- SG 2 15430.4 5 4 4 PPA 40 YF126ST 7846.9 220 CarboLite 16/20- SG 4 31387.6 5.5 5 6 PPA 40 YF126ST 7296.9 220 CarboLite 16/20- SG 6 43781.4 5.5 6 8 PPA 40 YF126ST 6818.9 220 CarboLite 16/20- SG 8 54551.2 5.5 7 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 8 12 PPA 40 YF126ST 4932.9 180 CarboLite 16/20- SG 12 59194.8 4.5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.06 21.98 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 64467.6 269764.2 1819.99 45.5 Attachment K- NDB-027 Page 101 of 113 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 16 MD: [18678, 18684] 6659.9 214.96 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4068.97 4283.93 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 16 MD: [18678, 18684] 853.2 167.27 0.51 Attachment K- NDB-027 Page 102 of 113 Stage 17 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 17 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 12000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6479.7 psi Zoneset name: Stage 17 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 4060.76 10 0.73 2974.87 1461000.3 0.22 2500 Shale 4070.77 15 0.7 2834.47 1762000.5 0.22 2500 Nanushuk 3 SS 4085.76 15.3 0.68 2775.3 1898000.5 0.22 2000 Top Nan 4101.08 6 0.65 2663.76 838900.2 0.27 1000 Shale 4107.09 2 0.7 2894.66 2665000.7 0.23 2500 Nan DS 4109.09 1.5 0.64 2617.06 819400.2 0.27 1500 Nan DS 4110.56 2 0.64 2648.53 1222000.3 0.26 1500 Nan CS 4112.57 13 0.63 2594.73 869100.2 0.27 1000 Nan CS 4125.59 1.5 0.61 2529.46 1002000.3 0.27 1000 Attachment K- NDB-027 Page 103 of 113 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 4127.07 4 0.65 2663.47 706600.2 0.28 1000 Nan CS 4131.07 9 0.61 2510.31 1166000.3 0.27 1000 Nan CS 4140.06 7 0.65 2692.77 769000.2 0.27 1000 Nan CS 4147.08 5.5 0.62 2575.29 1278000.4 0.26 1000 Nan CS 4152.56 13 0.65 2698.72 691700.2 0.28 1000 Nan DS 4165.58 2.5 0.68 2852.6 1748000.4 0.26 1500 Nan DS 4168.08 12.5 0.64 2654.92 1111000.3 0.27 1500 Nan DS 4180.58 4 0.7 2927.44 1692000.4 0.26 1500 Nan DS 4184.58 2.5 0.65 2708.58 822100.2 0.27 1500 Shale 4187.07 2 0.7 2919.17 2665000.7 0.23 2500 Nan DS 4189.07 4 0.65 2715.83 1159000.3 0.27 1500 Nan DS 4193.08 4 0.63 2630.26 838300.2 0.27 1000 Shale 4197.08 4 0.7 2957.61 2665000.7 0.23 2500 Nan DS 4201.08 6 0.65 2715.54 1133000.3 0.27 1500 Shale 4207.09 2 0.7 2933.1 2665000.7 0.23 2500 Nan DS 4209.09 2 0.63 2646.65 1078000.3 0.27 1500 Attachment K- NDB-027 Page 104 of 113 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 4211.09 6.5 0.67 2815.76 1694000.4 0.26 1500 Nan DS 4217.59 4 0.62 2608.07 898500.2 0.27 1500 Nan DS 4221.59 3.5 0.65 2744.84 929100.3 0.27 1500 Shale 4225.07 2 0.7 2945.57 2665000.7 0.23 2500 Nan DS 4227.07 12.5 0.65 2731.5 1562000.4 0.26 1500 Nan DS 4239.57 2 0.66 2781.1 1397000.4 0.26 1500 Shale 4241.57 2 0.7 2957.03 2665000.7 0.23 2500 Nan DS 4243.57 2 0.65 2763.26 1242000.3 0.26 1500 Shale 4245.57 8 0.69 2927.88 2665000.7 0.23 2500 Nan DS 4253.58 2 0.64 2723.23 932500.2 0.27 1500 Shale 4255.58 4 0.7 2967.47 2665000.7 0.23 2500 Nan DS 4259.58 6 0.65 2753.54 1427000.4 0.26 1500 Shale 4265.58 8 0.7 2975.88 2665000.7 0.23 2500 Nan DS 4273.59 6.5 0.65 2800.1 1469000.4 0.26 1500 Shale 4280.09 6 0.69 2951.08 2665000.7 0.23 2500 Nan DS 4286.09 2 0.64 2759.49 838400.2 0.27 1000 Attachment K- NDB-027 Page 105 of 113 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 4288.09 2 0.7 2989.52 2665000.7 0.23 2500 Nan DS 4290.06 4 0.65 2789.95 1469000.4 0.26 1500 Shale 4294.06 2 0.7 2993.58 2665000.7 0.23 2500 Nan DS 4296.06 6 0.67 2883.93 1545000.4 0.26 1500 Shale 4302.07 12 0.7 3002.72 2665000.7 0.23 2500 Nan DS 4314.07 2.5 0.65 2787.63 1214000.3 0.27 1500 Shale 4316.57 20 0.69 2980.96 2665000.7 0.23 2500 Attachment K- NDB-027 Page 106 of 113 Name: Stage 17 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 17 PAD 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 7238.8 180 CarboLite 16/20- SG 1 7238.8 4.5 3 2 PPA 40 YF126ST 7715.2 200 CarboLite 16/20- SG 2 15430.4 5 4 4 PPA 40 YF126ST 7846.9 220 CarboLite 16/20- SG 4 31387.6 5.5 5 6 PPA 40 YF126ST 7296.9 220 CarboLite 16/20- SG 6 43781.4 5.5 6 8 PPA 40 YF126ST 6818.9 220 CarboLite 16/20- SG 8 54551.2 5.5 7 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 8 12 PPA 40 YF126ST 4932.9 180 CarboLite 16/20- SG 12 59194.8 4.5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.06 21.98 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 64467.6 269764.2 1819.99 45.5 Attachment K- NDB-027 Page 107 of 113 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 17 MD: [18137, 18143] 6479.7 240.5 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4064.65 4305.15 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 17 MD: [18137, 18143] 775.31 194.29 0.53 Attachment K- NDB-027 Page 108 of 113 Stage 18 The following are the results of the computer simulation which was run for the following combination of inputs: Stage ID: 18 Simulator Settings: Simulator type: p3dmp1 Shut-in time (s): 6000 Element Size (m): Vertical: 6.1 Horizontal: 24.38 A maximum surface pressure was simulated as 6315.8 psi Zoneset name: Stage 18 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 4038.78 10 0.73 2958.77 1461000.3 0.22 2500 Shale 4048.79 15 0.7 2819.1 1762000.5 0.22 2500 Nanushuk 3 SS 4063.78 15.3 0.68 2760.5 1898000.5 0.22 2000 Top Nan 4079.1 6 0.65 2649.4 838900.2 0.27 1000 Shale 4085.1 2 0.7 2879.14 2665000.7 0.23 2500 Nan DS 4087.11 1.5 0.64 2603.14 819400.2 0.27 1500 Nan DS 4088.58 2 0.64 2634.32 1222000.3 0.26 1500 Nan CS 4090.58 13 0.63 2580.95 869100.2 0.27 1000 Attachment K- NDB-027 Page 109 of 113 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 4103.61 1.5 0.61 2515.97 1002000.3 0.27 1000 Nan CS 4105.09 4 0.65 2649.4 706600.2 0.28 1000 Nan CS 4109.09 9 0.61 2496.97 1166000.3 0.27 1000 Nan CS 4118.08 7 0.65 2678.56 769000.2 0.27 1000 Nan CS 4125.1 5.5 0.62 2561.66 1278000.4 0.26 1000 Nan CS 4130.58 13 0.65 2684.5 691700.2 0.28 1000 Nan DS 4143.6 2.5 0.68 2837.52 1748000.4 0.26 1500 Nan DS 4146.1 12.5 0.64 2640.85 1111000.3 0.27 1500 Nan DS 4158.6 4 0.7 2911.92 1692000.4 0.26 1500 Nan DS 4162.6 2.5 0.65 2694.37 822100.2 0.27 1500 Shale 4165.09 2 0.7 2903.8 2665000.7 0.23 2500 Nan DS 4167.09 4 0.65 2701.47 1159000.3 0.27 1500 Nan DS 4171.1 4 0.63 2616.48 838300.2 0.27 1000 Shale 4175.1 4 0.7 2942.09 2665000.7 0.23 2500 Nan DS 4179.1 6 0.65 2701.33 1133000.3 0.27 1500 Shale 4185.1 2 0.7 2917.72 2665000.7 0.23 2500 Attachment K- NDB-027 Page 110 of 113 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 4187.11 2 0.63 2632.87 1078000.3 0.27 1500 Nan DS 4189.11 6.5 0.67 2801.11 1694000.4 0.26 1500 Nan DS 4195.6 4 0.62 2594.58 898500.2 0.27 1500 Nan DS 4199.61 3.5 0.65 2730.48 929100.3 0.27 1500 Shale 4203.08 2 0.7 2930.2 2665000.7 0.23 2500 Nan DS 4205.09 12.5 0.65 2717.28 1562000.4 0.26 1500 Nan DS 4217.59 2 0.66 2766.59 1397000.4 0.26 1500 Shale 4219.59 2 0.7 2941.66 2665000.7 0.23 2500 Nan DS 4221.59 2 0.65 2748.9 1242000.3 0.26 1500 Shale 4223.59 8 0.69 2912.79 2665000.7 0.23 2500 Nan DS 4231.59 2 0.64 2709.16 932500.2 0.27 1500 Shale 4233.6 4 0.7 2952.24 2665000.7 0.23 2500 Nan DS 4237.6 6 0.65 2739.33 1427000.4 0.26 1500 Shale 4243.6 8 0.7 2960.66 2665000.7 0.23 2500 Nan DS 4251.61 6.5 0.65 2785.59 1469000.4 0.26 1500 Shale 4258.1 6 0.69 2935.85 2665000.7 0.23 2500 Attachment K- NDB-027 Page 111 of 113 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 4264.11 2 0.64 2745.27 838400.2 0.27 1000 Shale 4266.11 2 0.7 2974.14 2665000.7 0.23 2500 Nan DS 4268.08 4 0.65 2775.59 1469000.4 0.26 1500 Shale 4272.08 2 0.7 2978.35 2665000.7 0.23 2500 Nan DS 4274.08 6 0.67 2869.14 1545000.4 0.26 1500 Shale 4280.09 12 0.7 2987.34 2665000.7 0.23 2500 Nan DS 4292.09 2.5 0.65 2773.41 1214000.3 0.27 1500 Shale 4294.59 20 0.69 2965.88 2665000.7 0.23 2500 Attachment K- NDB-027 Page 112 of 113 Name: Stage 18 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 18 PAD 40 YF126ST 16800 400 10 2 1 PPA 40 YF126ST 7238.8 180 CarboLite 16/20- SG 1 7238.8 4.5 3 2 PPA 40 YF126ST 7715.2 200 CarboLite 16/20- SG 2 15430.4 5 4 4 PPA 40 YF126ST 7846.9 220 CarboLite 16/20- SG 4 31387.6 5.5 5 6 PPA 40 YF126ST 7296.9 220 CarboLite 16/20- SG 6 43781.4 5.5 6 8 PPA 40 YF126ST 6818.9 220 CarboLite 16/20- SG 8 54551.2 5.5 7 10 PPA 40 YF126ST 5818 200 CarboLite 16/20- SG 10 58180 5 8 12 PPA 40 YF126ST 4932.9 180 CarboLite 16/20- SG 12 59194.8 4.5 Pad Percentage Clean Pad Percentage (%) Dirty Pad Percentage (%) 26.06 21.98 Totals Fluid Vol (gal) Proppant mass (lbm) Slurry Vol (bbl) Pump Time (min) 64467.6 269764.2 1819.99 45.5 Attachment K- NDB-027 Page 113 of 113 Summary Table: Maximum Pressures Case Max Parameters Perforation Max Surface Pressure (psi) Max Height (ft) Perf 18 MD: [17634, 17640] 6315.8 217.59 Summary Table: Height TVDs Max Fracture Top TVD (ft) Max Fracture Bottom TVD (ft) 4045.61 4263.2 Summary Table: Propped Fracture Results Case Closed Fracture Parameters Perforation Length Height Avg Wellbore Width (ft) (ft) (in) Perf 18 MD: [17634, 17640] 823.72 173.25 0.59 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-027 (PTD No. 225-066; Sundry No. 325-648) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 October 31, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. SFD 10/28/2025 (a)(2) Plat Provided with application. SFD 10/28/2025 (a)(2)(A) Well location Provided with application. Surface location in Section 4, T11N, R6E, UM. Wellbore passes through Section 5, T11N, R6E, Sections 32 and 31 of T12N, R6E. Top of productive interval in Section 30, T12N, R6E. Productive interval passes through Section 25, T12N, R6E, and TD in Section 24, T12N, R6E. SFD 10/28/2025 (a)(2)(B) Each water well within ½ mile None: According to the Water Estate map available through DNRs Alaska Mapper application (accessed online Oct 28, 2025), there are no wells are used for drinking water purposes are known to lie within ½ mile of the surface location of NDB-027. There are no subsurface water rights or temporary subsurface water rights within about 14 miles of the surface location of NDB-027. SFD 10/28/2025 (a)(2)(C) Identify all well types within ½ mile Not Provided. AOGCCs List of 30 wells, well branches, and plugbacks: Fiord 2, Fiord 3 , Fiord 3A, DW-02, NDB-010, NDB-011, NDB-024, NDB-024 PB1, NDB-025, NDB-027, NDB-031, NDB-032, NDB-037, NDB-040, NDB-048, NDB-051, NDB-006, NDB-014, NDB-016, NDB-018, NDB-030, NDB-036, NDB-043, NDB-043A, NDB-044, NDB-046, NDB-046L1, NDB-049, NDB-050, and NDB-050 PB1. SFD 10/28/2025 (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 SFD 10/28/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-027 (PTD No. 225-066; Sundry No. 325-648) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 October 31, 2025 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 (-1,408 to -1,486 TVDSS; base of permafrost ~1,170 MD (~-1,080 TVDSS)). (a)(4) Baseline water sampling plan None required. SFD 10/28/2025 (a)(5) Casing and cementing information Provided with application. Proposed schematic attached, as built not generated to date. CDW 10/21/2025 (a)(6) Casing and cementing operation assessment Surface casing cemented with 33 bbl good cement returned to surface. Two stage cement job in 9-5/8 liner. First stage cemented from shoe of 11995 ft to approx. 10995 ft. 2nd stage cemented through CFLEX stage tool at 5979 ft went as planned. Cemented with no losses. Cement circulated off liner top. 7 intermediate liner from 11832 to shoe of 17275 ft. CBL shows TOC 13886 ft with good cement from there to shoe. No issues with cement for the upcoming stimulation. CDW 10/21/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-027 (PTD No. 225-066; Sundry No. 325-648) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 October 31, 2025 (a)(6)(A) Casing cemented below lowermost freshwater aquifer and conforms to 20 AAC 25.030 No freshwater aquifers present. (See Section (a)(3), above.) SFD 10/28/2025 (a)(6)( B) Each hydrocarbon zone is isolated Yes, cement isolates each hydrocarbon zone. Surface casing was set at 2935 MD (-2320 TVDSS) and cemented with 33 barrels of good returns at surface. For NDB-027, 9-5/8 intermediate 1 liner was set at 11,995 MD (-3,332 TVDSS) and cemented in two stages. Stage 2 is required to isolate the upper portion of the Tuluvak interval from the TS-790 marker at 5901 MD (-2726 TVDSS) up to the Tuluvak Sand top at 3,311 MD (-2,440 TVDSS). The stage collar was set at 5979 MD (-2734 TVDSS) and cemented with 130 barrels of good cement to surface off the top of the liner. The bottom of the intermediate 1 liner was cemented with no losses and an estimated cement top of about 11,000 MD (-3235 TVDSS). The 7 intermediate 2 liner is designed to topset the NT3.2 reservoir (top at about 17,340 MD, or -4010 TVDSS). The shoe was set at 17,275 MD (-3995 TVDSS) and cemented with 61 barrels of losses. The SLB interpretation of the CBL log indicates a cement transition zone from 13,350 to 13,886 MD (-3465 to -3520 TVDSS), with good cement bond from 13,886 MD downward to the 7 shoe at 17,275 MD. SFD interprets the top of good, consistent cement bond to be at 14,050 MD (-3465 TVDSS) with the top of the Nanushuk Formation at 15,992 MD (-3731 TVDSS). So, cement isolates each hydrocarbon zone. SFD 10/28/2025 (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 4300 psi MITIA, 5500 psi MITT 9/30/2025.. CDW 10/21/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-027 (PTD No. 225-066; Sundry No. 325-648) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 October 31, 2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi wellhead max. frac. Pressure 8800 psi. Pump knock out 8100 and GORV 8500 psi., lines test 9200 psi. CDW 10/21/2025 (a)(9)(A) Fracturing and confining zones: lithologic description for each zone (a)(9)(B) Geological name of each zone (a)(9)(C) and (a)(9)(D) Measured and true vertical depths (a)(9)(E) Fracture pressure for each zone Upper Confining Zones: About 750 TVT of claystone, shale and volcanic tuff assigned to the Seabee Formation (top 8460 MD, -2982 TVDSS).. The estimated fracture gradient for the upper confining interval is 13.7 ppg EMW (0.71 psi/ft). Fracturing Zone: Perforated zone lies within a subdivision of the Nanushuk Formation which is comprised of highly laminated fine-grained sandstones, silts, and shales. Distributary channel mouth bar deposits and shoreface sands comprise major sand packages in the Nanushuk Fm (top 15,992 MD, 3731 TVDSS) which 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: Not penetrated in this well, but about 900 TVT of Lower Torok shales with thin interbedded siltstones with an estimated fracture gradient of 13.3 ppg EMW (0.69 psi/ft). SFD 10/28/2025 (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory It is highly unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids from this operation because of cement isolation and / or separation distance. There are five wells within ½ mile of NDB-027 that penetrate the confining intervals. AOGCC evaluated all wells that may transect the confining zones within the NDB-027 Area of Review and found it highly unlikely that any of these wells will interfere with fracturing fluids due to cement-isolation and/or separation distance or direction. No wells are proposed for additional monitoring during the frac. CDW 10/21/2025 SFD 10/29/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-027 (PTD No. 225-066; Sundry No. 325-648) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 October 31, 2025 (a)(11) Faults and fractures, Sufficient information to determine no interference with containment of the hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory One: It is unlikely that any faults will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. The operator has identified one fault through seismic or well data within a ½-mile radius of NDB-027. This fault trends NNE, and as mapped, it does not approach closer than 2000 to the east of NDB-027. Induced fractures are expected to propagate along azimuth 330°, which is roughly parallel with the wellbore, so the likelihood of an induced fracture intersecting this fault is vanishingly small. SFD 10/29/2025 (a)(12) Proposed program for fracturing operation Provided with application. CDW 10/21/2025 (a)(12)(A) Estimated volume Provided with application. 37572 bbl total dirty vol. 4.38million lb total proppant CDW 10/21/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 10/21/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger, Tracerco, Patina disclosures provided. CDW 10/21/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 10/21/2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 7784 psi. Max. 8800 psi allowable treating pressure. Max pressure is 8100 psi to 8500 psi to Pump shutdown. With 3800 psi back pressure IA (IA popoff set 4100 psi), max tubing differential should be 4700 psi. CDW 10/21/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-027 (PTD No. 225-066; Sundry No. 325-648) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 October 31, 2025 (a)(12)(F) Fractures height, length, MD and TVD to top, description of fracturing model None of the induced fractures will penetrate through the confining intervals. The modeled half-lengths of the induced fractures range from 260' to 499' according to the Operator's Computer simulation. The modeled heights of the induced fractures range from 190' to 355'. The induced fractures may penetrate a short distance into the overlying confining layer, but not through it, as that confining layer is 750 thick. The bottom of the induced fractures may penetrate a short distance into the underling confining layer, which is 900 thick, but not through it. SFD 10/29/2025 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified. CDW 10/21/2025 (b)Testing of casing or intermediate casing Tested >110% of max anticipated pressure 3800 psi back pressure, plan to test to 4300 psi, popoff set as 4100 psi CDW 10/21/2025 (c) Fracturing string (c)(1) Packer >100 below TOC of production or intermediate casing 4.5 tubing will be anchored with a retrievable packer set at approx. 17089 ft with perforations planned for 17634 ft. 7: liner shoe at 17275 ft. TOC in 7 liner at 13886 ft so USIT/CBL conservatively shows good cement at area of interest - so no cement concerns. CDW 10/21/2025 (c)(2) Tested >110% of max anticipated pressure differential Tubing test of 5500 psi. Max pressure differential is estimated as 5000 psi (8800 with 3800 psi backpressure) so test of 5500 psi satisfies 110% CDW 10/21/2025 (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. IA PRV set as 4100 psi. CDW 10/21/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 10/21/2025 (f) Surface casing pressures Monitored with gauge and pressure relief device IA PRV set at 4100 psi. Surface annulus open. Frac pressures continuously monitored. CDW 10/21/2025 20 AAC 25.283 Hydraulic Fracturing Application Checklist Pikka NDB-027 (PTD No. 225-066; Sundry No. 325-648) Paragraph Sub-Paragraph Section Complete? AOGCC Page 7 October 31, 2025 (g) Annulus pressure monitoring & notification 500 psi criteria During hydraulic fracturing operations, all annulus pressures must be continuously monitored and recorded. If at any time during hydraulic fracturing operations the annulus pressure increases more than 500 psig above those anticipated increases caused by pressure or thermal transfer, the operator shall: CDW 10/21/2025 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). SFD 10/29/2025 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. SFD 10/29/2025 (l) Variances requested Modifications of deadlines, requests for variances or waivers No plan for post fracture water well analysis. Commission may require this depending on performance of the fracturing operation. LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-027 PB1 (50-103-20922-7000) 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: 10/17/2025 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: 225-066 T40992 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.20 09:09:04 -08'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDB-027 PB1 Definitive Compass Survey Report - NAD27.pdf ؒ NDB-027 PB1 Definitive Compass Survey Report - NAD83.pdf ؒ NDB-027 PB1 Definitive survey-NAD27.txt ؒ NDB-027 PB1 Definitive survey-NAD83.txt ؒ NDB-027 PB1 Definitive survey.txt ؒ NDB-027 PB1 WA Definitive Survey.xlsx ؒ ؤؐؐؐLog Digital Data and Plots ؤؐؐؐLWD جؐؐؐDigital Data ؒ جؐؐؐFE ؒ ؒ NDB-027 PB1_LWD_GR_Res_RM_11998 - 8077ft_5MD_BROOH.las ؒ ؒ NDB-027 PB1_LWD_GR_Res_RM_12000ft.LAS ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDB-027 PB1_AP_R01_RM.las ؒ ؒ NDB-027 PB1_AP_R02_RM.las ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDB-027 PB1_DMD_RM_12000ft.las ؒ NDB-027 PB1_DMT_R01_RM.las ؒ NDB-027 PB1_DMT_R02_RM.las ؒ ؤؐؐؐGraphic Images جؐؐؐCGM ؒ جؐؐؐFE ؒ ؒ NDB-027 PB1_LWD_GR_Res_RM_12000ft_2MD.cgm ؒ ؒ NDB-027 PB1_LWD_GR_Res_RM_12000ft_2TVD.cgm ؒ ؒ NDB-027 PB1_LWD_GR_Res_RM_12000ft_5MD.cgm ؒ ؒ NDB-027 PB1_LWD_GR_Res_RM_12000ft_5TVD.cgm ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDB-027 PB1_AP_RM.cgm ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDB-027 PB1_DMD_RM_12000ft.cgm ؒ NDB-027 PB1_DMT_RM.cgm ؒ ؤؐؐؐPDF جؐؐؐFE ؒ NDB-027 PB1_LWD_GR_Res_RM_12000ft_2MD.pdf LETTER OF TRANSMITTAL ؒ NDB-027 PB1_LWD_GR_Res_RM_12000ft_2TVD.pdf ؒ NDB-027 PB1_LWD_GR_Res_RM_12000ft_5MD.pdf ؒ NDB-027 PB1_LWD_GR_Res_RM_12000ft_5TVD.pdf ؒ جؐؐؐPWD ؒ NDB-027 PB1_AP_RM.pdf ؒ ؤؐؐؐVSS NDB-027 PB1_DMD_RM_12000ft.pdf NDB-027 PB1_DMT_RM.pdf LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-027 (50-103-20922-0000) 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: 10/17/2025 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: 225-066 T40991 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.10.20 09:04:18 -08'00' LETTER OF TRANSMITTAL جؐؐؐDirectional Survey ؒ NDB-027 Vertical Section.pdf ؒ NDB-027 Comparison View 1.pdf ؒ NDB-027 Comparison View 2.pdf ؒ NDB-027 Definitive Compass Survey Report - NAD27.pdf ؒ NDB-027 Definitive Compass Survey Report - NAD83.pdf ؒ NDB-027 Definitive survey-NAD27.txt ؒ NDB-027 Definitive survey-NAD83.txt ؒ NDB-027 Definitive survey.txt ؒ NDB-027 Plan View .pdf ؒ NDB-027 WA Definitive Survey.xlsx ؒ ؤؐؐؐLog Digital Data and Plots جؐؐؐCement Evaluation Logs ؒ ؤؐؐؐSonicScope 7in Liner ؒ ؒ NDB-027_TOC-RM_4000.pdf ؒ ؒ Oil_Search_Santos_Pikka_NDB_027_R1_7in_Liner_SonicScope475_ReamDown_RM_TOC.pdf ؒ ؒ Oil_Search_Santos_Pikka_NDB_027_R1_7in_Liner_SonicScope475_ReamDown_RM_TOC_PPT.pptx ؒ ؒ ؒ جؐؐؐDlis ؒ ؒ NDB-027_TOC-RM Producer.dlis ؒ ؒ NDB-027_TOC-RM_Customer.dlis ؒ ؒ ؒ جؐؐؐLAS ؒ ؒ NDB-027_TOC-RM_LAS.las ؒ ؒ ؒ ؤؐؐؐLogs ؒ NDB-027_TOC-RM_1000.pdf ؒ NDB-027_TOC-RM_200.pdf ؒ NDB-027_TOC-RM_2000.pdf ؒ NDB-027_TOC-RM_4000.pdf ؒ NDB-027_TOC-RM_4000_Labeled.pdf ؒ NDB-027_TOC-RM_500.pdf ؒ NDB-027_TOC-RM_6000.pdf ؒ ؤؐؐؐLWD جؐؐؐDigital Data ؒ جؐؐؐFE ؒ ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26894-17311ft_BROOH.las ؒ ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26914ft.las ؒ ؒ ؒ جؐؐؐPWD LETTER OF TRANSMITTAL ؒ ؒ NDB-027_AP_R01_RM.las ؒ ؒ NDB-027_AP_R02_RM.las ؒ ؒ NDB-027_AP_R03_RM.las ؒ ؒ NDB-027_AP_R06_RM.las ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDB-027_DMD_RM_26914ft.las ؒ NDB-027_DMT_R01_RM.las ؒ NDB-027_DMT_R02_RM.las ؒ NDB-027_DMT_R03_RM.las ؒ NDB-027_DMT_R06_RM.las ؒ ؤؐؐؐGraphic Images جؐؐؐCGM ؒ جؐؐؐFE ؒ ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26894-17311ft_BROOH.cgm ؒ ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26914ft_2MD.cgm ؒ ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26914ft_2TVD.cgm ؒ ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26914ft_5MD.cgm ؒ ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26914ft_5TVD.cgm ؒ ؒ ؒ جؐؐؐPWD ؒ ؒ NDB-027_AP_RM.cgm ؒ ؒ ؒ ؤؐؐؐVSS ؒ NDB-027_DMD_RM_26914ft.cgm ؒ NDB-027_DMT_RM.cgm ؒ ؤؐؐؐPDF جؐؐؐFE ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26894-17311ft_BROOH.pdf ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26914ft_2MD.pdf ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26914ft_2TVD.pdf ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26914ft_5MD.pdf ؒ NDB-027_LWD_GR_Res_Den_Neu_Cal_RM_26914ft_5TVD.pdf ؒ جؐؐؐPWD ؒ NDB-027_AP_RM.pdf ؒ ؤؐؐؐVSS NDB-027_DMD_RM_26914ft.pdf NDB-027_DMT_RM.pdf 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:Conwell, Russell (Russell) To:McLellan, Bryan J (OGC) Cc:Tirpack, Robert (Robert) Subject:NDB-027 (PTD 225-066) 7" Liner FIT and Cement Job Results Date:Thursday, September 11, 2025 6:08:09 AM Attachments:Oil_Search_Santos_Pikka_NDB_027_R1_7in_Liner_SonicScope475_ReamDown_RM_TOC.pdf Reporting - Cement - NDB-027 - 2025-09-10 12.23.51.pdf Production Casing & FIT Test Chart NDB-027.xlsm Prod CSG and FIT.pdf NDB-027 Schematic As Built 09.11.25.pdf Hi Bryan, We have just completed the FIT at the 7” shoe and have also received the final 7” TOC report from the SLB SonicScope run. See the summary below and I have also attached the FIT data, SLB ToC report, Wellview Cementing Report and draft well schematic. Below is a high-level summary of the cement job: Well Design and Geology 9-5/8” Intermediate 1 Liner: 9-5/8” Liner Top at 2,780’ MD 13-3/8” Shoe at 2,935’ MD TS790 at 5,901’ MD CFLEX Stage Tool at 5,979’ MD 9-5/8” Shoe at 11,995’ MD 7” Intermediate 2 Liner: 7” Liner Top at 11,832’ MD Top of the Nanushuk was picked at 15,992’ MD 7” Shoe at 17,275’ MD Cement Job Planning / Execution 9-5/8” Intermediate 1 Liner: 1st stage of the cement job planned with 15.3 ppg tail slurry at 30% excess, targeting TOC 1000’ MD above the 9-5/8” shoe. No losses during execution of the 1st stage cement job. After drilling out the 9-5/8” shoe a LOT was conducted to 14.0 ppg. 2nd Stage of cement job planned with CFLEX ~78’ below the TS790. Also planned with a full 15.3 ppg tail slurry at 120% excess, targeting TOC at the 9-5/8” liner top. During execution of the 2nd stage cement, ~15bbls of losses were noted and ~130 bbls of good cement was observed at surface off the top of liner. 7” Intermediate 2 Liner: 7” Liner cement job planned with a full 15.3 ppg tail slurry at 30% excess, targeting TOC 200’ TVD above top of Nanushuk to 13,991’ MD (3,609’ TVD). During execution of the job, a total of 61 bbls of losses were noted while displacing the cement. Good lift pressures were noted and an FIT to 14.0ppg was conducted after drilling out the 7” shoe. Observations / Conclusions 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 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. Let me know if you have any questions or comments. Regards Russell Russell Conwell Senior Drilling Engineer m: +1 907 615 2234| e: russell.conwell@santos.com 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 From:Davies, Stephen F (OGC) To:Conwell, Russell (Russell) Cc:McLellan, Bryan J (OGC); Dewhurst, Andrew D (OGC); Starns, Ted C (OGC) Subject:RE: NDB-027 (PTD 225-066) 12-1/4" PB1 Date:Thursday, September 11, 2025 10:02:43 AM Attachments:image003.png Hello Russell, Yes, since the gyro survey confirmed that 9-5/8” casing was indeed run into the original wellbore rather than the sidetracked wellbore I agree with your proposed naming/numbering of the various data sets as you describe below. Please let me know if I can help further. Regards and Be Well, Steve Davies AOGCC From: Conwell, Russell (Russell) <Russell.Conwell@santos.com> Sent: Thursday, September 11, 2025 9:53 AM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: FW: NDB-027 (PTD 225-066) 12-1/4" PB1 Hi Steve, I got a text from Bryan saying he is out and just to followup with yourself if you are ok with the proposed naming convention as below. Let me know if you see any issues. Thanks again. Russell Conwell Senior Drilling Engineer m: +1 907 615 2234| e: russell.conwell@santos.com From: Conwell, Russell (Russell) Sent: Wednesday, September 10, 2025 9:16 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Harvey, Brett (Brett) <Brett.Harvey@santos.com>; Thompson, Ron (Ron) <Ron.Thompson@contractor.santos.com>; Lewallen, Anna (Anna) <Anna.Lewallen@santos.com> Subject: RE: NDB-027 (PTD 225-066) 12-1/4" PB1 Hi Bryan, To followup further on the note below, we have subsequently confirmed that the 9-5/8” casing was actually run into the original 12-1/4” hole section rather than the re-drill (sidetrack). Details as below: No significant difficulty was noted while running 9-5/8” casing around the sidetrack depth or all the way to TD at 12000’ (i.e. assumed we had run 9-5/8” into the sidetracked hole as planned). When RIH with the 8-1/2” BHA to drillout 9-5/8” casing, a single MWD check shot survey appeared to match the inclination in the original wellbore rather than the sidetrack. On the trip out after drilling the 8-1/2” hole, multiple further MWD check shot surveys confirmed that inclination inside the 9-5/8” casing closely matched the original wellbore rather than the sidetrack. As a definitive confirmation, a gyro survey was run prior to drilling out the 7” shoe. This survey has confirmed the 9-5/8” casing was run into the original wellbore rather than the sidetrack. Based on this change we are proposing that all future references (surveys / logs etc) to NDB- 027 PB1 (API 50-103-20922-70-00) will be the sidetracked wellbore as per the attached survey to 12,000’ MD. The NDB-027 (API 50-103-20922-00-00) will be based on the original 12-1/4” hole and subsequent surveys to the well TD. Note we will be using the gyro survey with MWD surveys tied in as the final definitive survey for the well. Let me know if you have any questions. Thanks. Regards Russell Russell Conwell Senior Drilling Engineer m: +1 907 615 2234| e: russell.conwell@santos.com From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, August 25, 2025 9:00 AM To: Harvey, Brett (Brett) <Brett.Harvey@santos.com>; Conwell, Russell (Russell) <Russell.Conwell@santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Starns, Ted C (OGC) <ted.starns@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: ![EXT]: RE: NDB-027 (PTD 225-066) 12-1/4" PB1 Hello Brett and Russell, That is correct: The API Number for the NDB-027 PB1 wellbore is 50-103-20922-70-00. The API Number for NDB-027 remains 50-103-20922-00-00. The Permit to Drill Number for both wellbores remains 225-066. Please let me know if you have any further questions. Thanks Again and Be Well, Steve Davies Senior Petroleum Geologist AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Harvey, Brett (Brett) <Brett.Harvey@santos.com> Sent: Monday, August 25, 2025 8:01 AM To: Conwell, Russell (Russell) <Russell.Conwell@santos.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: RE: NDB-027 (PTD 225-066) 12-1/4" PB1 Morning, To help the follow up, we are curious what the PB1 API number is, usually the last two digits differ from the main wellbore. Brett Harvey Senior Operations Geologist t: 907-646-7101 | m: 716-640-4514 | e: Brett.Harvey@.santos.com Santos.com | Follow us on LinkedIn, Facebook and Twitter Santos acknowledges the Traditional Owners and Custodians of the lands on which we operate. From: Conwell, Russell (Russell) <Russell.Conwell@santos.com> Sent: Monday, 25 August 2025 07:40 To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Harvey, Brett (Brett) <Brett.Harvey@santos.com> Subject: RE: NDB-027 (PTD 225-066) 12-1/4" PB1 Hi Brian, Thanks again for getting back. Can you please confirm if the API number will change for the new wellbore? We just want to make sure we get all logs and reports labeled correctly moving forward. Russell Conwell Senior Drilling Engineer m: +1 907 615 2234| e: russell.conwell@santos.com From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, August 21, 2025 5:22 PM To: Conwell, Russell (Russell) <Russell.Conwell@santos.com> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: ![EXT]: RE: NDB-027 (PTD 225-066) 12-1/4" PB1 Russell, Plan is approved. Please submit cement report for the 2nd stage cement job as soon as feasible after pumping it. If there are any abnormalities, we may require a CBL to ensure Tuluvak in the active wellbore is isolated. 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. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Conwell, Russell (Russell) <Russell.Conwell@santos.com> Sent: Wednesday, August 20, 2025 8:24 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Tirpack, Robert (Robert) <Robert.Tirpack@santos.com> Subject: NDB-027 (PTD 225-066) 12-1/4" PB1 Hi Bryan, As per our phone conversation this afternoon, we have now confirmed that the 12-1/4” hole was accidentally sidetracked below the 13-3/8” casing shoe with the relevant depths below: 13-3/8” casing shoe - 2935’ MD Section TD 12000’ MD in the Seabee (see logs attached) Estimated sidetrack point – 3322’ MD Top Tuluvak sand 3311’ MD As per the verbal agreement in our call, can you please confirm that cementing of the original wellbore and exposed Tuluvak will not be required based on the following: Inability to re-enter the original wellbore to set cement Nanushuk is not exposed in the original wellbore Cementing of the 9-5/8” liner in the sidetrack will provide isolation of the Tuluvak above the sidetrack point Notes: Original wellbore will be designated PB1 BH location will remain within 500’ of the original plan in the PTD Directional surveys will be submitted for both wellbores Let me know if you have any further questions. Thanks. Russell Conwell Senior Drilling Engineer m: +1 907 615 2234| e: russell.conwell@santos.com 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 Tuluvak Sand @ 3,311' MD Top Nan 3.2 @17,344' MD Top Nanushuk @15,992' NDB-027 Well Schematic (As Built Draft) 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2,780' MD 13-3/8" 68 ppf L-80 Surface Casing2,935' MD 4-½”, 12.6ppf P-110S Production Liner26,893' MD 4-½” Liner Hanger/Top Packer17,125' MD GL 69.74' RKB – Bottom Flange 9/11/2025 9-5/8" Tieback2,780' MD 9-5/8" Cflex Stage Tool (50' MD below TS790)5,979' MD 7" TOC (224' TVD above top Nanushuk)13,886' MD 7", 26ppf L-80 Production Liner17,275' MD 9-5/8", 47ppf L-80 Intermediate Liner11,995' MD 9-5/8" Primary TOC (1000' MD above shoe)10,995' MD 7" Liner Hanger and Liner Top Packer11,832' MD PB1 Sidetrack 12,000' MD 12¼” openhole STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDB-027 JBR 10/10/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Test with 5". 7" and 9-5/8" Test went good no failures. Accumulator bottles 24 @ 1015 psi precharge Avg. Test Results TEST DATA Rig Rep:Sonny ClarkOperator:Oil Search (Alaska), LLC Operator Rep:Brian Buzby Rig Owner/Rig No.:Nabors 272 PTD#:2250660 DATE:8/28/2025 Type Operation:DRILL Annular: 250/3600Type Test:BIWKLY Valves: 250/3600 Rams: 250/3600 Test Pressures:Inspection No:bopKPS250829102319 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5 MASP: 1482 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 2 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8 P #1 Rams 1 4-1/2" x 7" V P #2 Rams 1 Blind/Shears P #3 Rams 1 9-5/8" FBR P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/8"P Kill Line Valves 2 3-1/8&2-1/16 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3100 Pressure After Closure P2000 200 PSI Attained P15 Full Pressure Attained P69 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P14@ 2200 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P20 #1 Rams P6 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 ’ Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Russell Conwell Senior Drilling Engineer Oil Search Alaska, LLC 601 W 5th Avenue Anchorage, AK, 99501 Re: Pikka Field, Nanushuk Oil Pool, NDBi-027 Oil Search Alaska, LLC Permit to Drill Number: 225-066 Surface Location: 2393’ FSL, 2246’ FWL, Sec 4, T11N, R6E, UM Bottomhole Location: 4756’ FSL, 4409’ FEL, Sec 24, T12N, R5E, UM Dear Mr. Conwell: 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, (SFHPSZ$. 8JMTPO Commissioner DATED this 4th day of August 2025. Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.08.04 08:10:48 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 26,893' TVD: 4,095' 4a. Location of Well (Governmental Section): 7. Property Designation: ADL 392984, 391445 Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 8/14/2025 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 517' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 69.8' 15. Distance to Nearest Well Open Surface: x- 422,211.92 y- 5,972,777.15 Zone- 4 22.8' to Same Pool: 1843' 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 90.37 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 42" 20"x34" 215# X-52 Welded 80' Surface Surface 128' 128' 16" 13-3/8" 68# L-80 TXP BTC 2,926' Surface Surface 2,926' 2,386' 12-1/4" 9-5/8" 47# L-80 HYD563 9,224 2,776' 2,320 12,000' 3,411' Tie Back 9-5/8" 47# L-80 HYD563 2,776' Surface Surface 2,776' 2,320' 8-1/2" x 9-7/8"7" 26# L-80 HYD563 5,456' 11,850' 3,396' 17,306' 4,083' 6-1/8" 4-1/2" 12.6# P-110S HYD563 9,737' 17,156' 4,038' 26,893' 4,095' Tubing 4-1/2" 12.6# P-110S HYD563 17,156' Surface Surface 17,156' 4,038' 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: Russell Conwell Russell Conwell Contact Email:russell.conwell@santos.com Senior Drilling Engineer Contact Phone:1-907-615-2234 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 Pikka NDB-027 Pikka/Nanushuk Oil Pool Uncemented Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft): Total Depth TVD (ft): IS000361277U STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 See attachment 6 1,482 2166’ FSL, 4586’ FEL, Sec 30, T12N, R6E, UM 4756’ FSL, 4409’ FEL, Sec 24, T12N, R5E, UM LONS 19-003 601 W Fifth Avenue, Anchorage, AK 99501-6301 Oil Search Alaska, LLC 2393’ FSL, 2246’ FWL, Sec 4, T11N, R6E, UM 393020, 393019, 393018, 392970, 392968 4379 18. Casing Program:Top - Setting Depth - BottomSpecifications 1,897 GL / BF Elevation above MSL (ft): Cement Volume MDSize Plugs (measured): (including stage data) Grouted to surface See attachment 6 See attachment 6 N/A Effect. Depth MD (ft): Effect. Depth TVD (ft): See attachment 6 Conductor/Structural LengthCasing Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): s N ype of W L l R L 1 Class: os N s No s N o D h D hh h 277U o well is p G S S 20 A S S S s No s No S G s No essss Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) enior Drilling Engineer 225-066 By Gavin Gluyas at 8:35 am, Jun 26, 2025 DSR-6/30/25A.Dewhurst 01AUG25 BJM 7/30/25 10 AUG 25 See attached emails. 50-103-20922-00-00 See attached conditions of approval JLC 8/1/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.08.04 08:06:51 -08'00'08/04/25 08/04/25 RBDMS JSB 080525 NDB-027 (PTD 225-066) Approval 1. 250 - 2. 6 . All a - -25- 4. 5. . 6. . Cement -. 7. . - : a. - - - - 10. not approved 11. - are met: a. a - it will - d. Page 1 of 1 25 June 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Permit to Drill Oil Search (Alaska), LLC, a subsidiary of Santos Limited NDB-027 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. NDB-027 is planned to be a horizontal producer targeting the Nanushuk 3. The approximate spud date is anticipated to be August 14th, 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 ~75 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. At no point will the static wellbore fluid be underbalanced to the expected formation pore pressure. 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) 615-2234 or russell.conwell@santos.com. Respectfully, Russell Conwell Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Respectfully, RllC ll Application for Permit to Drill NDB-027 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 Requests......................................................................................................12 Attachments..................................................................................................................................................16 Attachment 1: Location Maps..........................................................................................................17 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: Managed Pressure Drilling .....................................................................................37 Attachment 14: As Built Survey NDB Well 27 Conductor Final........................................................39 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 NDB-027. This will be a development production well. 2. Location Summary 20 AAC 25.005 (c) (2) A plat identifying the property and the property's owners and showing: (A) the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines; (B) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth Location at Surface Reference to Government Section Lines 2,393’ FSL, 2,246’ FWL, Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,777 E 422,212’ Rig KB Elevation 47’ above GL Ground Level 22.8’ above MSL Location at Top of Productive Interval Reference to Government Section Lines 2,166’ FSL, 4,586’ FEL, Sec 30, T12N, R6E, UM NAD 27 Coordinate System N 5,983,243’ E 410,181’ Measured Depth, Rig KB (MD) 17,737’ Total Vertical Depth, Rig KB (TVD) 4,145’ Total vertical Depth, Subsea (TVDSS) 4,075’ Location at Bottom of Productive Interval Reference to Government Section Lines 4,756’ FSL, 4,409’ FEL, Sec 24, T12N, R5E, UM NAD 27 Coordinate System N 5,991,170’ E 405,602’ Measured Depth, Rig KB (MD) 26,893’ Total Vertical Depth, Rig KB (TVD) 4,095’ Total vertical Depth, Subsea (TVDSS) 4,025’ (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. A 21-day BOPE test schedule is planned per the waiver acceptance letter and conditional requirements outlined in Docket Number OTH-25-010 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 1,632 psi at TD in Seabee at 3,411’ TVD (9.2ppg EMW in the Seabee formation to section TD) Maximum surface pressure 1,291 psi from TD in the Seabee (0.10 psi/ft gas gradient to surface, 3,411’ 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. (12.8 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 4,083’ 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, 4,083’ 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. (11.7 ppg LOT required for Kick Tolerance with 11.0ppg MW) 9-5/8” Liner Test 4,000 psi surface pressure (MIT-IA after upper completion run, test pressure driven by annular pressure during frac job) 6-1/8” Production Hole Pressure Data Maximum anticipated BHP 1,897 psi in the Nanushuk 3.2 at 4,145’ TVD (8.8ppg EMW top NT3.2 formation to heel target) Maximum surface pressure 1,482 psi from the NT3.2 (0.10 psi/ft gas gradient to surface, 4,145’ 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. (10.3ppg 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” 20”x34” 215# X-52 Welded 80’ Surface 128’ / 128’ 16” 13-3/8” 68# L-80 TXP BTC 2,926’ Surface 2,926’ / 2,386’ 12-1/4” 9-5/8” 47# L-80 HYD 563 9,224’ 2,776’ 12,000’ / 3,411’ Tie Back 9-5/8” 47# L-80 HYD 563 2,776’ Surface 2,776’ / 2,320’ 8-1/2” x 9-7/8”7” 26 L-80 HYD 563 5,456’ 11,850’ 17,306’ / 4,083’ 6-1/8” 4-1/2” 12.6# P-110S HYD 563 9,737’ 17,156’ 26,893’ / 4,095’ Tubing 4-1/2” 12.6# P-110S HYD 563 17,156’ Surface 17,156’ / 4,038’ Please refer to Attachment 6: Cement Summary for further details. 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Parker 272 Diverter Equipment: Hydril MSP annular BOP, 21 1/4” x 2000 psi, flanged Diverter Spool 21 1/4” x 2000 psi with 16-3/4” flanged sidearm connection. Interlocked knife/gate valves. 16” Diverter Line. Please refer to Attachment 3: BOPE Equipment for further details. A diverter variance is requested for NDB-027. 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 10.5 - 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 9.0 - 10.0 ppg 50 - 80 sec ALAP 10 - 20 n/a < 5 ml/30min n/a n/a A diagram of drilling fluid system on Parker 272 is on file with AOGCC. 9. Abnormally Pressured Formation Information 20 AAC 25.005 (c) (9) For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); N/A – Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis 20 AAC 25.005 (c) (10) For an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); N/A – Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis 20 AAC 25.005 (c) (11) For a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); The NDB-027 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 NDB-027 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed NDB-027 Drilling Program 1. Drill 20” conductor to ~128’ MD/TVD. Cement to surface. Install Cellar and landing ring on conductor. 2. Move in / rig up Parker 272. 3. Nipple up spacer spools over the 20” conductor. 4. Pick up 5-7/8” drill pipe, fill pits with spud mud and prepare for surface hole drilling. Make up 16” motor BHA with MWD and LWD tools. 5. Spud well and drill surface hole section to TD. Perform wiper trips as required. Circulate and condition hole to run casing. POOH and lay down BHA. 6. Run 13-3/8” 68# surface casing as per casing tally and land on pre-installed landing ring. Circulate and condition mud prior to commencing cement job. 7. Cement 13-3/8” casing as per cement program. Verify cement returns to surface. 8. NU casing head and spacer spool. NU BOPE with Rotating Control Device (RCD). BOP configured from top to bottom: annular preventor, 4-1/2” x 7” VBR, blind/shear, mud cross, 9-5/8” Fixed Rams. Test rams to 5000 psi high (initial test only – 3600 psi for subsequent tests) and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 48 hrs notice for witnessing BOP test. 9. Close blind shear rams and pressure test casing to 2600 psi for 30 min. 10. Make up 12-1/4” RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment and displace well to MOBM. 11. Drill out shoe track and 20 - 50’ of new formation. Perform FIT / LOT. 12. Directionally drill 12-1/4” intermediate hole section #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 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” VBR’s to 3-1/2” x 5-1/2” VBR’s. 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 tripping 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 set open hole hydraulic set packers 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 10bpm. 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 9.2 ppg 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 Requests 20 AAC 25.035. Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements. (h)(2) from the diverter system requirements in (c) of this section if the variance provides at least equally effective means of diverting flow away from the drill rig or if drilling experience in the near vicinity indicates that a diverter is not necessary A diverter variance is requested for the NDB-027 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. NDB-027 surface hole is surrounded by more than 18 other existing surface holes at the NDB pad location. Additionally, there are 4 previously drilled wells (NDB-037, NDB-032, NDBi-030 and NDB-024) within 600’ of the proposed NDB-027 surface hole TD location (see attachment 11). More than 34 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 18 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 NDB-027 well. NDB-027 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 NDB-027 be granted. 20 AAC 25.035. Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements. (e)(10)(A) when installed, repaired, or changed on a development or service well and at time intervals not to exceed each 14 days thereafter, BOPE, including kelly valves, emergency valves, and choke manifolds, must be function pressure-tested to the required working pressure specified in the approved Permit to Drill, using a non-compressible fluid, except that an annular type preventer need not be tested to more than 50 percent of its rated working pressure; however, the commission will require that the BOPE be function pressure-tested weekly, if the commission determines that a weekly BOPE pressure test interval is indicated by a particular drilling rig's BOPE performance A 21-day BOPE test schedule is planned as per the waiver acceptance letter and conditional requirements outlined in Docket Number OTH-25-010 from the AOGCC to Oil Search Alaska for Parker 272 operating at NDB (see attachment 12). 20 AAC 25.030. Casing and cementing (d)(5) intermediate and production casing must be cemented with sufficient cement to fill the annular space from the casing shoe to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above all significant hydrocarbon zones and abnormally geo- pressured strata or, if zonal coverage is not required under (a) of this section, from the casing shoe to a minimum of 500 feet measured depth or 250 feet true vertical depth, whichever is greater, above the casing shoe A variance is requested to the above regulation 20 AAC 25.030 (d)(5) for the following: 1. 9-5/8” Primary 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 ECD’s 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 100 feet TVD above the top of the Nanushuk formation. Due to ERD nature of this section (inclination 70-84°), additional TVD height of the cement top will significantly increase cement volumes and the subsequent risk of losses due to ECD’s exceeding the formation fracture gradient. Additionally, the 100 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 ~152 feet TVD (~1511 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. Variance request is denied. Pump cement volume to achieve 200' TVD above top Nanushuk, howeve r a 100' TVD result demonstrated by a cement quality log will be accepted. -bjm Attachments Attachment 1: Location Maps 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 2 300.0 0.00 0.00 300.0 0.0 0.0 0.00 0.00 0.0 3 1000.8 17.50 325.00 990.0 87.0 -60.9 2.50 325.00 105.2 4 1155.8 17.50 325.00 1137.8 125.2 -87.6 0.00 0.00 151.4 5 2728.0 64.00 308.59 2299.0 798.3 -817.5 3.01 -20.19 1141.0 6 2928.0 64.00 308.59 2386.7 910.4 -958.0 0.00 0.00 1318.7 7 3603.3 84.26 308.79 2570.4 1314.3 -1462.3 3.00 0.57 1957.6 8 16305.6 84.26 308.79 3841.5 9232.0 -11313.5 0.00 0.00 14456.4 9 17132.0 69.60 329.38 4029.8 9832.2 -11839.3 3.00 128.16 15254.2 10 17305.4 74.80 329.38 4082.8 9974.3 -11923.4 3.00 0.00 15415.6 11 17351.2 74.80 329.38 4094.8 10012.3 -11945.9 0.00 0.00 15458.8 12 17737.6 90.26 329.38 4144.9 10341.0 -12140.4 4.00 0.00 15832.3 NDB-027 Heel Rev 2.0 13 26893.3 90.37 329.38 4094.8 18220.4 -16803.1 0.00 -0.23 24785.6 NDB-027 Toe Rev 3.0 Plan: NDB-027 Rev F.0 Plan Summary 0 3 0 4000 8000 12000 16000 20000 24000 Measured Depth 20" Conductor Casing 9-5/8" Intermediate Liner 7" Intermediate Liner 4-1/2" Production Liner 45 45 90 90 0 90 180 270 30 210 60 240 120 300 150 330 Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [90 usft/in] 5075100125150175200225250275300325350375400425450475 5005255505756006256506757007257507758008258508759009259509751000102510501075110011251150115411751200122512501275130013251350137514001425145014751500152515501575160016251650167517001725175017751800182518501875190019251950Plan: NDBi-026 Rev A.0 4750751001251501752002252502753003253503754004254504755005255465505756006256506757007257507758008258508759009259509751000NDB-29 Slot Saver 475075100125150175200225250275300325350 375400425450475500525550575600625650675700725750775800825850875900925 950975 10001025105010751100112511501175120012251250125312751300132513501375140014251450147515001525155015751600162516501675170017251750177518001825185018751900192519501975200020252050207521002125215021752200222522502275230023252350NDBi-030 475075100125150175200225250275300325350375400425450475500525550575600625650675700725750775NDB-023 Slot Saver 475075100125150175200225250275300325327350375400425450475500525550575600625650675700725750775 800NDB-025 75100125150175200225250275300325350375399400411425450475500525550575600625650675 700 725 750 775 800Plan NDBi-028 Rev A.0 475075100125150175200225250275300325350375399400425450475500525550575600625650675700725Plan: NDB-031 Rev E.1 475075100125150175200225250275300325350375400425450475500525550575600625650675700725750775800825850875900925950974975100010251050107511001125115011751200122512501275130013251350NDB-032 475075100125150175189200225250275300325350375400425450475500525550575600625650675700725750775800825850875900925950975100010251050107511001125115011741175120012251250127513001325135013751400142514501475150015251550157516001625NDB-024PB1 475075100125150175189200225250275300325350375400425450475500525550575600625650675700725750775800825850875900925950975100010251050107511001125115011741175120012251250127513001325135013751400142514501475150015251550157516001625NDB-024 475075100125150175200225250275300325350375400425450 475500525550575600625650Plan NDB-022 Rev A.0 0 2250 0 3500 7000 10500 14000 17500 21000 24500 Vertical Section at 317.32° 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Intermediate Liner 4-1/2" Production Liner 0 28 55 0 275 550 825 1100 1375 1650 1925 Measured Depth Equivalent Magnetic Distance DDI 7.514 SURVEY PROGRAM Date: 2021-02-16T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 47.0 1000.0 Plan: NDB-027 Rev F.0 (NDB-027)SDI_URSA1_I4 1000.0 2926.0 Plan: NDB-027 Rev F.0 (NDB-027)3_MWD+IFR2+MS+Sag 2926.0 12000.0 Plan: NDB-027 Rev F.0 (NDB-027)3_MWD+IFR2+MS+Sag 12000.0 17306.0 Plan: NDB-027 Rev F.0 (NDB-027)3_MWD+IFR2+MS+Sag 17306.0 26893.3 Plan: NDB-027 Rev F.0 (NDB-027)3_MWD+IFR2+MS+Sag Surface Location North / 5972525.15 East / 1562244.72 Elevation / 22.8 CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2385.8 2926.013-3/8" Surface Casing 3410.6 12000.09-5/8" Intermediate Liner 4082.9 17306.0 7" Intermediate Liner 4094.8 26893.34-1/2" Production Liner Mag Model & Date: BGGM2024 04-Sep-25 Magnetic North is 13.60° East of True North (Magnetic De Mag Dip & Field Strength: 80.52°57114.03874 FORMATION TOP DETAILS TVDPathFormation 1046.8 Upper SB 1138.8 Base Ice B Perm 1393.8 BP Transition 1741.8 Middle SB 2135.8 MCU 2438.8 Tuluvak Shale 2499.8 Tuluvak Sand 2794.8 TS_790 3139.8 Seabee 3797.8 Nanushuk 3850.8 NT8 MFS 3898.8 NT7 MFS 3939.8 NT6 MFS 3968.8 NT5 MFS 4012.8 NT4 MFS 4082.8 NT3 MFS 4092.8NT3.2 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 surrounding wells 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 Rig on 27 @ 69.8usft Standard Planning Report - Geographic 21 May, 2025 Plan: Plan: NDB-027 Rev F.0 Santos NAD27 Conversion Pikka NDB B-27 NDB-027 Santos Ltd Planning Report - Geographic Well B-27Local Co-ordinate Reference:Database:EDM Rig on 27 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Rig on 27 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-27Well: NDB-027Wellbore: Plan: NDB-027 Rev F.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-27 Wellhead Elevation:0.5 0.0 0.0 5,972,777.15 422,211.92 0.0 70° 20' 8.716 N 150° 37' 51.974 W 22.8 usft usft usft usft usft usft usft °-0.59Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NDB-027 Model NameMagnetics BGGM2024 4/09/2025 13.60 80.52 57,114.03847043 Phase:Version: Audit Notes: Design Plan: NDB-027 Rev F.0 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:47.0 317.320.00.047.0 Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Date 21/05/2025 Depth To (usft) Depth From (usft) SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISC Plan: NDB-027 Rev F.0 (NDB-02147.0 1,000.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-027 Rev F.0 (NDB-0221,000.0 2,926.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-027 Rev F.0 (NDB-0232,926.0 12,000.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-027 Rev F.0 (NDB-02412,000.0 17,306.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-027 Rev F.0 (NDB-02517,306.0 26,865.4 21/05/2025 14:58:07 COMPASS 5000.17 Build Page 2 Santos Ltd Planning Report - Geographic Well B-27Local Co-ordinate Reference:Database:EDM Rig on 27 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Rig on 27 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-27Well: NDB-027Wellbore: Plan: NDB-027 Rev F.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 0.000.000.000.000.00.0300.00.000.00300.0 325.000.002.502.50-60.987.0990.0325.0017.501,000.8 0.000.000.000.00-87.6125.21,137.8325.0017.501,155.8 -20.19-1.042.963.01-817.5798.32,299.0308.5964.002,728.0 0.000.000.000.00-958.0910.42,386.7308.5964.002,928.0 0.590.033.003.00-1,462.31,314.42,570.4308.7984.263,603.3 0.000.000.000.00-11,312.79,232.63,841.5308.7984.2616,305.4 128.172.49-1.773.00-11,838.59,832.74,029.8329.3969.6017,131.6 0.000.003.003.00-11,922.69,974.84,082.8329.3974.8017,305.1 0.000.000.000.00-11,945.110,012.84,094.8329.3974.8017,350.9 0.000.004.004.00-12,139.610,341.54,144.9329.3990.2617,737.3 NDB-027 Heel Rev 4.620.000.000.00-16,801.618,221.44,094.8329.3990.3726,893.1 NDB-027 Toe Rev 3 21/05/2025 14:58:07 COMPASS 5000.17 Build Page 3 Santos Ltd Planning Report - Geographic Well B-27Local Co-ordinate Reference:Database:EDM Rig on 27 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Rig on 27 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-27Well: NDB-027Wellbore: Plan: NDB-027 Rev F.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 0.00.00 422,211.925,972,777.15 70° 20' 8.716 N 150° 37' 51.974 W 100.0 0.00 100.0 0.0 0.00.00 422,211.925,972,777.15 70° 20' 8.716 N 150° 37' 51.974 W 128.0 0.00 128.0 0.0 0.00.00 422,211.925,972,777.15 70° 20' 8.716 N 150° 37' 51.974 W 20" Conductor Casing 200.0 0.00 200.0 0.0 0.00.00 422,211.925,972,777.15 70° 20' 8.716 N 150° 37' 51.974 W 300.0 0.00 300.0 0.0 0.00.00 422,211.925,972,777.15 70° 20' 8.716 N 150° 37' 51.974 W 347.0 1.17 347.0 0.4 -0.3325.00 422,211.655,972,777.55 70° 20' 8.719 N 150° 37' 51.982 W Start Build 2.50 400.0 2.50 400.0 1.8 -1.2325.00 422,210.695,972,778.95 70° 20' 8.733 N 150° 37' 52.011 W 500.0 4.99 499.7 7.1 -5.0325.00 422,207.005,972,784.34 70° 20' 8.786 N 150° 37' 52.120 W 587.0 7.17 586.3 14.7 -10.3325.00 422,201.795,972,791.94 70° 20' 8.860 N 150° 37' 52.274 W Start DLS 3.00 TFO -37.01 600.0 7.49 599.1 16.0 -11.2325.00 422,200.855,972,793.31 70° 20' 8.873 N 150° 37' 52.302 W 700.0 9.99 698.0 28.5 -19.9325.00 422,192.275,972,805.84 70° 20' 8.996 N 150° 37' 52.557 W 800.0 12.48 796.1 44.4 -31.1325.00 422,181.265,972,821.92 70° 20' 9.153 N 150° 37' 52.883 W 900.0 14.98 893.2 63.9 -44.7325.00 422,167.855,972,841.50 70° 20' 9.344 N 150° 37' 53.281 W 996.6 17.39 985.9 85.9 -60.2325.00 422,152.645,972,863.71 70° 20' 9.561 N 150° 37' 53.732 W Start 150.0 hold at 996.6 MD 1,000.0 17.48 989.2 86.8 -60.8325.00 422,152.065,972,864.56 70° 20' 9.569 N 150° 37' 53.749 W 1,000.8 17.50 990.0 87.0 -60.9325.00 422,151.925,972,864.77 70° 20' 9.571 N 150° 37' 53.753 W 1,060.4 17.50 1,046.8 101.7 -71.2325.00 422,141.805,972,879.54 70° 20' 9.715 N 150° 37' 54.053 W Upper Schrader Bluff 1,100.0 17.50 1,084.6 111.4 -78.0325.00 422,135.075,972,889.37 70° 20' 9.811 N 150° 37' 54.253 W 1,146.6 17.50 1,129.0 122.9 -86.0325.00 422,127.165,972,900.92 70° 20' 9.924 N 150° 37' 54.487 W Start DLS 3.00 TFO -12.01 1,155.8 17.50 1,137.8 125.2 -87.6325.00 422,125.585,972,903.22 70° 20' 9.947 N 150° 37' 54.534 W 1,156.9 17.53 1,138.8 125.4 -87.8324.96 422,125.415,972,903.47 70° 20' 9.949 N 150° 37' 54.539 W Base Ice Bearing Permafrost 1,200.0 18.75 1,179.8 136.3 -95.7323.57 422,117.685,972,914.45 70° 20' 10.056 N 150° 37' 54.768 W 1,300.0 21.63 1,273.6 163.6 -116.8320.93 422,096.805,972,941.91 70° 20' 10.324 N 150° 37' 55.386 W 1,400.0 24.53 1,365.6 193.5 -142.1318.89 422,071.845,972,972.13 70° 20' 10.619 N 150° 37' 56.124 W 1,431.1 25.44 1,393.8 203.4 -150.8318.35 422,063.275,972,982.07 70° 20' 10.716 N 150° 37' 56.378 W Base Permafrost Transition 1,500.0 27.46 1,455.5 226.1 -171.4317.26 422,042.885,973,005.01 70° 20' 10.939 N 150° 37' 56.980 W 1,600.0 30.40 1,543.0 261.2 -204.7315.92 422,009.995,973,040.46 70° 20' 11.285 N 150° 37' 57.951 W 1,700.0 33.35 1,627.9 298.8 -241.8314.79 421,973.275,973,078.39 70° 20' 11.654 N 150° 37' 59.035 W 1,800.0 36.32 1,710.0 338.7 -282.7313.83 421,932.815,973,118.70 70° 20' 12.046 N 150° 38' 0.229 W 1,839.8 37.50 1,741.8 355.2 -299.9313.49 421,915.715,973,135.37 70° 20' 12.208 N 150° 38' 0.734 W Middle Schrader Bluff 1,900.0 39.29 1,789.0 380.8 -327.2313.00 421,888.735,973,161.26 70° 20' 12.460 N 150° 38' 1.530 W 2,000.0 42.26 1,864.7 425.0 -375.2312.27 421,841.155,973,205.97 70° 20' 12.895 N 150° 38' 2.933 W 2,100.0 45.24 1,937.0 471.2 -426.7311.61 421,790.205,973,252.70 70° 20' 13.350 N 150° 38' 4.435 W 2,200.0 48.22 2,005.5 519.3 -481.4311.02 421,736.025,973,301.32 70° 20' 13.822 N 150° 38' 6.033 W 2,300.0 51.20 2,070.1 569.0 -539.1310.48 421,678.765,973,351.70 70° 20' 14.312 N 150° 38' 7.720 W 2,400.0 54.19 2,130.7 620.4 -599.9309.99 421,618.585,973,403.69 70° 20' 14.817 N 150° 38' 9.494 W 2,408.7 54.45 2,135.8 624.9 -605.3309.95 421,613.235,973,408.28 70° 20' 14.861 N 150° 38' 9.652 W MCU 2,500.0 57.18 2,187.1 673.2 -663.3309.53 421,555.655,973,457.16 70° 20' 15.336 N 150° 38' 11.348 W 2,600.0 60.17 2,239.1 727.3 -729.4309.10 421,490.145,973,511.95 70° 20' 15.869 N 150° 38' 13.278 W 2,700.0 63.16 2,286.5 782.6 -797.9308.70 421,422.235,973,567.92 70° 20' 16.412 N 150° 38' 15.279 W 2,728.0 64.00 2,299.0 798.3 -817.5308.59 421,402.815,973,583.78 70° 20' 16.566 N 150° 38' 15.851 W 2,800.0 64.00 2,330.6 838.6 -868.1308.59 421,352.655,973,624.66 70° 20' 16.963 N 150° 38' 17.329 W 2,900.0 64.00 2,374.4 894.7 -938.3308.59 421,282.995,973,681.45 70° 20' 17.514 N 150° 38' 19.381 W 2,926.0 64.00 2,385.8 909.3 -956.6308.59 421,264.885,973,696.21 70° 20' 17.658 N 150° 38' 19.914 W 13-3/8" Surface Casing 2,928.0 64.00 2,386.7 910.4 -958.0308.59 421,263.495,973,697.34 70° 20' 17.669 N 150° 38' 19.955 W 3,000.0 66.16 2,417.0 951.1 -1,009.0308.61 421,212.895,973,738.60 70° 20' 18.069 N 150° 38' 21.446 W 21/05/2025 14:58:07 COMPASS 5000.17 Build Page 4 Santos Ltd Planning Report - Geographic Well B-27Local Co-ordinate Reference:Database:EDM Rig on 27 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Rig on 27 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-27Well: NDB-027Wellbore: Plan: NDB-027 Rev F.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) 3,055.8 67.83 2,438.8 983.2 -1,049.1308.63 421,173.145,973,771.05 70° 20' 18.384 N 150° 38' 22.617 W Tuluvak Shale 3,100.0 69.16 2,455.0 1,008.9 -1,081.3308.65 421,141.255,973,797.08 70° 20' 18.637 N 150° 38' 23.556 W 3,200.0 72.16 2,488.1 1,067.8 -1,155.0308.68 421,068.215,973,856.78 70° 20' 19.216 N 150° 38' 25.708 W 3,239.3 73.34 2,499.8 1,091.3 -1,184.3308.69 421,039.135,973,880.56 70° 20' 19.447 N 150° 38' 26.565 W Tuluvak Sand 3,300.0 75.16 2,516.3 1,127.8 -1,229.8308.71 420,993.955,973,917.53 70° 20' 19.806 N 150° 38' 27.896 W 3,367.9 77.20 2,532.5 1,169.0 -1,281.3308.73 420,942.925,973,959.31 70° 20' 20.212 N 150° 38' 29.399 W Start 12819.2 hold at 3367.9 MD 3,400.0 78.16 2,539.3 1,188.6 -1,305.8308.74 420,918.695,973,979.17 70° 20' 20.405 N 150° 38' 30.113 W 3,500.0 81.16 2,557.3 1,250.2 -1,382.5308.76 420,842.625,974,041.52 70° 20' 21.010 N 150° 38' 32.354 W 3,600.0 84.16 2,570.1 1,312.3 -1,459.8308.79 420,765.975,974,104.43 70° 20' 21.621 N 150° 38' 34.613 W 3,603.3 84.26 2,570.4 1,314.4 -1,462.3308.79 420,763.465,974,106.48 70° 20' 21.641 N 150° 38' 34.687 W 3,700.0 84.26 2,580.1 1,374.7 -1,537.3308.79 420,689.085,974,167.56 70° 20' 22.234 N 150° 38' 36.878 W 3,800.0 84.26 2,590.1 1,437.0 -1,614.9308.79 420,612.195,974,230.69 70° 20' 22.847 N 150° 38' 39.144 W 3,900.0 84.26 2,600.1 1,499.3 -1,692.4308.79 420,535.305,974,293.82 70° 20' 23.460 N 150° 38' 41.409 W 4,000.0 84.26 2,610.1 1,561.7 -1,770.0308.79 420,458.415,974,356.96 70° 20' 24.072 N 150° 38' 43.675 W 4,100.0 84.26 2,620.1 1,624.0 -1,847.5308.79 420,381.515,974,420.09 70° 20' 24.685 N 150° 38' 45.941 W 4,200.0 84.26 2,630.1 1,686.4 -1,925.1308.79 420,304.625,974,483.22 70° 20' 25.298 N 150° 38' 48.206 W 4,300.0 84.26 2,640.1 1,748.7 -2,002.6308.79 420,227.735,974,546.36 70° 20' 25.911 N 150° 38' 50.472 W 4,400.0 84.26 2,650.1 1,811.0 -2,080.2308.79 420,150.845,974,609.49 70° 20' 26.524 N 150° 38' 52.738 W 4,500.0 84.26 2,660.1 1,873.4 -2,157.7308.79 420,073.955,974,672.62 70° 20' 27.137 N 150° 38' 55.004 W 4,600.0 84.26 2,670.1 1,935.7 -2,235.3308.79 419,997.065,974,735.75 70° 20' 27.750 N 150° 38' 57.269 W 4,700.0 84.26 2,680.1 1,998.0 -2,312.8308.79 419,920.175,974,798.89 70° 20' 28.363 N 150° 38' 59.535 W 4,800.0 84.26 2,690.1 2,060.4 -2,390.4308.79 419,843.285,974,862.02 70° 20' 28.975 N 150° 39' 1.801 W 4,900.0 84.26 2,700.2 2,122.7 -2,467.9308.79 419,766.385,974,925.15 70° 20' 29.588 N 150° 39' 4.067 W 5,000.0 84.26 2,710.2 2,185.1 -2,545.5308.79 419,689.495,974,988.29 70° 20' 30.201 N 150° 39' 6.333 W 5,100.0 84.26 2,720.2 2,247.4 -2,623.0308.79 419,612.605,975,051.42 70° 20' 30.814 N 150° 39' 8.599 W 5,200.0 84.26 2,730.2 2,309.7 -2,700.6308.79 419,535.715,975,114.55 70° 20' 31.427 N 150° 39' 10.865 W 5,300.0 84.26 2,740.2 2,372.1 -2,778.1308.79 419,458.825,975,177.68 70° 20' 32.040 N 150° 39' 13.131 W 5,400.0 84.26 2,750.2 2,434.4 -2,855.7308.79 419,381.935,975,240.82 70° 20' 32.652 N 150° 39' 15.398 W 5,500.0 84.26 2,760.2 2,496.7 -2,933.2308.79 419,305.045,975,303.95 70° 20' 33.265 N 150° 39' 17.664 W 5,600.0 84.26 2,770.2 2,559.1 -3,010.8308.79 419,228.155,975,367.08 70° 20' 33.878 N 150° 39' 19.930 W 5,700.0 84.26 2,780.2 2,621.4 -3,088.3308.79 419,151.255,975,430.22 70° 20' 34.491 N 150° 39' 22.196 W 5,800.0 84.26 2,790.2 2,683.8 -3,165.9308.79 419,074.365,975,493.35 70° 20' 35.103 N 150° 39' 24.462 W 5,845.8 84.26 2,794.8 2,712.3 -3,201.4308.79 419,039.135,975,522.27 70° 20' 35.384 N 150° 39' 25.501 W TS_790 5,900.0 84.26 2,800.2 2,746.1 -3,243.4308.79 418,997.475,975,556.48 70° 20' 35.716 N 150° 39' 26.729 W 6,000.0 84.26 2,810.2 2,808.4 -3,321.0308.79 418,920.585,975,619.61 70° 20' 36.329 N 150° 39' 28.995 W 6,100.0 84.26 2,820.2 2,870.8 -3,398.5308.79 418,843.695,975,682.75 70° 20' 36.942 N 150° 39' 31.262 W 6,200.0 84.26 2,830.2 2,933.1 -3,476.1308.79 418,766.805,975,745.88 70° 20' 37.554 N 150° 39' 33.528 W 6,300.0 84.26 2,840.2 2,995.4 -3,553.6308.79 418,689.915,975,809.01 70° 20' 38.167 N 150° 39' 35.795 W 6,400.0 84.26 2,850.3 3,057.8 -3,631.2308.79 418,613.015,975,872.15 70° 20' 38.780 N 150° 39' 38.061 W 6,500.0 84.26 2,860.3 3,120.1 -3,708.7308.79 418,536.125,975,935.28 70° 20' 39.393 N 150° 39' 40.328 W 6,600.0 84.26 2,870.3 3,182.5 -3,786.3308.79 418,459.235,975,998.41 70° 20' 40.005 N 150° 39' 42.594 W 6,700.0 84.26 2,880.3 3,244.8 -3,863.8308.79 418,382.345,976,061.54 70° 20' 40.618 N 150° 39' 44.861 W 6,800.0 84.26 2,890.3 3,307.1 -3,941.3308.79 418,305.455,976,124.68 70° 20' 41.231 N 150° 39' 47.127 W 6,900.0 84.26 2,900.3 3,369.5 -4,018.9308.79 418,228.565,976,187.81 70° 20' 41.843 N 150° 39' 49.394 W 7,000.0 84.26 2,910.3 3,431.8 -4,096.4308.79 418,151.675,976,250.94 70° 20' 42.456 N 150° 39' 51.661 W 7,100.0 84.26 2,920.3 3,494.1 -4,174.0308.79 418,074.785,976,314.07 70° 20' 43.069 N 150° 39' 53.928 W 7,200.0 84.26 2,930.3 3,556.5 -4,251.5308.79 417,997.885,976,377.21 70° 20' 43.681 N 150° 39' 56.195 W 7,300.0 84.26 2,940.3 3,618.8 -4,329.1308.79 417,920.995,976,440.34 70° 20' 44.294 N 150° 39' 58.461 W 7,400.0 84.26 2,950.3 3,681.2 -4,406.6308.79 417,844.105,976,503.47 70° 20' 44.907 N 150° 40' 0.728 W 7,500.0 84.26 2,960.3 3,743.5 -4,484.2308.79 417,767.215,976,566.61 70° 20' 45.519 N 150° 40' 2.995 W 7,600.0 84.26 2,970.3 3,805.8 -4,561.7308.79 417,690.325,976,629.74 70° 20' 46.132 N 150° 40' 5.262 W 7,700.0 84.26 2,980.3 3,868.2 -4,639.3308.79 417,613.435,976,692.87 70° 20' 46.744 N 150° 40' 7.529 W 7,800.0 84.26 2,990.4 3,930.5 -4,716.8308.79 417,536.545,976,756.00 70° 20' 47.357 N 150° 40' 9.796 W 7,900.0 84.26 3,000.4 3,992.8 -4,794.4308.79 417,459.655,976,819.14 70° 20' 47.970 N 150° 40' 12.063 W 8,000.0 84.26 3,010.4 4,055.2 -4,871.9308.79 417,382.755,976,882.27 70° 20' 48.582 N 150° 40' 14.330 W 21/05/2025 14:58:07 COMPASS 5000.17 Build Page 5 Santos Ltd Planning Report - Geographic Well B-27Local Co-ordinate Reference:Database:EDM Rig on 27 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Rig on 27 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-27Well: NDB-027Wellbore: Plan: NDB-027 Rev F.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) 8,100.0 84.26 3,020.4 4,117.5 -4,949.5308.79 417,305.865,976,945.40 70° 20' 49.195 N 150° 40' 16.598 W 8,200.0 84.26 3,030.4 4,179.9 -5,027.0308.79 417,228.975,977,008.54 70° 20' 49.807 N 150° 40' 18.865 W 8,300.0 84.26 3,040.4 4,242.2 -5,104.6308.79 417,152.085,977,071.67 70° 20' 50.420 N 150° 40' 21.132 W 8,400.0 84.26 3,050.4 4,304.5 -5,182.1308.79 417,075.195,977,134.80 70° 20' 51.033 N 150° 40' 23.399 W 8,500.0 84.26 3,060.4 4,366.9 -5,259.7308.79 416,998.305,977,197.93 70° 20' 51.645 N 150° 40' 25.667 W 8,600.0 84.26 3,070.4 4,429.2 -5,337.2308.79 416,921.415,977,261.07 70° 20' 52.258 N 150° 40' 27.934 W 8,700.0 84.26 3,080.4 4,491.5 -5,414.8308.79 416,844.525,977,324.20 70° 20' 52.870 N 150° 40' 30.201 W 8,800.0 84.26 3,090.4 4,553.9 -5,492.3308.79 416,767.625,977,387.33 70° 20' 53.483 N 150° 40' 32.469 W 8,900.0 84.26 3,100.4 4,616.2 -5,569.9308.79 416,690.735,977,450.47 70° 20' 54.095 N 150° 40' 34.736 W 9,000.0 84.26 3,110.4 4,678.6 -5,647.4308.79 416,613.845,977,513.60 70° 20' 54.708 N 150° 40' 37.004 W 9,100.0 84.26 3,120.4 4,740.9 -5,725.0308.79 416,536.955,977,576.73 70° 20' 55.320 N 150° 40' 39.271 W 9,200.0 84.26 3,130.4 4,803.2 -5,802.5308.79 416,460.065,977,639.86 70° 20' 55.933 N 150° 40' 41.539 W 9,293.4 84.26 3,139.8 4,861.5 -5,875.0308.79 416,388.215,977,698.85 70° 20' 56.505 N 150° 40' 43.658 W Seabee 9,300.0 84.26 3,140.5 4,865.6 -5,880.1308.79 416,383.175,977,703.00 70° 20' 56.545 N 150° 40' 43.807 W 9,400.0 84.26 3,150.5 4,927.9 -5,957.6308.79 416,306.285,977,766.13 70° 20' 57.158 N 150° 40' 46.074 W 9,500.0 84.26 3,160.5 4,990.2 -6,035.2308.79 416,229.395,977,829.26 70° 20' 57.770 N 150° 40' 48.342 W 9,600.0 84.26 3,170.5 5,052.6 -6,112.7308.79 416,152.495,977,892.39 70° 20' 58.383 N 150° 40' 50.610 W 9,700.0 84.26 3,180.5 5,114.9 -6,190.3308.79 416,075.605,977,955.53 70° 20' 58.995 N 150° 40' 52.877 W 9,800.0 84.26 3,190.5 5,177.3 -6,267.8308.79 415,998.715,978,018.66 70° 20' 59.608 N 150° 40' 55.145 W 9,900.0 84.26 3,200.5 5,239.6 -6,345.4308.79 415,921.825,978,081.79 70° 21' 0.220 N 150° 40' 57.413 W 10,000.0 84.26 3,210.5 5,301.9 -6,422.9308.79 415,844.935,978,144.93 70° 21' 0.832 N 150° 40' 59.681 W 10,100.0 84.26 3,220.5 5,364.3 -6,500.5308.79 415,768.045,978,208.06 70° 21' 1.445 N 150° 41' 1.949 W 10,200.0 84.26 3,230.5 5,426.6 -6,578.0308.79 415,691.155,978,271.19 70° 21' 2.057 N 150° 41' 4.217 W 10,300.0 84.26 3,240.5 5,488.9 -6,655.6308.79 415,614.265,978,334.32 70° 21' 2.670 N 150° 41' 6.485 W 10,400.0 84.26 3,250.5 5,551.3 -6,733.1308.79 415,537.365,978,397.46 70° 21' 3.282 N 150° 41' 8.753 W 10,500.0 84.26 3,260.5 5,613.6 -6,810.7308.79 415,460.475,978,460.59 70° 21' 3.894 N 150° 41' 11.021 W 10,600.0 84.26 3,270.5 5,676.0 -6,888.2308.79 415,383.585,978,523.72 70° 21' 4.507 N 150° 41' 13.289 W 10,700.0 84.26 3,280.6 5,738.3 -6,965.8308.79 415,306.695,978,586.86 70° 21' 5.119 N 150° 41' 15.557 W 10,800.0 84.26 3,290.6 5,800.6 -7,043.3308.79 415,229.805,978,649.99 70° 21' 5.732 N 150° 41' 17.825 W 10,900.0 84.26 3,300.6 5,863.0 -7,120.9308.79 415,152.915,978,713.12 70° 21' 6.344 N 150° 41' 20.093 W 11,000.0 84.26 3,310.6 5,925.3 -7,198.4308.79 415,076.025,978,776.25 70° 21' 6.956 N 150° 41' 22.362 W 11,100.0 84.26 3,320.6 5,987.6 -7,276.0308.79 414,999.135,978,839.39 70° 21' 7.569 N 150° 41' 24.630 W 11,200.0 84.26 3,330.6 6,050.0 -7,353.5308.79 414,922.235,978,902.52 70° 21' 8.181 N 150° 41' 26.898 W 11,300.0 84.26 3,340.6 6,112.3 -7,431.1308.79 414,845.345,978,965.65 70° 21' 8.793 N 150° 41' 29.167 W 11,400.0 84.26 3,350.6 6,174.7 -7,508.6308.79 414,768.455,979,028.79 70° 21' 9.406 N 150° 41' 31.435 W 11,500.0 84.26 3,360.6 6,237.0 -7,586.2308.79 414,691.565,979,091.92 70° 21' 10.018 N 150° 41' 33.704 W 11,600.0 84.26 3,370.6 6,299.3 -7,663.7308.79 414,614.675,979,155.05 70° 21' 10.630 N 150° 41' 35.972 W 11,700.0 84.26 3,380.6 6,361.7 -7,741.3308.79 414,537.785,979,218.18 70° 21' 11.243 N 150° 41' 38.241 W 11,800.0 84.26 3,390.6 6,424.0 -7,818.8308.79 414,460.895,979,281.32 70° 21' 11.855 N 150° 41' 40.509 W 11,900.0 84.26 3,400.6 6,486.4 -7,896.4308.79 414,384.005,979,344.45 70° 21' 12.467 N 150° 41' 42.778 W 12,000.0 84.26 3,410.6 6,548.7 -7,973.9308.79 414,307.105,979,407.58 70° 21' 13.079 N 150° 41' 45.046 W 9-5/8" Intermediate Liner 12,100.0 84.26 3,420.6 6,611.0 -8,051.5308.79 414,230.215,979,470.72 70° 21' 13.692 N 150° 41' 47.315 W 12,200.0 84.26 3,430.7 6,673.4 -8,129.0308.79 414,153.325,979,533.85 70° 21' 14.304 N 150° 41' 49.584 W 12,300.0 84.26 3,440.7 6,735.7 -8,206.6308.79 414,076.435,979,596.98 70° 21' 14.916 N 150° 41' 51.852 W 12,400.0 84.26 3,450.7 6,798.0 -8,284.1308.79 413,999.545,979,660.11 70° 21' 15.528 N 150° 41' 54.121 W 12,500.0 84.26 3,460.7 6,860.4 -8,361.7308.79 413,922.655,979,723.25 70° 21' 16.141 N 150° 41' 56.390 W 12,600.0 84.26 3,470.7 6,922.7 -8,439.2308.79 413,845.765,979,786.38 70° 21' 16.753 N 150° 41' 58.659 W 12,700.0 84.26 3,480.7 6,985.1 -8,516.8308.79 413,768.875,979,849.51 70° 21' 17.365 N 150° 42' 0.928 W 12,800.0 84.26 3,490.7 7,047.4 -8,594.3308.79 413,691.975,979,912.64 70° 21' 17.977 N 150° 42' 3.197 W 12,900.0 84.26 3,500.7 7,109.7 -8,671.8308.79 413,615.085,979,975.78 70° 21' 18.590 N 150° 42' 5.466 W 13,000.0 84.26 3,510.7 7,172.1 -8,749.4308.79 413,538.195,980,038.91 70° 21' 19.202 N 150° 42' 7.735 W 13,100.0 84.26 3,520.7 7,234.4 -8,826.9308.79 413,461.305,980,102.04 70° 21' 19.814 N 150° 42' 10.004 W 13,200.0 84.26 3,530.7 7,296.7 -8,904.5308.79 413,384.415,980,165.18 70° 21' 20.426 N 150° 42' 12.273 W 13,300.0 84.26 3,540.7 7,359.1 -8,982.0308.79 413,307.525,980,228.31 70° 21' 21.038 N 150° 42' 14.542 W 13,400.0 84.26 3,550.7 7,421.4 -9,059.6308.79 413,230.635,980,291.44 70° 21' 21.650 N 150° 42' 16.811 W 13,500.0 84.26 3,560.7 7,483.8 -9,137.1308.79 413,153.735,980,354.57 70° 21' 22.263 N 150° 42' 19.080 W 13,600.0 84.26 3,570.8 7,546.1 -9,214.7308.79 413,076.845,980,417.71 70° 21' 22.875 N 150° 42' 21.350 W 21/05/2025 14:58:07 COMPASS 5000.17 Build Page 6 Santos Ltd Planning Report - Geographic Well B-27Local Co-ordinate Reference:Database:EDM Rig on 27 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Rig on 27 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-27Well: NDB-027Wellbore: Plan: NDB-027 Rev F.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) 13,700.0 84.26 3,580.8 7,608.4 -9,292.2308.79 412,999.955,980,480.84 70° 21' 23.487 N 150° 42' 23.619 W 13,800.0 84.26 3,590.8 7,670.8 -9,369.8308.79 412,923.065,980,543.97 70° 21' 24.099 N 150° 42' 25.888 W 13,900.0 84.26 3,600.8 7,733.1 -9,447.3308.79 412,846.175,980,607.11 70° 21' 24.711 N 150° 42' 28.157 W 14,000.0 84.26 3,610.8 7,795.4 -9,524.9308.79 412,769.285,980,670.24 70° 21' 25.323 N 150° 42' 30.427 W 14,100.0 84.26 3,620.8 7,857.8 -9,602.4308.79 412,692.395,980,733.37 70° 21' 25.935 N 150° 42' 32.696 W 14,200.0 84.26 3,630.8 7,920.1 -9,680.0308.79 412,615.505,980,796.50 70° 21' 26.547 N 150° 42' 34.966 W 14,300.0 84.26 3,640.8 7,982.5 -9,757.5308.79 412,538.605,980,859.64 70° 21' 27.160 N 150° 42' 37.235 W 14,400.0 84.26 3,650.8 8,044.8 -9,835.1308.79 412,461.715,980,922.77 70° 21' 27.772 N 150° 42' 39.505 W 14,500.0 84.26 3,660.8 8,107.1 -9,912.6308.79 412,384.825,980,985.90 70° 21' 28.384 N 150° 42' 41.774 W 14,600.0 84.26 3,670.8 8,169.5 -9,990.2308.79 412,307.935,981,049.04 70° 21' 28.996 N 150° 42' 44.044 W 14,700.0 84.26 3,680.8 8,231.8 -10,067.7308.79 412,231.045,981,112.17 70° 21' 29.608 N 150° 42' 46.314 W 14,800.0 84.26 3,690.8 8,294.1 -10,145.3308.79 412,154.155,981,175.30 70° 21' 30.220 N 150° 42' 48.583 W 14,900.0 84.26 3,700.8 8,356.5 -10,222.8308.79 412,077.265,981,238.43 70° 21' 30.832 N 150° 42' 50.853 W 15,000.0 84.26 3,710.8 8,418.8 -10,300.4308.79 412,000.375,981,301.57 70° 21' 31.444 N 150° 42' 53.123 W 15,100.0 84.26 3,720.9 8,481.2 -10,377.9308.79 411,923.475,981,364.70 70° 21' 32.056 N 150° 42' 55.393 W 15,200.0 84.26 3,730.9 8,543.5 -10,455.5308.79 411,846.585,981,427.83 70° 21' 32.668 N 150° 42' 57.662 W 15,300.0 84.26 3,740.9 8,605.8 -10,533.0308.79 411,769.695,981,490.96 70° 21' 33.280 N 150° 42' 59.932 W 15,400.0 84.26 3,750.9 8,668.2 -10,610.6308.79 411,692.805,981,554.10 70° 21' 33.892 N 150° 43' 2.202 W 15,500.0 84.26 3,760.9 8,730.5 -10,688.1308.79 411,615.915,981,617.23 70° 21' 34.504 N 150° 43' 4.472 W 15,600.0 84.26 3,770.9 8,792.8 -10,765.7308.79 411,539.025,981,680.36 70° 21' 35.116 N 150° 43' 6.742 W 15,700.0 84.26 3,780.9 8,855.2 -10,843.2308.79 411,462.135,981,743.50 70° 21' 35.728 N 150° 43' 9.012 W 15,800.0 84.26 3,790.9 8,917.5 -10,920.8308.79 411,385.245,981,806.63 70° 21' 36.340 N 150° 43' 11.282 W 15,868.9 84.26 3,797.8 8,960.5 -10,974.2308.79 411,332.255,981,850.13 70° 21' 36.762 N 150° 43' 12.846 W Nanushuk 15,900.0 84.26 3,800.9 8,979.9 -10,998.3308.79 411,308.345,981,869.76 70° 21' 36.952 N 150° 43' 13.552 W 16,000.0 84.26 3,810.9 9,042.2 -11,075.9308.79 411,231.455,981,932.89 70° 21' 37.564 N 150° 43' 15.822 W 16,100.0 84.26 3,820.9 9,104.5 -11,153.4308.79 411,154.565,981,996.03 70° 21' 38.176 N 150° 43' 18.093 W 16,187.2 84.26 3,829.6 9,158.9 -11,221.0308.79 411,087.545,982,051.05 70° 21' 38.709 N 150° 43' 20.071 W Start DLS 3.00 TFO 126.98 16,200.0 84.26 3,830.9 9,166.9 -11,231.0308.79 411,077.675,982,059.16 70° 21' 38.788 N 150° 43' 20.363 W 16,300.0 84.26 3,840.9 9,229.2 -11,308.5308.79 411,000.785,982,122.29 70° 21' 39.400 N 150° 43' 22.633 W 16,305.4 84.26 3,841.5 9,232.6 -11,312.7308.79 410,996.635,982,125.70 70° 21' 39.433 N 150° 43' 22.756 W 16,387.7 82.74 3,850.8 9,284.9 -11,375.5310.75 410,934.355,982,178.64 70° 21' 39.946 N 150° 43' 24.595 W NT8 MFS 16,400.0 82.51 3,852.4 9,292.9 -11,384.8311.04 410,925.205,982,186.73 70° 21' 40.025 N 150° 43' 24.866 W 16,500.0 80.67 3,867.0 9,359.4 -11,458.0313.44 410,852.675,982,253.98 70° 21' 40.677 N 150° 43' 27.010 W 16,600.0 78.85 3,884.8 9,428.5 -11,528.0315.87 410,783.405,982,323.84 70° 21' 41.356 N 150° 43' 29.060 W 16,668.7 77.61 3,898.8 9,477.5 -11,574.1317.55 410,737.795,982,373.27 70° 21' 41.837 N 150° 43' 30.411 W NT7 MFS 16,700.0 77.05 3,905.7 9,500.1 -11,594.6318.32 410,717.575,982,396.14 70° 21' 42.060 N 150° 43' 31.010 W 16,800.0 75.27 3,929.6 9,574.0 -11,657.6320.81 410,655.385,982,470.68 70° 21' 42.786 N 150° 43' 32.854 W 16,839.3 74.58 3,939.8 9,603.6 -11,681.3321.80 410,631.965,982,500.54 70° 21' 43.077 N 150° 43' 33.550 W NT6 MFS 16,900.0 73.52 3,956.5 9,650.0 -11,716.8323.34 410,596.975,982,547.24 70° 21' 43.532 N 150° 43' 34.589 W 16,942.5 72.79 3,968.8 9,682.9 -11,740.7324.43 410,573.325,982,580.37 70° 21' 43.855 N 150° 43' 35.292 W NT5 MFS 16,992.3 71.94 3,983.9 9,721.8 -11,767.9325.72 410,546.575,982,619.54 70° 21' 44.237 N 150° 43' 36.088 W Start Build 3.00 17,000.0 71.81 3,986.3 9,727.8 -11,772.0325.92 410,542.535,982,625.62 70° 21' 44.296 N 150° 43' 36.208 W 17,081.9 70.42 4,012.8 9,792.8 -11,814.3328.06 410,500.975,982,691.06 70° 21' 44.935 N 150° 43' 37.447 W NT4 MFS 17,100.0 70.12 4,018.9 9,807.3 -11,823.2328.54 410,492.195,982,705.61 70° 21' 45.077 N 150° 43' 37.708 W 17,131.6 69.60 4,029.8 9,832.7 -11,838.5329.39 410,477.145,982,731.22 70° 21' 45.327 N 150° 43' 38.157 W 17,142.2 69.91 4,033.4 9,841.2 -11,843.5329.39 410,472.205,982,739.77 70° 21' 45.411 N 150° 43' 38.305 W Start Build 4.00 17,200.0 71.65 4,052.5 9,888.2 -11,871.3329.39 410,444.885,982,787.04 70° 21' 45.872 N 150° 43' 39.120 W 17,300.0 74.65 4,081.5 9,970.6 -11,920.1329.39 410,397.015,982,869.89 70° 21' 46.682 N 150° 43' 40.549 W 21/05/2025 14:58:07 COMPASS 5000.17 Build Page 7 Santos Ltd Planning Report - Geographic Well B-27Local Co-ordinate Reference:Database:EDM Rig on 27 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Rig on 27 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-27Well: NDB-027Wellbore: Plan: NDB-027 Rev F.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) 17,305.1 74.80 4,082.8 9,974.8 -11,922.6329.39 410,394.545,982,874.16 70° 21' 46.723 N 150° 43' 40.623 W NT3 MFS 17,306.0 74.80 4,083.0 9,975.6 -11,923.0329.39 410,394.115,982,874.90 70° 21' 46.730 N 150° 43' 40.636 W 7" Intermediate Liner 17,343.2 74.80 4,092.8 10,006.5 -11,941.3329.39 410,376.135,982,906.03 70° 21' 47.034 N 150° 43' 41.172 W NT3.2 Top Reservoir 17,350.9 74.80 4,094.8 10,012.8 -11,945.1329.39 410,372.455,982,912.40 70° 21' 47.097 N 150° 43' 41.282 W 17,400.0 76.77 4,106.9 10,053.8 -11,969.3329.39 410,348.635,982,953.62 70° 21' 47.499 N 150° 43' 41.993 W 17,500.0 80.77 4,126.3 10,138.2 -12,019.3329.39 410,299.575,983,038.52 70° 21' 48.329 N 150° 43' 43.458 W 17,531.5 82.03 4,131.1 10,165.0 -12,035.1329.39 410,283.985,983,065.50 70° 21' 48.592 N 150° 43' 43.923 W Start DLS 3.00 TFO 89.27 17,544.2 82.54 4,132.8 10,175.9 -12,041.6329.39 410,277.685,983,076.41 70° 21' 48.699 N 150° 43' 44.111 W Start 9342.1 hold at 17544.2 MD 17,600.0 84.77 4,138.9 10,223.6 -12,069.8329.39 410,249.955,983,124.39 70° 21' 49.167 N 150° 43' 44.939 W 17,700.0 88.77 4,144.6 10,309.5 -12,120.6329.39 410,200.015,983,210.81 70° 21' 50.011 N 150° 43' 46.429 W 17,737.3 90.26 4,144.9 10,341.5 -12,139.6329.39 410,181.375,983,243.09 70° 21' 50.327 N 150° 43' 46.986 W 17,800.0 90.26 4,144.6 10,395.5 -12,171.5329.39 410,149.995,983,297.39 70° 21' 50.857 N 150° 43' 47.923 W 17,900.0 90.26 4,144.2 10,481.6 -12,222.5329.39 410,099.965,983,383.96 70° 21' 51.702 N 150° 43' 49.416 W 18,000.0 90.26 4,143.7 10,567.6 -12,273.4329.39 410,049.945,983,470.54 70° 21' 52.548 N 150° 43' 50.910 W 18,100.0 90.26 4,143.2 10,653.7 -12,324.3329.39 409,999.915,983,557.11 70° 21' 53.394 N 150° 43' 52.403 W 18,200.0 90.26 4,142.8 10,739.8 -12,375.2329.39 409,949.895,983,643.69 70° 21' 54.239 N 150° 43' 53.897 W 18,300.0 90.26 4,142.3 10,825.8 -12,426.2329.39 409,899.865,983,730.27 70° 21' 55.085 N 150° 43' 55.390 W 18,400.0 90.27 4,141.9 10,911.9 -12,477.1329.39 409,849.845,983,816.84 70° 21' 55.930 N 150° 43' 56.884 W 18,500.0 90.27 4,141.4 10,997.9 -12,528.0329.39 409,799.815,983,903.42 70° 21' 56.776 N 150° 43' 58.377 W 18,600.0 90.27 4,140.9 11,084.0 -12,578.9329.39 409,749.795,983,989.99 70° 21' 57.621 N 150° 43' 59.871 W 18,700.0 90.27 4,140.5 11,170.1 -12,629.9329.39 409,699.765,984,076.57 70° 21' 58.467 N 150° 44' 1.365 W 18,800.0 90.27 4,140.0 11,256.1 -12,680.8329.39 409,649.745,984,163.15 70° 21' 59.312 N 150° 44' 2.858 W 18,900.0 90.27 4,139.5 11,342.2 -12,731.7329.39 409,599.715,984,249.72 70° 22' 0.158 N 150° 44' 4.352 W 19,000.0 90.27 4,139.1 11,428.2 -12,782.6329.39 409,549.695,984,336.30 70° 22' 1.004 N 150° 44' 5.846 W 19,100.0 90.27 4,138.6 11,514.3 -12,833.6329.39 409,499.665,984,422.88 70° 22' 1.849 N 150° 44' 7.339 W 19,200.0 90.28 4,138.1 11,600.4 -12,884.5329.39 409,449.645,984,509.45 70° 22' 2.695 N 150° 44' 8.833 W 19,300.0 90.28 4,137.6 11,686.4 -12,935.4329.39 409,399.625,984,596.03 70° 22' 3.540 N 150° 44' 10.327 W 19,400.0 90.28 4,137.1 11,772.5 -12,986.3329.39 409,349.595,984,682.61 70° 22' 4.386 N 150° 44' 11.821 W 19,500.0 90.28 4,136.6 11,858.6 -13,037.3329.39 409,299.575,984,769.18 70° 22' 5.231 N 150° 44' 13.315 W 19,600.0 90.28 4,136.2 11,944.6 -13,088.2329.39 409,249.555,984,855.76 70° 22' 6.077 N 150° 44' 14.809 W 19,700.0 90.28 4,135.7 12,030.7 -13,139.1329.39 409,199.525,984,942.34 70° 22' 6.922 N 150° 44' 16.303 W 19,800.0 90.28 4,135.2 12,116.7 -13,190.0329.39 409,149.505,985,028.92 70° 22' 7.768 N 150° 44' 17.797 W 19,900.0 90.28 4,134.7 12,202.8 -13,240.9329.39 409,099.485,985,115.49 70° 22' 8.613 N 150° 44' 19.291 W 20,000.0 90.28 4,134.2 12,288.9 -13,291.9329.39 409,049.455,985,202.07 70° 22' 9.459 N 150° 44' 20.785 W 20,100.0 90.29 4,133.7 12,374.9 -13,342.8329.39 408,999.435,985,288.65 70° 22' 10.304 N 150° 44' 22.279 W 20,200.0 90.29 4,133.2 12,461.0 -13,393.7329.39 408,949.415,985,375.22 70° 22' 11.150 N 150° 44' 23.773 W 20,300.0 90.29 4,132.7 12,547.0 -13,444.6329.39 408,899.395,985,461.80 70° 22' 11.995 N 150° 44' 25.267 W 20,400.0 90.29 4,132.2 12,633.1 -13,495.6329.39 408,849.375,985,548.38 70° 22' 12.841 N 150° 44' 26.761 W 20,500.0 90.29 4,131.7 12,719.2 -13,546.5329.39 408,799.345,985,634.96 70° 22' 13.686 N 150° 44' 28.255 W 20,600.0 90.29 4,131.2 12,805.2 -13,597.4329.39 408,749.325,985,721.53 70° 22' 14.532 N 150° 44' 29.749 W 20,700.0 90.29 4,130.7 12,891.3 -13,648.3329.39 408,699.305,985,808.11 70° 22' 15.377 N 150° 44' 31.244 W 20,800.0 90.29 4,130.1 12,977.4 -13,699.2329.39 408,649.285,985,894.69 70° 22' 16.223 N 150° 44' 32.738 W 20,900.0 90.30 4,129.6 13,063.4 -13,750.2329.39 408,599.265,985,981.27 70° 22' 17.068 N 150° 44' 34.232 W 21,000.0 90.30 4,129.1 13,149.5 -13,801.1329.39 408,549.245,986,067.85 70° 22' 17.914 N 150° 44' 35.727 W 21,100.0 90.30 4,128.6 13,235.5 -13,852.0329.39 408,499.225,986,154.42 70° 22' 18.759 N 150° 44' 37.221 W 21,200.0 90.30 4,128.1 13,321.6 -13,902.9329.39 408,449.195,986,241.00 70° 22' 19.605 N 150° 44' 38.715 W 21,300.0 90.30 4,127.5 13,407.7 -13,953.9329.39 408,399.175,986,327.58 70° 22' 20.450 N 150° 44' 40.210 W 21,400.0 90.30 4,127.0 13,493.7 -14,004.8329.39 408,349.155,986,414.16 70° 22' 21.296 N 150° 44' 41.704 W 21,500.0 90.30 4,126.5 13,579.8 -14,055.7329.39 408,299.135,986,500.74 70° 22' 22.141 N 150° 44' 43.199 W 21,600.0 90.30 4,126.0 13,665.9 -14,106.6329.39 408,249.115,986,587.32 70° 22' 22.987 N 150° 44' 44.693 W 21,700.0 90.31 4,125.4 13,751.9 -14,157.5329.39 408,199.095,986,673.90 70° 22' 23.832 N 150° 44' 46.188 W 21,800.0 90.31 4,124.9 13,838.0 -14,208.5329.39 408,149.075,986,760.47 70° 22' 24.678 N 150° 44' 47.682 W 21,900.0 90.31 4,124.4 13,924.1 -14,259.4329.39 408,099.055,986,847.05 70° 22' 25.523 N 150° 44' 49.177 W 22,000.0 90.31 4,123.8 14,010.1 -14,310.3329.39 408,049.035,986,933.63 70° 22' 26.369 N 150° 44' 50.671 W 21/05/2025 14:58:07 COMPASS 5000.17 Build Page 8 Santos Ltd Planning Report - Geographic Well B-27Local Co-ordinate Reference:Database:EDM Rig on 27 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Rig on 27 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-27Well: NDB-027Wellbore: Plan: NDB-027 Rev F.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) 22,100.0 90.31 4,123.3 14,096.2 -14,361.2329.39 407,999.015,987,020.21 70° 22' 27.214 N 150° 44' 52.166 W 22,200.0 90.31 4,122.7 14,182.2 -14,412.1329.39 407,949.005,987,106.79 70° 22' 28.059 N 150° 44' 53.661 W 22,300.0 90.31 4,122.2 14,268.3 -14,463.1329.39 407,898.985,987,193.37 70° 22' 28.905 N 150° 44' 55.156 W 22,400.0 90.31 4,121.6 14,354.4 -14,514.0329.39 407,848.965,987,279.95 70° 22' 29.750 N 150° 44' 56.650 W 22,500.0 90.32 4,121.1 14,440.4 -14,564.9329.39 407,798.945,987,366.53 70° 22' 30.596 N 150° 44' 58.145 W 22,600.0 90.32 4,120.5 14,526.5 -14,615.8329.39 407,748.925,987,453.11 70° 22' 31.441 N 150° 44' 59.640 W 22,700.0 90.32 4,120.0 14,612.6 -14,666.7329.39 407,698.905,987,539.69 70° 22' 32.287 N 150° 45' 1.135 W 22,800.0 90.32 4,119.4 14,698.6 -14,717.6329.39 407,648.885,987,626.26 70° 22' 33.132 N 150° 45' 2.630 W 22,900.0 90.32 4,118.9 14,784.7 -14,768.6329.39 407,598.875,987,712.84 70° 22' 33.978 N 150° 45' 4.124 W 23,000.0 90.32 4,118.3 14,870.8 -14,819.5329.39 407,548.855,987,799.42 70° 22' 34.823 N 150° 45' 5.619 W 23,100.0 90.32 4,117.7 14,956.8 -14,870.4329.39 407,498.835,987,886.00 70° 22' 35.668 N 150° 45' 7.114 W 23,200.0 90.32 4,117.2 15,042.9 -14,921.3329.39 407,448.815,987,972.58 70° 22' 36.514 N 150° 45' 8.609 W 23,300.0 90.33 4,116.6 15,128.9 -14,972.2329.39 407,398.795,988,059.16 70° 22' 37.359 N 150° 45' 10.104 W 23,400.0 90.33 4,116.0 15,215.0 -15,023.2329.39 407,348.785,988,145.74 70° 22' 38.205 N 150° 45' 11.599 W 23,500.0 90.33 4,115.5 15,301.1 -15,074.1329.39 407,298.765,988,232.32 70° 22' 39.050 N 150° 45' 13.094 W 23,600.0 90.33 4,114.9 15,387.1 -15,125.0329.39 407,248.745,988,318.90 70° 22' 39.896 N 150° 45' 14.590 W 23,700.0 90.33 4,114.3 15,473.2 -15,175.9329.39 407,198.735,988,405.48 70° 22' 40.741 N 150° 45' 16.085 W 23,800.0 90.33 4,113.7 15,559.3 -15,226.8329.39 407,148.715,988,492.06 70° 22' 41.586 N 150° 45' 17.580 W 23,900.0 90.33 4,113.2 15,645.3 -15,277.7329.39 407,098.695,988,578.64 70° 22' 42.432 N 150° 45' 19.075 W 24,000.0 90.33 4,112.6 15,731.4 -15,328.7329.39 407,048.685,988,665.22 70° 22' 43.277 N 150° 45' 20.570 W 24,100.0 90.34 4,112.0 15,817.5 -15,379.6329.39 406,998.665,988,751.80 70° 22' 44.123 N 150° 45' 22.065 W 24,200.0 90.34 4,111.4 15,903.5 -15,430.5329.39 406,948.645,988,838.39 70° 22' 44.968 N 150° 45' 23.561 W 24,300.0 90.34 4,110.8 15,989.6 -15,481.4329.39 406,898.635,988,924.97 70° 22' 45.813 N 150° 45' 25.056 W 24,400.0 90.34 4,110.2 16,075.7 -15,532.3329.39 406,848.615,989,011.55 70° 22' 46.659 N 150° 45' 26.551 W 24,500.0 90.34 4,109.6 16,161.7 -15,583.2329.39 406,798.605,989,098.13 70° 22' 47.504 N 150° 45' 28.047 W 24,600.0 90.34 4,109.0 16,247.8 -15,634.1329.39 406,748.585,989,184.71 70° 22' 48.350 N 150° 45' 29.542 W 24,700.0 90.34 4,108.4 16,333.9 -15,685.1329.39 406,698.575,989,271.29 70° 22' 49.195 N 150° 45' 31.038 W 24,800.0 90.34 4,107.8 16,419.9 -15,736.0329.39 406,648.555,989,357.87 70° 22' 50.040 N 150° 45' 32.533 W 24,900.0 90.35 4,107.2 16,506.0 -15,786.9329.39 406,598.545,989,444.45 70° 22' 50.886 N 150° 45' 34.029 W 25,000.0 90.35 4,106.6 16,592.1 -15,837.8329.39 406,548.525,989,531.03 70° 22' 51.731 N 150° 45' 35.524 W 25,100.0 90.35 4,106.0 16,678.1 -15,888.7329.39 406,498.515,989,617.61 70° 22' 52.576 N 150° 45' 37.020 W 25,200.0 90.35 4,105.4 16,764.2 -15,939.6329.39 406,448.495,989,704.19 70° 22' 53.422 N 150° 45' 38.515 W 25,300.0 90.35 4,104.8 16,850.3 -15,990.6329.39 406,398.485,989,790.78 70° 22' 54.267 N 150° 45' 40.011 W 25,400.0 90.35 4,104.2 16,936.3 -16,041.5329.39 406,348.465,989,877.36 70° 22' 55.113 N 150° 45' 41.506 W 25,500.0 90.35 4,103.6 17,022.4 -16,092.4329.39 406,298.455,989,963.94 70° 22' 55.958 N 150° 45' 43.002 W 25,600.0 90.35 4,103.0 17,108.4 -16,143.3329.39 406,248.445,990,050.52 70° 22' 56.803 N 150° 45' 44.498 W 25,700.0 90.36 4,102.3 17,194.5 -16,194.2329.39 406,198.425,990,137.10 70° 22' 57.649 N 150° 45' 45.994 W 25,800.0 90.36 4,101.7 17,280.6 -16,245.1329.39 406,148.415,990,223.68 70° 22' 58.494 N 150° 45' 47.489 W 25,900.0 90.36 4,101.1 17,366.6 -16,296.0329.39 406,098.395,990,310.27 70° 22' 59.339 N 150° 45' 48.985 W 26,000.0 90.36 4,100.5 17,452.7 -16,347.0329.39 406,048.385,990,396.85 70° 23' 0.185 N 150° 45' 50.481 W 26,100.0 90.36 4,099.8 17,538.8 -16,397.9329.39 405,998.375,990,483.43 70° 23' 1.030 N 150° 45' 51.977 W 26,200.0 90.36 4,099.2 17,624.8 -16,448.8329.39 405,948.365,990,570.01 70° 23' 1.875 N 150° 45' 53.473 W 26,300.0 90.36 4,098.6 17,710.9 -16,499.7329.39 405,898.345,990,656.59 70° 23' 2.721 N 150° 45' 54.969 W 26,400.0 90.36 4,097.9 17,797.0 -16,550.6329.39 405,848.335,990,743.18 70° 23' 3.566 N 150° 45' 56.465 W 26,500.0 90.37 4,097.3 17,883.0 -16,601.5329.39 405,798.325,990,829.76 70° 23' 4.411 N 150° 45' 57.960 W 26,600.0 90.37 4,096.7 17,969.1 -16,652.4329.39 405,748.315,990,916.34 70° 23' 5.257 N 150° 45' 59.456 W 26,700.0 90.37 4,096.0 18,055.2 -16,703.3329.39 405,698.295,991,002.92 70° 23' 6.102 N 150° 46' 0.952 W 26,800.0 90.37 4,095.4 18,141.2 -16,754.3329.39 405,648.285,991,089.51 70° 23' 6.947 N 150° 46' 2.449 W 26,886.3 90.37 4,094.8 18,215.5 -16,798.2329.39 405,605.125,991,164.24 70° 23' 7.677 N 150° 46' 3.740 W TD at 26886.3 26,893.1 90.37 4,094.8 18,221.4 -16,801.6329.39 405,601.735,991,170.10 70° 23' 7.734 N 150° 46' 3.841 W 21/05/2025 14:58:07 COMPASS 5000.17 Build Page 9 Santos Ltd Planning Report - Geographic Well B-27Local Co-ordinate Reference:Database:EDM Rig on 27 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Rig on 27 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-27Well: NDB-027Wellbore: Plan: NDB-027 Rev F.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. (°) NDB-027 Toe Rev 3.0 4,094.8 5,991,170.10 405,601.7318,221.4 -16,801.60.00 0.00 70° 23' 7.734 N 150° 46' 3.841 W - plan hits target center - Point NDB-027 Heel Rev 2.4,144.9 5,983,243.09 410,181.3710,341.5 -12,139.60.00 0.00 70° 21' 50.327 N 150° 43' 46.986 W - plan hits target center - Polygon -105.9Point 1 5,983,132.94 410,591.514,144.9 411.3 True 8,290.5Point 2 5,991,579.63 405,711.124,144.9 -4,556.9 True 7,985.1Point 3 5,991,279.64 405,191.134,144.9 -5,073.8 True -411.2Point 4 5,982,833.04 410,071.524,144.9 -105.6 True Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 20" Conductor Casing128.0128.0 20 20 13-3/8" Surface Casing2,385.82,926.0 13-3/8 16 9-5/8" Intermediate Liner3,410.612,000.0 9-5/8 12-1/4 7" Intermediate Liner4,083.017,306.0 78-1/2 4-1/2" Production Liner4,094.826,893.1 4-1/2 6-1/8 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 1,060.4 Upper Schrader Bluff 0.001,046.8 1,156.9 Base Ice Bearing Permafrost 0.001,138.8 1,431.1 Base Permafrost Transition 0.001,393.8 1,839.8 Middle Schrader Bluff 0.001,741.8 2,408.7 MCU 0.002,135.8 3,055.8 Tuluvak Shale 0.002,438.8 3,239.3 Tuluvak Sand 0.002,499.8 5,845.8 TS_790 0.002,794.8 9,293.4 Seabee 0.003,139.8 15,868.9 Nanushuk 0.003,797.8 16,387.7 NT8 MFS 0.003,850.8 16,668.7 NT7 MFS 0.003,898.8 16,839.3 NT6 MFS 0.003,939.8 16,942.5 NT5 MFS 0.003,968.8 17,081.9 NT4 MFS 0.004,012.8 17,305.1 NT3 MFS 0.004,082.8 17,343.2 NT3.2 Top Reservoir 0.004,092.8 21/05/2025 14:58:07 COMPASS 5000.17 Build Page 10 Santos Ltd Planning Report - Geographic Well B-27Local Co-ordinate Reference:Database:EDM Rig on 27 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Rig on 27 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-27Well: NDB-027Wellbore: Plan: NDB-027 Rev F.0Design: Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 347.0 347.0 0.4 -0.3 Start Build 2.50 587.0 586.3 14.7 -10.3 Start DLS 3.00 TFO -37.01 996.6 985.9 85.9 -60.2 Start 150.0 hold at 996.6 MD 1,146.6 1,129.0 122.9 -86.0 Start DLS 3.00 TFO -12.01 3,367.9 2,532.5 1,169.0 -1,281.3 Start 12819.2 hold at 3367.9 MD 16,187.2 3,829.6 9,158.9 -11,221.0 Start DLS 3.00 TFO 126.98 16,992.3 3,983.9 9,721.8 -11,767.9 Start Build 3.00 17,142.2 4,033.4 9,841.2 -11,843.5 Start Build 4.00 17,531.5 4,131.1 10,165.0 -12,035.1 Start DLS 3.00 TFO 89.27 17,544.2 4,132.8 10,175.9 -12,041.6 Start 9342.1 hold at 17544.2 MD 26,886.3 4,094.8 18,215.5 -16,798.2 TD at 26886.3 21/05/2025 14:58:07 COMPASS 5000.17 Build Page 11 0300060009000120001500018000-21000 -18000 -15000 -12000 -9000 -6000 -3000 0 3000West(-)/East(+) (3000 usft/in)NDB-027 Toe Rev 3.0NDB-027 Heel Rev 2.093%20" Conductor Casing13-3/8" Surface Casing9-5/8" Intermediate Liner7" Intermediate Liner4-1/2" Production LinerPlan: NDB-027 Rev F.013:50, May 21 2025 -150001500300045000 3500 7000 10500 14000 17500 21000 24500Vertical Section at 317.32°20" Conductor Casing13-3/8" Surface Casing9-5/8" Intermediate Liner7" Intermediate Liner4-1/2" Production Liner10000°Upper Schrader BluffBase Ice Bearing PermafrostBase Permafrost TransitionMiddle Schrader BluffMCUTuluvak ShaleTuluvak SandTS_790SeabeeNanushukNT8 MFSNT7 MFSNT6 MFSNT5 MFSNT4 MFSNT3 MFSNT3.2 Top ReservoirPlan: NDB-027 Rev F.013:23, May 21 2025 21 May, 2025 Anticollision Summary Report Santos Pikka NDB B-27 NDB-027 Plan: NDB-027 Rev F.0 Santos Ltd Anticollision Summary Report Well B-27 - Slot B-27Local Co-ordinate Reference:SantosCompany: Rig on 27 @ 69.8usftTVD Reference:PikkaProject: Rig on 27 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-27Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-027 Database:EDM Offset DatumReference Design:Plan: NDB-027 Rev F.0 Offset TVD Reference: Interpolation Method: Depth Range: Reference Error Model: Scan Method: Error Surface: Filter type: ISCWSA Closest Approach 3D Combined Pedal Curve NO GLOBAL FILTER: Using user defined selection & filtering criteria MD Interval 25.0usft Unlimited Maximum centre distance of 2,884.6usft Plan: NDB-027 Rev F.0 Results Limited by: SigmaWarning Levels Evaluated at:2.79 ISCWSA TESTCasing Method: From (usft) Survey Tool Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 21/05/2025 SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISCWSA Rev 4)47.0 1,000.0 Plan: NDB-027 Rev F.0 (NDB-027) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag1,000.0 2,926.0 Plan: NDB-027 Rev F.0 (NDB-027) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,926.0 12,000.0 Plan: NDB-027 Rev F.0 (NDB-027) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag12,000.0 17,306.0 Plan: NDB-027 Rev F.0 (NDB-027) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag17,306.0 26,893.3 Plan: NDB-027 Rev F.0 (NDB-027) 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 CC, ESB-15 - NDB-015 - Plan: NDB-015 Rev A.0 300.0 300.2 239.4 230.4 49.086 SFB-15 - NDB-015 - Plan: NDB-015 Rev A.0 7,875.0 7,165.7 2,880.9 2,644.1 15.361 CCB-16 - NDBi-016 - NDBi-016 325.0 325.5 219.3 210.4 45.437 ESB-16 - NDBi-016 - NDBi-016 326.1 326.6 219.3 210.4 45.426 SFB-16 - NDBi-016 - NDBi-016 9,475.0 9,204.4 2,879.7 2,547.0 10.896 CC, ESB-17 - NDB-017 - NDB-017 Slot Saver 300.0 300.2 199.3 190.6 41.814 SFB-17 - NDB-017 - NDB-017 Slot Saver 750.0 747.3 218.0 208.3 39.388 CC, ESB-18 - NDBi-018 - NDBi-018 310.2 310.1 179.5 170.7 37.227 SFB-18 - NDBi-018 - NDBi-018 8,775.0 8,893.1 2,883.2 2,613.5 13.474 CC, ESB-19 - NDBi-019 - Plan: NDBi-019 Rev A.0 300.0 300.2 159.4 150.4 32.510 SFB-19 - NDBi-019 - Plan: NDBi-019 Rev A.0 775.0 778.6 184.8 174.0 29.181 CC, ESB-20 - NDBi-020 - Plan: NDBi-020 Rev A.0 300.0 300.2 139.3 130.3 28.361 SFB-20 - NDBi-020 - Plan: NDBi-020 Rev A.0 9,550.0 8,954.5 2,879.6 2,549.2 10.971 CC, ESB-21 - NDB-021 - Plan:NDB-021 Rev A.0 300.0 300.2 119.3 110.2 24.068 SFB-21 - NDB-021 - Plan:NDB-021 Rev A.0 550.0 547.8 126.0 116.3 23.068 CCB-22 - NDB-022 - Plan NDB-022 Rev A.0 300.0 300.2 99.3 90.2 19.942 ESB-22 - NDB-022 - Plan NDB-022 Rev A.0 325.0 325.2 99.3 90.2 19.765 SFB-22 - NDB-022 - Plan NDB-022 Rev A.0 11,400.0 11,001.0 2,483.4 2,038.1 7.004 CC, ESB-23 - NDB-023 - NDB-023 Slot Saver 300.0 300.2 79.2 70.4 16.318 SFB-23 - NDB-023 - NDB-023 Slot Saver 425.0 425.1 80.4 71.5 16.105 CCB-24 - NDB-024 - NDB-024 188.9 188.6 60.0 51.5 12.411 ESB-24 - NDB-024 - NDB-024 250.0 249.6 60.1 51.5 12.213 SFB-24 - NDB-024 - NDB-024 7,300.0 7,101.8 1,052.9 820.7 5.719 CCB-24 - NDB-024PB1 - NDB-024PB1 188.9 188.6 60.0 51.3 12.377 ESB-24 - NDB-024PB1 - NDB-024PB1 250.0 249.6 60.1 51.3 12.180 SFB-24 - NDB-024PB1 - NDB-024PB1 2,800.0 2,713.6 289.3 240.9 7.880 CC, ESB-25 - NDB-025 - NDB-025 327.0 326.9 39.2 30.3 7.745 SFB-25 - NDB-025 - NDB-025 375.0 374.9 39.4 30.5 7.706 CCB-26 - NDBi-026 - Plan: NDBi-026 Rev A.0 300.0 300.0 19.9 10.9 3.612 ESB-26 - NDBi-026 - Plan: NDBi-026 Rev A.0 325.0 325.0 19.9 10.9 3.587 SFB-26 - NDBi-026 - Plan: NDBi-026 Rev A.0 25,839.3 25,156.1 1,798.2 1,057.1 3.038 CC, ESB-28 - NDBi-028 - Plan NDBi-028 Rev A.0 410.8 410.8 20.4 11.1 3.576 SFB-28 - NDBi-028 - Plan NDBi-028 Rev A.0 425.0 424.9 20.5 11.1 3.562 CCB-29 - NDB-029 - NDB-29 Slot Saver 546.5 546.2 38.8 29.5 7.195 ESB-29 - NDB-029 - NDB-29 Slot Saver 550.0 549.7 38.8 29.5 7.185 SFB-29 - NDB-029 - NDB-29 Slot Saver 575.0 574.5 38.9 29.6 7.141 CCB-30 - NDBi-030 - NDBi-030 1,252.7 1,250.4 38.6 26.7 5.038 ESB-30 - NDBi-030 - NDBi-030 1,275.0 1,272.5 38.6 26.6 4.981 21/05/2025 13:18:52 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-27 - Slot B-27Local Co-ordinate Reference:SantosCompany: Rig on 27 @ 69.8usftTVD Reference:PikkaProject: Rig on 27 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-27Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-027 Database:EDM Offset DatumReference Design:Plan: NDB-027 Rev F.0 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB SFB-30 - NDBi-030 - NDBi-030 3,525.0 3,572.0 114.2 52.3 2.363 CCB-31 - NDB-031 - Plan: NDB-031 Rev E.1 399.4 398.3 79.6 70.6 15.914 ESB-31 - NDB-031 - Plan: NDB-031 Rev E.1 400.0 398.9 79.6 70.6 15.912 SFB-31 - NDB-031 - Plan: NDB-031 Rev E.1 500.0 496.4 80.7 71.6 15.679 CCB-32 - NDB-032 - NDB-032 974.1 975.2 83.1 72.1 12.405 ESB-32 - NDB-032 - NDB-032 975.0 976.1 83.1 72.1 12.401 SFB-32 - NDB-032 - NDB-032 11,900.0 12,354.4 2,075.4 1,686.7 6.708 CCB-33 - NDB-033 - Plan: NDB-033 Rev A.0 566.0 563.8 118.1 108.7 22.684 ESB-33 - NDB-033 - Plan: NDB-033 Rev A.0 575.0 572.5 118.1 108.7 22.612 SFB-33 - NDB-033 - Plan: NDB-033 Rev A.0 650.0 642.2 120.2 110.6 22.337 CCB-34 - NDBi-034 - Plan: NDBi-034 Rev A.0 721.2 713.3 132.5 122.1 21.868 ESB-34 - NDBi-034 - Plan: NDBi-034 Rev A.0 750.0 740.8 132.6 122.1 21.414 SFB-34 - NDBi-034 - Plan: NDBi-034 Rev A.0 24,900.0 25,286.6 1,824.5 1,051.6 2.956 CCB-35 - NDB-035 - NDB-035 Slot Saver 794.7 791.1 152.1 142.1 26.533 ESB-35 - NDB-035 - NDB-035 Slot Saver 800.0 796.3 152.1 142.1 26.459 SFB-35 - NDB-035 - NDB-035 Slot Saver 950.0 941.5 156.8 146.3 25.302 CC, ESB-36 - NDBi-036 - NDBi-036 47.0 47.3 180.1 171.0 38.320 SFB-36 - NDBi-036 - NDBi-036 725.0 702.6 195.9 186.2 35.608 CCB-36 - NDBi-036 - Plan: NDBi-036 Rev E.0 398.1 395.6 179.8 170.8 36.567 ESB-36 - NDBi-036 - Plan: NDBi-036 Rev E.0 400.0 397.4 179.8 170.8 36.550 SFB-36 - NDBi-036 - Plan: NDBi-036 Rev E.0 625.0 608.8 185.3 175.9 35.040 Normal Operations, CCB-37 - NDB-037 - NDB-037 16,994.2 17,776.0 165.7 30.3 1.538 Caution - Monitor Closely,B-37 - NDB-037 - NDB-037 17,075.0 17,776.0 183.5 1.0 1.260 Caution - Monitor Closely,B-37 - NDB-037 - NDB-037 17,100.0 17,776.0 195.2 0.1 1.253 CCB-38 - NDBi-038 - Plan: NDBi-038 Rev A.0 571.8 566.5 217.9 208.5 42.021 ESB-38 - NDBi-038 - Plan: NDBi-038 Rev A.0 575.0 569.2 217.9 208.5 41.974 SFB-38 - NDBi-038 - Plan: NDBi-038 Rev A.0 700.0 677.8 223.0 213.4 41.128 CCB-39 - NDB-039 - Plan: NDB-039 Rev A.0 689.3 676.4 233.0 222.6 38.871 ESB-39 - NDB-039 - Plan: NDB-039 Rev A.0 700.0 686.1 233.1 222.6 38.626 SFB-39 - NDB-039 - Plan: NDB-039 Rev A.0 9,500.0 8,663.4 2,881.9 2,544.3 10.741 CC, ESB-41 - NDBi-041 - Plan: NDBi-041 Rev A.0 677.7 663.0 273.0 263.3 50.060 SFB-41 - NDBi-041 - Plan: NDBi-041 Rev A.0 7,450.0 6,352.8 2,879.4 2,648.5 15.751 CC, ESB-42 - NDB-042 - NDB-042 Slot Saver 978.8 969.1 284.3 273.7 45.794 SFB-42 - NDB-042 - NDB-042 Slot Saver 1,025.0 1,000.0 284.9 274.2 45.224 CC, ESB-43 - NDBi-043A - NDBi-043A 758.2 746.9 307.8 297.8 53.559 SFB-43 - NDBi-043A - NDBi-043A 10,175.0 12,619.9 1,103.8 940.7 8.561 Wildcat CC, ES, SFFiord 2 - Fiord 2 - Fiord 2 26,893.3 4,328.0 954.4 644.6 3.872 Caution - Monitor Closely,Fiord 3 - Fiord 3 - Fiord 3 20,142.4 4,107.5 441.5 4.4 1.264 Take Immediate Action, EFiord 3 - Fiord 3 - Fiord 3 20,200.0 4,107.5 445.2 -7.7 1.230 Take Immediate Action, SFiord 3 - Fiord 3 - Fiord 3 20,225.0 4,107.5 449.1 -8.3 1.229 SFFiord 3 - Fiord 3A - Fiord 3A 19,275.0 3,884.9 1,055.5 696.3 3.689 ESFiord 3 - Fiord 3A - Fiord 3A 19,300.0 3,866.5 1,054.7 696.4 3.696 CCFiord 3 - Fiord 3A - Fiord 3A 19,353.4 3,827.2 1,054.0 697.9 3.717 21/05/2025 13:18:52 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-27 - Slot B-27Local Co-ordinate Reference:SantosCompany: Rig on 27 @ 69.8usftTVD Reference:PikkaProject: Rig on 27 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-27Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-027 Database:EDM Offset DatumReference Design:Plan: NDB-027 Rev F.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 3A, Fiord 3A V0 Fiord 3, Fiord 3, Fiord 3 V0 B-26, NDBi-026, Plan: NDBi-026 Rev A.0 V0 B-29, NDB-029, NDB-29 Slot Saver V0 B-15, NDB-015, Plan: NDB-015 Rev A.0 V0 B-30, NDBi-030, NDBi-030 V0 B-23, NDB-023, NDB-023 Slot Saver V0 B-34, NDBi-034, Plan: NDBi-034 Rev A.0 V0 B-39, NDB-039, Plan: NDB-039 Rev A.0 V0 B-42, NDB-042, NDB-042 Slot Saver V0 B-16, NDBi-016, NDBi-016 V0 B-25, NDB-025, NDB-025 V0 B-28, NDBi-028, Plan NDBi-028 Rev A.0 V0 B-31, NDB-031, Plan: NDB-031 Rev E.1 V0 B-43, NDBi-043A, NDBi-043A V0 B-38, NDBi-038, Plan: NDBi-038 Rev A.0 V0 B-19, NDBi-019, Plan: NDBi-019 Rev A.0 V0 B-41, NDBi-041, Plan: NDBi-041 Rev A.0 V0 B-32, NDB-032, NDB-032 V0 B-24, NDB-024PB1, NDB-024PB1 V0 B-24, NDB-024, NDB-024 V0 B-33, NDB-033, Plan: NDB-033 Rev A.0 V0 B-18, NDBi-018, NDBi-018 V0 B-36, NDBi-036, NDBi-036 V0 B-36, NDBi-036, Plan: NDBi-036 Rev E.0 V0 B-17, NDB-017, NDB-017 Slot Saver V0 B-35, NDB-035, NDB-035 Slot Saver V0 B-20, NDBi-020, Plan: NDBi-020 Rev A.0 V0 B-37, NDB-037, NDB-037 V0 B-21, NDB-021, Plan:NDB-021 Rev A.0 V0 B-22, NDB-022, Plan NDB-022 Rev A.0 V0 L E G E N D Coordinates are relative to: B-27 - Slot B-27 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 Rig on 27 @ 69.8usft 21/05/2025 13:18:52 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-27 - Slot B-27Local Co-ordinate Reference:SantosCompany: Rig on 27 @ 69.8usftTVD Reference:PikkaProject: Rig on 27 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-27Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-027 Database:EDM Offset DatumReference Design:Plan: NDB-027 Rev F.0 Offset TVD Reference: 0.00 3.00 6.00 9.00 0 5000 10000 15000 20000 25000 Measured Depth Stop Drilling Caution - Monitor Closely Normal Operations Separation Factor Plot Fiord 2, Fiord 2, Fiord 2 V0 Fiord 3, Fiord 3A, Fiord 3A V0 Fiord 3, Fiord 3, Fiord 3 V0 B-26, NDBi-026, Plan: NDBi-026 Rev A.0 V0 B-29, NDB-029, NDB-29 Slot Saver V0 B-15, NDB-015, Plan: NDB-015 Rev A.0 V0 B-30, NDBi-030, NDBi-030 V0 B-23, NDB-023, NDB-023 Slot Saver V0 B-34, NDBi-034, Plan: NDBi-034 Rev A.0 V0 B-39, NDB-039, Plan: NDB-039 Rev A.0 V0 B-42, NDB-042, NDB-042 Slot Saver V0 B-16, NDBi-016, NDBi-016 V0 B-25, NDB-025, NDB-025 V0 B-28, NDBi-028, Plan NDBi-028 Rev A.0 V0 B-31, NDB-031, Plan: NDB-031 Rev E.1 V0 B-43, NDBi-043A, NDBi-043A V0 B-38, NDBi-038, Plan: NDBi-038 Rev A.0 V0 B-19, NDBi-019, Plan: NDBi-019 Rev A.0 V0 B-41, NDBi-041, Plan: NDBi-041 Rev A.0 V0 B-32, NDB-032, NDB-032 V0 B-24, NDB-024PB1, NDB-024PB1 V0 B-24, NDB-024, NDB-024 V0 B-33, NDB-033, Plan: NDB-033 Rev A.0 V0 B-18, NDBi-018, NDBi-018 V0 B-36, NDBi-036, NDBi-036 V0 B-36, NDBi-036, Plan: NDBi-036 Rev E.0 V0 B-17, NDB-017, NDB-017 Slot Saver V0 B-35, NDB-035, NDB-035 Slot Saver V0 B-20, NDBi-020, Plan: NDBi-020 Rev A.0 V0 B-37, NDB-037, NDB-037 V0 B-21, NDB-021, Plan:NDB-021 Rev A.0 V0 B-22, NDB-022, Plan NDB-022 Rev A.0 V0 L E G E N D Coordinates are relative to: B-27 - Slot B-27 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 Rig on 27 @ 69.8usft 21/05/2025 13:18:52 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 5 Easting (5500 usft/in)Easting (5500 usft/in)NDB-027 Toe Rev 3.0Fiord 2Fiord 3AFiord 3Plan: NDBi-026 Rev A.0Plan: NDB-015 Rev A.0NDBi-030Plan: NDBi-034 Rev A.0Plan: NDB-039 Rev A.0NDBi-016NDB-025Plan NDBi-028 Rev A.0Plan: NDB-031 Rev E.1NDBi-043APlan: NDBi-038 Rev A.0Plan: NDBi-019 Rev A.0Plan: NDBi-041 Rev A.0NDB-032NDB-024PB1NDB-024Plan: NDB-033 Rev A.0NDBi-018NDBi-036Plan: NDBi-020 Rev A.0NDB-037Plan:NDB-021 Rev A.0Plan NDB-022 Rev A.0Plan: NDB-027 Rev F.0NDANDBNPF13:24, May 21 2025 Plan: NDB-027 Rev F.0AC FlipbookSURVEY PROGRAMDepth From Depth To Tool47.0 1000.0 SDI_URSA1_I41000.0 2926.0 3_MWD+IFR2+MS+Sag2926.0 12000.0 3_MWD+IFR2+MS+Sag12000.0 17306.0 3_MWD+IFR2+MS+Sag17306.0 26893.3 3_MWD+IFR2+MS+SagCASING DETAILSTVD MD Name128.0 128.0 20" Conductor Casing2385.8 2926.013-3/8" Surface Casing3410.6 12000.09-5/8" Intermediate Liner4082.9 17306.0 7" Intermediate Liner4094.8 26893.34-1/2" Production Liner50501001001501502002002502503003000901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [100 usft/in]475075100125150175200225250275300325350375400425449474499524549574599624649673698723748773798823848872897922947972997102210471072109711221147117111961221124612711296132113461371139614211446147114971522154715731598162316491674170017251751177618021827185318791904193019561982200820332059208521112137216321892215224122672294232023462372239824252451247725042530255625832609263626622689271527412765279028152839286428882912293829652992301930463073310131283156318332113239326732953323335233803409Plan: NDBi-026 Rev A.0475075100125150175200225250275300325350375400425450475500525550575600625649674698722747771795819843866890913937960983NDB-29 Slot Saver707510012515017520022525027530032434837239642144546949351754156558961463866268671073475878380783185587990392795297610001025105010751099112411491173119612191242126512881311133413571380140314261449147214951518154115641587161016341657168017031725Plan: NDB-015 Rev A.04751761011261511762012262512763013263513764014274524775025275525786036286536787037287537788038288538789039289539781003102810531078110311281153117812021227125212771302132713521377140214261451147615011525155015751599162416491673169817231747177217961821184518701895191919441968199220172041206620902115213921632188221222362260228523092333235723822406243024542478250325272551257525992623264826722696272027452770279428192844286928942919294429682992301530393063308731113136316031843208323232563280330433293353337734013426345034743499352335473571359536203645367036953720374537693794381938443869389439193943396839934018404340684093411741424167419242174242426742924316434143664391441644414466449145164540456545904615464046654690471547404764478948144839486448894914493949644988501350385063508851135138516351885212523752625287531253375362538754125436546154865511553655615586561156355660568557105735576057855810583458595884590959345959598460096033605860836108NDBi-030475075100125150175200225250275300325349374399423448472497522546570595619643667691715739763787810834857880903926949972NDB-023 Slot Saver4750751001251501752002252502753003263513774024284534785045295555806066316576827087337597848098358608869119379629871013103810631087111211371162118812151241126712931320134613721399142514521478150515311558158516121638166516921719174617721799182618531880190819351962198920162043207120982125215321802207223522622290231723452372240024272455248325102538256625932621264926772705273227572782280628312856Plan: NDBi-034 Rev A.04750751001251501752002252502753003263523784044294554815075335595856106366626887147407657918178438688949209459719971022104710711096112111461172119812251252127913061333136013871414144114681495152215491577160416311658Plan: NDB-039 Rev A.04750751001251501752002252502753003263523784044304564825085345605866116376636887137397647898148398638889129369609841008NDB-042 Slot Saver47507510012515017520022525027530032534937339742144647049451854256659061563966368771173575978380783185587990392795197599910241049107410991124114911721195121812401263128613091331135413771400142214451467149015121535155715791602162516461669169117131735175717791801182318451867188919111933195519772000NDBi-0164750751001251501752002252502753003253503754004244494744985225475715956196436666907137367597828048278498718929149359569789981021104310651088111011321154117511941213123212501269NDB-025707510012515017520022525027530032535037540042545047549952454857259662064466869171473776078380582885087189391493595697799710191040106210831104112511461166118512041222Plan NDBi-028 Rev A.0475075100125150175200225250275300325351376401426451477502526551576601625649673697721745768791814837860882904926947969990101110331055107811001122114411651186120612251245Plan: NDB-031 Rev E.14750751001251501752002252502753003273533794054314574845095355615876126386636887127377617858098338568799029259479709921014NDBi-043A47507510012515017520022525027530032635137740342945448050553055558060563065467970372775177479882184486789091393595797910011023104610681090Plan: NDBi-038 Rev A.0707510012515017520022525027530032434937339742244647049451854256558961263565868170472774977179381583685787990092094096098010001021104310641085110611271148116711841200Plan: NDBi-019 Rev A.047507510012515017520022525027530032635237840443045648250853456058661263866469071674276879482084687289792394997410001025105010741099112411481174120212291256128313101337Plan: NDBi-041 Rev A.04750751001251501752002252502753003253513764014274524775025285535786036286536787037287527778028268518769009259499749981023104810721097112211471171119612201244126912931317134113651389141314371461148515091533155715811604162816521676169917231747177117951819184218661890191419381962198620102034205920832107213121552180220422282253227723012326235023742399242324472471249525192543256725912614263826612685270827312755278028042828285228762900NDB-0324750751001251501752002252502753003253503753994244494744995235485735986226476726977227467717968218468718969219469709951020104510701095112011451169119412191244126912931318134313681393141814431469149415191544156915941620164516701696172117461772179718231848187418991925195019762001202720522078210321292155218022062232225722832309233423602386241224372463248925152540256625922618264426702696272227472771279528202844286828922916294229692996NDB-024PB147507510012515017520022525027530032535037539942444947449952354857359862264767269772274677179682184687189692194697099510201045107010951120114511691194121912441269129313181343136813931418144314691494151915441569159416201645167016961721174617721797182318481874189919251950197620012027205220782103212921552180220622322257228323092334236023862412243724632489251525402566259226182644267026962722274727712795281928432867289129142939NDB-024707510012515017520022525027530032535137640142745247750352855257760262665067469872274676979281583886188390692895097199310151037105910811103112511471168118812091229Plan: NDB-033 Rev A.0475075100125150175200225250275300325349373398422446471495519543567592616640664688712736759783807831854878902925949973996102110461070109511201145116811911213123612581281130313251348137013921414143614581481150315251547156915911613163516571679170017221744176617881810183118531875189619181939196119822003NDBi-018475075100125150175200225250275300325351377402428453479504530555580605630655680704728753777800824847870893915937959981100210241046106810901113113511571178NDBi-036475075100125150175200225250275300326351377403428454479505530555580605630655679703728752776799823846869891914936958980100210241046106810911113113511571179Plan: NDBi-036 Rev E.07075100125150175200225250275300324348373397421445470494518542566590614637661685708732755779802825848871894916939961NDB-017 Slot Saver475075100125150175200225250275300325351377402428453479504529555580605630655680705730754779803828852876900924947971994NDB-035 Slot Saver7075100125150175200225250275300324349373398422447471496520545569593618642667691716740765789814838862887911936960985101010341059108411091134115911821206123012541277130113251349137313971420144414681492151615401564158816121636165916831707173117551779180318271851187518991923194719711995201820422066209021142138Plan: NDBi-020 Rev A.047507510012515017520022525027530032635237840342945548150653255858460963566168771273876478981584086689191794296899310181043106810931118114311691195122112481274130013271353137914051431145714831509153515611587161316381664169017161741176717931818184418691895192019461971199620222047207220972122214721722197222122462271229523202345162911631516339163631638816413164371646216487165121653816563165881661416639166641669016715167411676616792168171684216868168931691816943169681699316994NDB-03747507510012515017520022525027530032434937339842244747149551954356759161463766068370672975177379581783986088190292294396398310021024104510661087110811291149116811851203Plan:NDB-021 Rev A.04750751001251501752002252502753003243493743984234484724975215465715956206446696947187437677928178418668909159409649891014103910641089111311381163118712111235126012841308133213571381140514301454147915031527155215761601162616501675169917241749177317981823184718721897192219461971199620212046207120952120214521702195222022452270229523202345237023952420244624712496252125462571Plan NDB-022 Rev A.047 500500 10001000 15001500 20002000 25002500 30003000 50005000 60006000 70007000 80008000 90009000 1000010000 1200012000 1400014000 1600016000 1800018000 2000020000 25000From Colour To MD47.0 To 26893.3MD Azi TFace47.0 0.00 0.00300.0 0.00 0.001000.8 325.00 325.001155.8 325.00 0.002728.0 308.59 -20.192928.0 308.59 0.003603.3 308.79 0.5716305.6 308.79 0.0017132.0 329.38 128.1617305.4 329.38 0.0017351.2 329.38 0.0017737.6 329.38 0.0026893.3 329.38 -0.23 0 30 60 0 450 900 1350 1800 2250 Partial Measured Depth Equivalent Magnetic Distance Plan: NDB-027 Rev F.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: NDB-027 Rev F.0 (NDB-027) SDI_URSA1_I4 1000.0 2926.0 Plan: NDB-027 Rev F.0 (NDB-027) 3_MWD+IFR2+MS+Sag 2926.0 12000.0 Plan: NDB-027 Rev F.0 (NDB-027) 3_MWD+IFR2+MS+Sag 12000.0 17306.0 Plan: NDB-027 Rev F.0 (NDB-027) 3_MWD+IFR2+MS+Sag 17306.0 26893.3 Plan: NDB-027 Rev F.0 (NDB-027) 3_MWD+IFR2+MS+Sag 13:28, May 21 2025 CASING DETAILS TVD MD Name 128.0 128.020" Conductor Casing 2385.8 2926.013-3/8" Surface Casing 3410.6 12000.09-5/8" Intermediate Liner 4082.9 17306.0 7" Intermediate Liner 4094.8 26893.34-1/2" Production Liner 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#FORWARD 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#DUTCH LOCK DOWN Choke Linefrom BOPPressure Gauge1502 Pressure SensorPressure TransducerBill of MaterialItemDescriptionTo Panic LineItemDescriptionA31/8” – 5,000 psi W.P.Remote HydraulicOperated ChokeB31/8”–5,000 psi W.P.Adjustable ManualChoke1–14 31/8” – 5,000 psi W.P.Manual Gate Valve1521/16”5000 iWP1521/16”–5,000psiW.P.Manual Gate ValveTo Mud GasLegendBlind SpareTo Tiger TankSeparatorValve Normally OpenValve Normally ClosedSep 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 84° 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 2nd 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. 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 runs 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: 372 bbls, 2087 cuft, 823 sks ArcticCem, Yield: 2.53 cuft/sk Tail 15.3ppg Tail: 66 bbls, 370 cuft, 299 sks HalCem Type I/II – 1.24 cuft/sk Temp BHST ~60° F (2.25°/100’ TVD below PermaFrost) Verification Method Cement returns to surface Notes Job will be mixed on the fly NDB-027 13-3/8" SURFACE CEMENT JOB Well Details Casing Stick Up on Rig Floor -4 ft MD 16.000 " Float Collar Depth 2861 ft MD 13.375 " Casing Shoe Depth 2926 ft MD 12.415 " TD Hole Depth 2926 ft MD 19.250 " Base Permafrost 1439 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 2861 2926 65 12.415 0.1497 9.7 0% 0 9.7 16" Open Hole x 13-3/8" Casing below base Permafrost 2426 2926 500 16.000 13.375 0.0749 37.5 50% 18.7 56.2 65.9 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 1439 2426 987 16.000 13.375 0.0749 73.9 50% 37.0 110.9 16" Open Hole x 13-3/8" Casing above base Permafrost 128 1439 1311 16.000 13.375 0.0749 98.2 150% 147.3 245.5 Conductor x 13-3/8" Cased Hole 46 128 82 19.250 13.375 0.1862 15.3 0% 0.0 15.3 371.7 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 2861 2865 12.415 0.1497 429.0 429.0 429.0 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: 340 bbls, 1910cuft, 1541sks 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 - 1st Stage Cement Job will not be logged, assuming job parameters are as expected (no losses, good lift pressures, FIT / LOT results). - 2nd Stage Cement Job will not be logged, assuming job parameters are as expected (no losses, good lift pressures, circulate cement off top of liner). Justification: - 1st 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 2nd Stage per Regulation 20 AAC 25.030(d)(5) - 2nd Stage bond evaluation does not affect 1 st Stage bond evaluation and frac decision. - 2nd Stage cement job will isolate Tuluvak with cement and a V0-rated LTP above it as a redundant means of isolation. - Well design allows for the OA annulus to be freeze protected by circulating in place (with Tieback) vs. bullheaded into place. With a sufficient initial LOT/FIT at the surface casing shoe, any potential Tuluvak pressures will be contained by the surface casing shoe and not cross flow into shallower formations. - Tuluvak isolation has been achieved on all historical Pikka development wells. - Seeking to simplify an already complicated operation, saving time/money. Verified cement calcs. -bjm NDB-027 9-5/8" 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 2776 ft MD 9.625 " DP Length 604 ft MD Cflex Depth 5896 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 2926 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 -4 600 604 0.0241 14.6 14.6 5-7/8" x 4" 130ksi Delta576 HWDP 600 2776 2176 0.0155 33.7 33.7 Liner Running Tools 2776 2821 45 2.5 0.0061 0.3 0.3 9-5/8” 47# L-80 Hydril 563 Casing to Float/Landing Collar 2821 11915 9094 8.681 0.0732 665.7 665.7 714.3 Hole Size Casing OD Casing ID Previous Casing ID NDB-027 9-5/8" 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 2776 ft MD 9.625 " DP Length 604 ft MD Cflex Depth 5896 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 2926 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 2926 5896 2970 12.250 9.625 0.0558 165.7 100% 165.7 331.3 13-3/8" Cased Hole x 9-5/8" Casing 2776 2926 150 12.415 9.625 0.0597 9.0 0% 0.0 9.0 340.3 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 -4 600 604 0.0241 14.6 14.6 5-7/8" x 4" 130ksi Delta576 HWDP 600 2776 2176 0.0155 33.7 33.7 5-7/8" 23.4# S135 Delta576 DP 2776 5896 3120 0.0241 75.2 75.2 123.5 Hole Size Casing OD Casing ID Previous Casing ID 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 + 125 ft shoe track Tail TOC 100’ 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: 154 bbls, 862cuft, 696sks 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. NDB-027 7" 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 17181 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 17306 ft MD TD Hole Depth 17306 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 9-5/8" Shoe Track 17181 17306 125 6.276 0.0383 4.8 0% 0 4.8 12-1/4" Open Hole x 9-5/8" Casing 14877 17306 2429 9.875 7.000 0.0471 114.5 30% 34.3 148.8 153.6 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 9-5/8” 47# L-80 Hydril 563 Casing to Float/Landing Collar 11895 17181 5286 6.276 0.0383 202.3 202.3 403.3 Hole Size Casing OD Casing ID Previous Casing ID Wait to hear from Russell Conwell to agree on height of cement above top of Nanushuk. -bjm Attachment 7: Prognosed Formation Tops NDB-027 Prognosed Tops Formation MD (ft) TVD KB (ft) TVDss (ft) Pore Pressure (ppg) Upper Schrader Bluff 1060 1047 977 7.2 Base Permafrost Transition 1431 1394 1324 7.3 Middle Schrader Bluff 1840 1742 1672 7.6 MCU 2409 2136 2066 7.8 Tuluvak Shale 3056 2439 2369 7.9 Tuluvak Sand 3239 2500 2430 10.2 TS_790 5846 2795 2725 9.4 Seabee 9294 3140 3070 9.2 Nanushuk 15869 3798 3728 8.9 NT8 MFS 16388 3851 3781 8.9 NT7 MFS 16669 3899 3829 8.9 NT6 MFS 16840 3940 3870 8.9 NT5 MFS 16943 3969 3899 8.9 NT4 MFS 17082 4013 3943 8.9 NT3 MFS 17305 4083 4013 8.8 NT3.2 Top Reservoir 17344 4093 4023 8.8 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” Production Hole LWD Gamma Ray Resistivity Density Neutron Sonic (7” Liner Cement Evaluation Only) Mudlogging No mudlogging is planned for NDB-027 Attachment 10: Wellhead & Tree Diagram Attachment 11: Diverter Variance Request NDB Surface Hole Map View Attachment 12: Oil Search Alaska 21-day BOPE Test Schedule Waiver Approval Letter Attachment 13: Managed Pressure Drilling Managed Pressure Drilling (MPD) will be implemented on NDB-027 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 10.0 - 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 9.0 – 10.0ppg mud weight with MPD utilized to trap back-pressure in order to manage ECD for losses as well as providing adequate pressures to maintain wellbore stability through the Nanushuk formations. Weighted trip fluids will be utilized to maintain downhole pressures for the final trip out and running of the 4-1/2” liner without MPD. At no point will the static wellbore fluid be underbalanced to formation pressure. See below for a schematic of the BOP/MPD stack with the choke flow diagram. Attachment 14: As Built Survey NDB Well 27 Conductor Final AS BUILT CERTIFICATION 3230 "C" Street, Ste. 201 Anchorage, Alaska 99503 PHONE: (907) 272-5451 FAX : (907) 272-9065 http://www.LOUNSBURYINC.com Certificate of Authorization No. AECC391 DATE: SHEET: FIELD BOOK: DRAWING NAME: DRAWN: CHECKED: GRID: OF SCALE: NORTH SLOPE BOROUGH PROJECT LOCATION: STATE OF ALASKA PIKKA UNIT AS BUILT SURVEY WELL 27 ND-B PAD CONDUCTORS WITHIN SECTION 4, TOWNSHIP 11 NORTH, RANGE 6 EAST, UMIAT MERIDIAN VICINITY MAP N NDB-CISUV-000011_1_IFC_20250521 5/23/25 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 NDB-027 PIKKA 225-066 NANUSHUK OIL WELL PERMIT CHECKLISTCompanyOil Search (Alaska), LLCWell Name:PIKKA NDB-027Initial Class/TypeDEV / PENDGeoArea890Unit11580On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250660Field & Pool:PIKKA, NANUSHUK OIL - 600100NA1Permit fee attachedYes2 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 boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes Variance for gap in cement coverage and 2nd stage cement back to surface casing.21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes Noted close approach with abandoned exploration well Fiord 3.26 Adequate wellbore separation proposedNo Diverter variance requested.27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 1482 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 probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S measures not required: None anticipated based on nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Tuluvak (with shallow gas) pressures anticipated to be 10.2 ppg EMW. Nanushuk reservoir at 8.9 ppg EMW36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate01-Aug-25ApprBJMDate30-Jul-25ApprADDDate01-Aug-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate($8JLC 8/1/2025
