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225-048
LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION Well clean up data for 19 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: 11/20/2025 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: 2025.11.21 09:00:44 -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 NDBi-030 50103208730000 NDB-031 50103209120000 NDB-032 50103208600000 NDBi-036 50103209080000 NDB-037 50103208950000 NDBi-043A 50103208590100 NDBi-044 50103208650000 NDBi-046L1 50103208830000 NDB-048 50103209020000 NDBi-049 50103208940000 NDBi-050 50103209040000 NDB-051 50103208800000 جؐؐؐNDB-010 ؒ Santos_Pikka_NDB-010_End of Well Data Report_1 min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-010_End of Well Data Report_30 min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-010_Rev A (1).pdf ؒ جؐؐؐNDB-011 ؒ Santos_Pikka_NDB-011_End of Well Data Report_1 min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-011_End of Well Data Report_30 Min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-011_Rev A (1).pdf ؒ جؐؐؐNDB-014 ؒ Santos_Pikka_NDBi-014_End of Well Clean-up Data Report_30 Minute_Final Data.xlsx ؒ Santos_Pikka_NDBi-014__End of Well Clean-up Data Report_1 Minute_Final Data.xlsx ؒ WT-XAK-0127.3_NDBi-014_Rev A_Signed.pdf ؒ جؐؐؐNDB-024 ؒ Santos_Pikka_NDB-024_End of Well Clean-Up Data Report_ 30-min_Final (2).xlsx ؒ Santos_Pikka_NDB-024_End of Well Clean-Up Data Report_1-min_Final (2).xlsx ؒ WT-XAK-0127.2_End of Well Clean-Up Data Report_NDB-024_Rev A_Signed.pdf 225-061 T41152 225-048 T41153 223-076 T39828 223-105 T39831 NDB-011 50103209160000 NDB-011 LETTER OF TRANSMITTAL ؒ جؐؐؐNDB-025 ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDB-025_End of Well Clean-up Data Report_30-min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-025_Rev A signed End of Well Clean-up Data Report.pdf ؒ جؐؐؐNDB-031 ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-031_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDB-031_Rev A Signed (1).pdf ؒ جؐؐؐNDB-032 ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_ 30 min_Final Data (1).xlsx ؒ Santos_Pikka_NDB-032_End of Well Clean-up Data Report_1 min_Final Data (1).xlsx ؒ WT-XAK-0127.3_NDB-032_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-037 ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_1-min_FINAL (1).xlsx ؒ Santos_Pikka_NDB-037_End of Well Clean-up Data Report_30-min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-037_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-048 ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDB-048_End of Well Clean-up Data Report_30 min_FINAL (1).xlsx ؒ WT-XAK-0127.5_NDB-048_Rev A_Signed (2).pdf ؒ جؐؐؐNDB-051 ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDB-051_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDB-051_Rev A_Signed.pdf ؒ جؐؐؐNDBi-016 ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_ 1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-016_End of Well Clean-Up_ Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-016_Rev A_Signed.pdf ؒ جؐؐؐNDBi-018 ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_1 min_Final.xlsx ؒ Santos_Pikka_NDBi-018_End of Well Clean-up_Build-up Data Report_30 min_Final.xlsx ؒ WT-XAK-0127.4_NDBi-018_Rev A_Signed.pdf ؒ جؐؐؐNDBi-030 224-006 T41154 225-028 T41155 224-124 T41156 224-143 T41157 224-105 T41158 224-085 T41159 224-013 T39830 223-006 T39829 223-120 T39832 LETTER OF TRANSMITTAL ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_1-min_Final Data.xlsx ؒ Santos_Pikka_NDBi-030_End of Well Clean-up Data Report_30 minute_Final Data.xlsx ؒ WT-XAK-0127.3_NDBi-030_Rev A_Signed.pdf ؒ جؐؐؐNDBi-036 ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_1 min_FINAL.xlsx ؒ Santos_Pikka_NDBi-036_End of Well Clean-up Data Report_30 min_FINAL.xlsx ؒ WT-XAK-0127.5_NDBi-036_Rev A Signed (1).pdf ؒ جؐؐؐNDBi-043A ؒ Santos_Pikka_NDBi-043_Daily Well Test Data Report_09152023_0830 - 09202023_2200_Final (1).xlsx ؒ WT-XAK-0127.1_NDBI-043_End of Well Report_Rev A (1).pdf ؒ جؐؐؐNDBi-044 ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_1-min_Final .xlsx ؒ Santos_Pikka_NDBi-044_End of Well Clean-Up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.3_End of Well Report_NDBi-044_Rev A_Signed.pdf ؒ جؐؐؐNDBi-046L1 ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_1 min_Final Data.xlsx ؒ Santos_Pikka_NDBi-046_End of Well Clean-up Data Report_30 min_Final Data.xlsx ؒ WT-XAK-0127.4_NDBi-046_Rev A_Signed.pdf ؒ جؐؐؐNDBi-049 ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_1-min_Final.xlsx ؒ Santos_Pikka_NDBi-049_End of Well Clean-up Data Report_30-min_Final.xlsx ؒ WT-XAK-0127.5_NDBi-049_Rev A Signed.pdf ؒ ؤؐؐؐNDBi-050 Santos_Pikka_NDBi-050_End of Well Clean-up Data Report_1-min_FINAL.xlsx Santos_Pikka_NDBi-050_End of Well Clean-up_Data Report_30-min_FINAL.xlsx WT-XAK-0127.5_NDBi-050_Rev A_Signed (1).pdf 225-012 T41160 224-119 T41161 224-154 T41162 223-052 T39834 223-087 T39835 224-029 T39837 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-011 Lithotrak Caliper data NDB-011 50103209160000 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 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 LETTER OF TRANSMITTAL DETAIL QTY DESCRIPTION NDB-011 (50-103-20916-0000) 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: 8/14/2025 From: Shannon Koh Santos 601 W 5th Ave. Anchorage, AK 99501 To: Gavin Glu as 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: LETTER OF TRANSMITTAL Directional Survey NDB-011 Comparison View-1.pdf NDB-011 Comparison View-2.pdf NDB-011 Definitive Compass Survey Report - NAD27.pdf NDB-011 Definitive Compass Survey Report - NAD83.pdf NDB-011 Definitive Survey - NAD27.txt NDB-011 Definitive Survey - NAD83.txt NDB-011 Plan View.pdf NDB-011 Vertical Section View.pdf NDB-011 WA Definitive Survey.xlsx Log Digital Data and Plots Baker Digital Data FE NDB-011_LWD_GR_Res_Den_Neu_Cal_RM_18634-12875ft_BROOH.las NDB-011_LWD_GR_Res_Den_Neu_Cal_RM_18634ft.las NDB-011_LWD_GR_Res_Den_Neu_RM_11193-12427ft_BROOH.las PWD NDB-011_AP_R01_RM.las NDB-011_AP_R02_RM.las NDB-011_AP_R03_RM.las VSS NDB-011_DMD_RM_18634ft.las NDB-011_DMT_R01_RM.las NDB-011_DMT_R02_RM.las NDB-011_DMT_R03_RM.las GeoScience Deliverables SoundTrak- Acoustic Data TOC NDB-011_9_625_Liner_Baker_Hughes_SDTK TOC Report.pdf NDB-011_LWD_SDTK_TOC_8677_12295.cgm NDB-011_LWD_SDTK_TOC_8677_12295.dlis NDB-011_LWD_SDTK_TOC_8677_12295.las NDB-011_LWD_SDTK_TOC_8677_12295.PDF NDB-011_LWD_SDTK_TOC_8677_12295_dlis.txt Graphic Images CGM LETTER OF TRANSMITTAL FE NDB-011_LWD_GR_Res_Den_Neu_Cal_RM_18634ft_2MD.cgm NDB-011_LWD_GR_Res_Den_Neu_Cal_RM_18634ft_2TVD.cgm NDB-011_LWD_GR_Res_Den_Neu_Cal_RM_18634ft_5MD.cgm NDB-011_LWD_GR_Res_Den_Neu_Cal_RM_18634ft_5TVD.cgm PWD NDB-011_AP_RM.cgm VSS NDB-011_DMD_RM_18634ft.cgm NDB-011_DMT_RM.cgm PDF FE NDB-011_LWD_GR_Res_Den_Neu_Cal_RM_18634ft_2MD.pdf NDB-011_LWD_GR_Res_Den_Neu_Cal_RM_18634ft_2TVD.pdf NDB-011_LWD_GR_Res_Den_Neu_Cal_RM_18634ft_5MD.pdf NDB-011_LWD_GR_Res_Den_Neu_Cal_RM_18634ft_5TVD.pdf PWD NDB-011_AP_RM.pdf VSS NDB-011_DMD_RM_18634ft.pdf NDB-011_DMT_RM.pdf 07/25/2025 325-442 CDW 08/14/2025 Variance to 20 AAC 25.283(a)(6)(A)(ii) is granted. See attached variance request. 10-404 A.Dewhurst 18AUG25 DSR-8/14/25BJM 8/19/25'tϬϴͬϭϵͬϮϬϮϱ Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.19 12:31:16 -08'00'08/19/25 RBDMS JSB 082025 Page 1 of 20 NDB-011 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-011. At the NDB-011 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-011 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 2,394 ft TVDSS/1,423 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: 2,394 to 3,067 ft TVDSS/ 673 ft thick Hydrocarbon Zone: 2,772 to 3,067 ft TVDSS Lithological Description: The Tuluvak Fm in the Pikka Unit area consists predominantly of claystone, siltstone, and thinly interbedded sandstones deposited in a prograding, shallow marine setting, grading with depth to the deep marine shales of the Seabee Fm. Sandstones. Upper Confining Zone Name Seabee Formation Depth/Thickness: 3,067 to 3,804 ft TVDSS/ 737 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: 3,804 to 4,758 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: 4,758 to 5,657 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 1-10 3,800 4,100 8,500 7,800 9,200 8,800 Fracture gradient values for each stage are listed in detail within Attachment K. In general, the fracture gradient values for the confining zones and pay zone are listed below: Upper confining: Shale gradient – 0.71 psi/ft Fracturing: Sand gradient- 0.61 psi/ft Lower confining: Shale gradient- 0.69 psi/ft Mechanical condition of wells transecting the confining zones –Qugruk 301, Qugruk 3, Qugruk 3A, NDBi-014, NDB-051, NDBi-049, NDB-048, NDBi-050, NDBi-046/NDBi-046L and NDBi-044 are within 1/2-mile radius of NDB-011. Please see Attachment B as reference. 11.Suspected fault or fracture that may transect the confining zones: There is one suspected fault within the ½ mile radius of NDB-011. Please See Attachment B. The fault shown on the map appears as a discontinuous reflector in seismic. There was no evidence during drilling or from logs that suggest offset. Note: Fractures are estimated to propagate along wellbore longitudinally at ~330 o. 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 18,296 4,201 246 383 40 5,091 8 2 17,755 4,216 250 413 40 4,967 8 3 17,174 4,233 247 367 40 5,272 10 4 16,486 4,253 248 357 40 5,120 10 5 15,902 4,270 254 380 40 5,542 12 6 15,316 4,287 273 402 40 5,336 12 7 14,732 4,304 241 333 40 4,954 11 8 14,146 4,321 226 389 40 4,778 11 9 13,646 4,335 296 457 40 4,484 10 10 13,025 4,353 293 452 40 4,310 10 5,091 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), LLC’s Sundry Application for a Fracture Stimulation for the Proposed NDB-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- 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-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 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 Attachment B 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 IntegrityQ-301 Abandoned 9-5/8" 47# L-80 4042 (Nanushuk) 3841 (Nanushuk) 3810'3683'logAbandoned with Cased hole cement plugsTOC 3,810' MDQ-301 was an exploration/appraisal well that was drilled in 2015. Itwas hydraulic fractured in the Nanushuk reservoir, flowed back, andplugged and abandoned in the same winter season.13.9ppg Extended Class G), with a second stage cement job from15.6ppg Class G cement plug laid on top of it.Well is fully abandoned. Q3A Abandoned Open Hole 4678 (Nanushuk) 4192' (Nanushuk)4678' 4177' Tag TOC set down 15k with DP.Open Hole Abandonment PlugTOC 4,177' MD1st plug (open hole plug): An open hole balanced cement plug136 bbls of 15.8 ppg cement. Cement was pumped with fullreturns, but while laying in the balanced plug in the well the stringMD inside the drill pipe.2.) 2nd plug (open hole balanced plug): A second open holebalanced plug was placed in the well by circulating 73 bbls of 15.8Well is fully abandoned. Q3 Abandoned Open Hole3875 3502 3502Tag TOC with DP.Open Hole Abandonment PlugTOC 3502' MDThe 12-1/4" open hole section was abandoned with 4 open hole plugs. Kuparuk C 6750' - 6753' MD, Alpine 6970' - 7230' MDCement Plug #1: Pump mud push, 120 bbls 15. 8 ppg Class G cement for openhole plug# 1. POOH to 6624' and circulate drill pipe clean. Pick up drill pipewhile WOC. Tag plug at 6852', with 14,000 lbs. Tag witnessed by Bob Noble. Plug at 7,500' MD - 6,852' MD, Cement Plug #2A: Pump mud push, 115 bbls 15. 8 ppg Class G cement for open hole plug# 2.Tag plug at 4216', with 10,000 lbs. Tag witnessed by Bob Noble. plug #2 4,581' MD - 4,216' MD. Plug #2 didn't meet regulations. Mixed up a second one. Cement Plug #2B: Pump mud push, 100 bbls 17 ppg Class G. Tag plug at 3,502' MD. Tag witnessed by Louis Grimaldi. Plug #2A 4,216' MD - 3,502' MD. Cement Plug #3: Pump mud push, 108 bbls 17 ppg Class G cement for bottom kick off plug. POOH to 2275. Cement plug #3 Kick off plug 3,144' - 2,507' MDCement Plug #4: Pump mud push, 88 bbls 15. 7 ppg AS1 cement for top kick off plug. Cement plug #4 top kick off plug 2,255 - 1,735' MDThe Q3A sidetrack wellbore was then kicked off by washing through soft cement and kicking off of cement plug #3 at 2708' MD. The Q3A well was then drilled and abandoned per the AOGCC Regulations. Well is fully abandoned. NDBi-044 ACTIVE 9-5/8" 47ppf 9678 (Nanushuk) 3,804 (Nanushuk) 7964 3,496 log open hole liner for productionTOC 7,964' & packer @ 10,823'a.Pump 80 bbls 12.5 ppg tuned spacer, 131 bbls 13.0 ppg 400 sxs 1.84 ft^3/sx EconoCem Tpe I-II lead cement, and 80 bbls of 15.3 ppg 1.24 ft^3/sx Versacem b.No returns while displacing cement job. Wiper dart #2 was lodged in the liner running tool when it was recovered. The follow liner wiper plug was then found Dynamic losses were encountered while drilling the float equipment indicating the lost circulation zone had not been isolated. d.15bbls 12.0 ppg tuned spacer and 95 bbls of 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail were circulated through the retainer, and 5 bbls were placed on top of the retainer. a.RIH and open up the Archer Cflex cement tool. Establish circulation and pump 80 bbls 12.5 ppg Tuned spacer 214 bbls 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail. 129 bbls were lost while displacing. The LTP was set and 263 bbls of contaminated mud / cement/ spacer was circulated to surface while circulating with the Cflex running tool. An additional 5 bbls of cement was circulated out off the top of the liner when circulating with the liner running too at the top of the liner. 01/30/24, 9-5/8" casing pressure tested to 4284 psi for 30 minutesNDBi-014 ACTIVE 9-5/8" 47ppf 7677 (Nanushuk) 3799 (Nanushuk) 7739 3,817 log open hole liner for productionTOC 7,739' & packer @ 10,257'b.Displace with rig pumps, adjusting rate to manage losses. Total losses from cement exit shoe to cement in place = 75 bbls.a.RIH and open up the Archer Cflex cement tool. Establish circulation and pump 80 bbls 12.5 ppg Mud Flush spacer, 80 bbls of 13.5 ppg Tuned Spacer, 305 bbls 15.3 ppg 1.24 ft^3/sx Versacem Type I-II Tail. Slight losses reported but reduced with lower displacement rate. The LTP was set and 104 bbls of contaminated cement was circulated to surface while circulating with the Cflex running tool. job at 7,739' MD. Top of hydrocarbon bearing zone in the Nanushuk was in the NT7 at 7,857' MD. CBL also showed adequate isolation throughout the Tuluvak with the 2nd stage cement job.2/14/24, 9-5/8" casing pressure tested to 4190 psi for 30 minutes NDB-051 ACTIVE 9-5/8" 47ppf 10,178 (Nanushuk) 3,740 (Nanushuk) 9,250 3,514 log open hole liner for productionTOC 9,250' & packer @11,378'Pump 80 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol A - (65 gallons each) downhole at 2.9-3 bpm, 93% returns. -Release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II at 2.9-3 bpm, Excess Volume 30% (839 sacks, yield 1.237 cu.ft/sk), initial circulating pressure 440 psi. -Added 300 lbs of Halliburton Bridgemaker II LCM to cement: 10 bbls neat cement ahead, 60 bbls with LCM added, 115 bbls of neat cement. -Land dart at 69 bbls away at 2.9 bpm at latch (1.5 bbls behind as calculated), clear indication of latch and release at 1000 psi. -Continue to chase with 15.3 ppg Versacem Tail Cement Type I/II, pump total of 185 bbls at average of 2.9 bpm, 235-400 psi, excess volume 30% (839 sacks, yield 1.237 cu ft/sk). -Release top pump down plug, chase with 20 bbls of washup from Halliburton. -Perform displacement with rig pumps, displace with 11.8 ppg OBM at 2.5 bpm, ICP 272 psi 1% return flow, FCP 600 psi 7% return flow. -Top pump down dart latch up confirmed at 45 bbls displaced. -Continue to displace with 11.8 ppg OBM, reduce rate to 2.5 bpm prior to plug bump: Final circulating pressure 600 psi. -Total displacement volume 656 bbls (measured by strokes at 96% pump efficiency). -Total losses from cement exit shoe to cement in place: 52 bbls w/4 bbls bleed back.06/11/24, 9-5/8" casing pressure tested to 3640 psi for 30 minutesNDBi-046/ NDBi-046L ACTIVE 9-5/8" 47ppf 11,166' (Nanushuk) 3,733' (Nanushuk) 10255 3,615 log open hole liner for productionTOC 10,255' & packer @ 12,572'- Pump 80 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol at 3.7-4 bpm, release bottom pump down plug for bottom plug, chase with 15.3 ppg Versacem Tail Cement Type I/II, pump total of 197 bbls at 4 bpm, release top pump down plug, chase with 20 bbls of water from Halliburton. Perform displacement with rig pumps, displace with 11.8 ppg OBM at 4 bpm, ICP 395 psi 8% flow, FCP 596 psi, 2% return flow, reduce rate to 3 bpm prior to plug bump: Final circulating pressure 596 psi. pressured up 500 psi over FCP 1,080 psi. Held 5 min, bled off checked floats. Floats held. CIP @ 12:45 hrs.- Total losses from cement exit shoe to cement in place: 43 bbls.to the casing show was found to be in good quality ranging down to partial coverage in limited areas. 07/11/24, 9-5/8" casing pressure tested to 3,667 psi for 30 minutesNDB-048 ACTIVE 9-5/8" 47ppf 12,044' (Nanushuk) 3,733' (Nanushuk) 10,908'3,574'Log open hole liner for productionTOC 12,044 MD' & Packer @ 11,989 MD'First stage of cement job: Pump 82 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol A downhole at 3 bpm, ~0% returns. and last 40 bbls Neat without Bridgemaker II LCM), excess volume 30%, at 3.5 bpm, average circulating pressure 330 psi. ~5% returns throughout cement pumping. Release top pump down plug, chase plug with displacement by rig pumps, displace with 11.5 ppg OBM at 3.5 bpm, ICP 200 psi. Average ~0% returns during displacement. Bottom plug landed on calculated strokes at 3.5 bpm, 520 psi circ pressure, shear with drop in circulating pressure to 493 psi and maintain 3.5 bpm as cemenexits shoe. Circulating pressure with cement turning shoe 493 ICP at 3.5 bpm. Reduce rate to 3.0 bpm, 455 psi circ. pressure to reduce ECD. Maintain 3 bpm to plug bump, FCP 500 psi; ~0% returns with cement around shoe. Bump plug, hold for 5 minutes, to check floats, floats held, Observations for the 1st stage of the cement job: There is 12/31/24, 9-5/8" casing pressure tested to 3,755 psi for 30 minutesNDBi-049 ACTIVE 9-5/8" 47ppf 11,560' (Nanushuk) 3,743' (Nanushuk) 10,477' 3,531' log open hole liner for productionTOC 10,477' & packer @ 11,438'Cement Job Execution-During execution of the 1st stage cement job, lost a reported 88 bbls after cement turned the corner, although lift pressure continued to increase during the displacement (ICP 280 psi, FCP 407 psi).liner top.-During execution of the 2nd stage cement job, ~6 bbls of losses were reported and good lift pressures noted. An estimated 140 bbls Spacer, 35 bbls contaminated cement, and 65 bbls pure cement observed at surface off the top of liner. Observations/ Conclusions: -For the 1st stage of the cement job, we have adequate isolation above the top of the Nanushuk formation. This is supported by the CBL log, -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 the top of the Nanushuk formation for frac operations. The 2nd stage cement job yielded adequate isolation below, across and above the Tuluvak significant hydrocarbons.12/10/24, 9-5/8" casing pressure tested to 4,020 psi for 30 minutesNDBi-050PB1 Abandonded 9-5/8" 47ppf 13,228' (Nanushuk) 3,727' (Nanushuk)Abandoned with Cased hole cement plugsCement retainer @ 13,009' MD with 45 bbls beneath retainer and 5 bbls above.was set at the very top of the Nanushuk formation. Upper hydrocarbon bearing zone in the Nanushuk is the NT8 MFS. NDBi-050PB1 wellbore was drilled to section. 45 bbls of cement was squeezed below the cement retainer, and 5 bbls were placed on top of the retainer. -Upper Liner Section: 2nd stage cement job was pumped through the Archer C-Flex stage tool per plan (325 bbls 15.3ppg cement) to isolate the Tuluvak sand. No losses were observed during the cement job and 50 bbls of cement were circulated off the liner top. casing shoe. Pressure test cement plug to 2000 psi for 30 min..Well is fully abandoned. NDBi-050 ACTIVELiner 1- 9-5/8" 47ppf to 9,990'. Liner 2- 7" 26 ppt to 15,137'.12,105' (Nanushuk) 3,738' (Nanushuk) 11,545' 3,671' log open hole liner for productionTOC 11,545' & packer @ 15,137'Cement Job Execution: liner top.-During execution of the 2nd stage cement, no losses were encountered and we saw good lift pressure. An estimated 110 bbls of spacer and 120 bbls of cement observed at surface off the top of liner.MD.-During execution of the 1st stage cement, we lost a reported 119 bbls during the cement job, although lift pressure continued to increase during the displacement (ICP 561 psi, FCP 878 psi). Majority of losses occurred during the last 100 bbls of displacement. 'Observation/ Conclusions:hydrocarbon zone within the upper Tuluvak formation. 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.3/23/2025, 9-5/8" casing pressure tested to 4,000 psi for 30 min. 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 Intermediate Liner Cement Job Execution Cement job pumped following the Halliburton Cementing Program Well Design 9-5/8” Liner Top at 2,578” MD 13-3/8” Casing Shoe at 2,758’ MD 9-5/8” Archer Cflex Mechanical Stage tool: 4,750’ MD 9-5/8” Shoe at 12,419’ MD Geology Top of Tuluvak TS 790 formation at 4,649 MD. Top of the Nanushuk picked at 9,436 MD. Top hydrocarbons in the NT8 (9,791’ MD). Cement Job Planning/Execution See attached cementing reports starting on subsequent pages for a summary of the work performed. Observations 9-5/8” Intermediate Liner 1st Stage Cement Job: -The Baker LWD TOC log indicates top of cement at ~9632’ MD (3917’ TVD) with partial bonds observed sporadically from 8700’ to 9598’ MD above that point. -The 9632’ MD top of cement would indicate that the Nanushuk formation has not been covered. ~9632’ MD (3917’ TVD) -Density Neutron LWD logs across the upper Nanushuk formations indicate that top of potential hydrocarbons in the NT8 in the NDB-011 well is ~9791’ MD / 3952’ TVD. -This would place top of cement ~159’ MD / 35’ TVD above the top of potential hydrocarbons observed on LWD logs. 9-5/8” Intermediate Liner 2nd Stage Cement Job: -Based on job execution results, cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation. The 12-1/4” hole section was drilled with 11.0ppg mud weight in an effort to combat low fracture gradients, high ECDs and cementing losses observed on recent offset wells. Unfortunately, this meant that wellbore stability became an issue and the hole required significant circulation and clean up in order to trip the BHA out of the hole. No losses were observed on the first stage cement job so it would appear that the hole was much larger than expected and despite pumping additional excess cement this was not sufficient to meet the target top of cement. The Baker LWD TOC cement log is attached for your information; there is no plans for any further cement logging. Due the hole conditions in this well, the top of the Nanushuk pool has not been cemented as per the approved PTD however, our assessment is that adequate isolation to prevent crossflow of the Nanushuk to any shallower permeable formations, as well as adequate isolation across the 9-5/8” shoe for frac operations has been achieved. Attachment D Attachment E Attachment F Well NameNDB-01107/16/25 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)aWFbWF00000c Pump CheckWF26 4028528511970119702852850285dDFITXL26 40300585 12600 24570 300 585eWF26 40280865 11760 36330 280 8650 8650 865 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOBSTAGE CUMSTAGE CUM Size or Stage Cum# PPA TYPE (BPM) (BBL) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) Type (BBL) (BBL)10Line out XL XL 26404040 9051680 3801000 4090520Drop Stage 1 Ball/Collet FP 040343 908126 3813600CSG-IV390830Stage 1 PADXL 2640 248291 115610416 485520 0 248 115640Slow for Seat XL 261850341 12062100 506520 0 50 120650Resume PadXL 2640 2343 120884 5073600 2120861ScourXL 2640 60403 12682520 532562413 241340/70-CL57 126573ScourXL 2640 120523 13885040 5829613348 1576140/70-CL106 137180Resume PadXL 2640 50573 14382100 603960 15761 50 142191FlatXL 2640 165738 16036930 673266635 22397CSG-IV158 1579102FlatXL 2640 180918 17837560 7488613887 36283CSG-IV165 1745113FlatXL 2640 1951113 19788190 8307621682 57965CSG-IV172 1917124FlatXL 2640 1951308 21738190 9126627819 85784CSG-IV166 2082135FlatXL 2640 1951503 23688190 9945633510 119294CSG-IV160 2242146FlatXL 2640 1951698 25638190 10764638802 158096CSG-IV154 2396157FlatXL 2640 1851883 27487770 11541641493 199589CSG-IV141 2537168FlatXL 2640 1702053 29187140 12255642148 241736CSG-IV125 2662170Clear Surface LinesXL 2640 152068 2933630 1231860 241736 15 2677180Spacer XL 2640152083 2948630 1238160 241736 15 2692190Drop Stage 2 Ball/Collet FP 04032086 2951126 1239420 241736 3 2695200Stage 2 PADXL 2640 2402326 319110080 1340220 241736 240 2935210Slow for Seat XL 2618502376 32412100 1361220 241736 50 2985220Resume PadXL 2640 1352511 33765670 1417920 241736 135 3120231FlatXL 2640 1702681 35467140 1489326836 248572CSG-IV163 3283242FlatXL 2640 1902871 37367980 15691214658 263231CSG-IV175 3458253FlatXL 2640 2103081 39468820 16573223349 286580CSG-IV185 3643264FlatXL 2640 2103291 41568820 17455229959 316539CSG-IV178 3821275FlatXL 2640 2103501 43668820 18337236088 352627CSG-IV172 3993286FlatXL 2640 2103711 45768820 19219241787 394413CSG-IV166 4159297FlatXL 2640 2003911 47768400 20059244857 439270CSG-IV153 4312308FlatXL 2640 1754086 49517350 20794243387 482657CSG-IV129 4441310Clear Surface LinesXL 2640 154101 4966630 2085720 482657 15 4456FLUIDNeat WaterCOMMENTSPrime and Pressure TestOpen well and initiate P-SleeveSD monitor 1.5H, line up for XLHSD- Monitor 30 minLoad Stage 1/ Collet #1DFIT Displacement (Add surface lines) Well NameNDB-01107/16/25 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)FLUIDNeat Water320Spacer XL 2640154116 4981630 2092020 482657 15 4471330Drop Stage 3 Ball/Collet FP 04034119 4984126 2093280 482657 3 4474340Stage 3 PADXL 2640 2314350 52159702 2190300 482657 231 4705350Slow for Seat XL 2618504400 52652100 2211300 482657 50 4755360Resume PadXL 2640 14401 526642 2211720 482657 1 4756371ScourXL 2640 604461 53262520 2236922413 48507140/70-CL57 4813383ScourXL 2640 1204581 54465040 22873213348 49841940/70-CL106 4919390Resume PadXL 2640 504631 54962100 2308320 498419 50 4969401FlatXL 2640 2004831 56968400 2392328044 506463CL-NRT192 5161412FlatXL 2640 2255056 59219450 24868217363 523826CL-NRT207 5367424FlatXL 2640 2755331 619611550 26023239253 563079CL-NRT234 5601436FlatXL 2640 2605591 645610920 27115251775 614853CL-NRT205 5806448FlatXL 2640 2405831 669610080 28123259558 674411CL-NRT177 59844510FlatXL 2640 2006031 68968400 28963258233 732644CL-NRT139 6122460Clear Surface LinesXL 2640 156046 6911630 2902620 732644 15 6137470Spacer XL 2640156061 6926630 2908920 732644 15 6152480Drop Stage 4 Ball/Collet FP 04036064 6929126 2910180 732644 3 6155490Stage 4 PADXL 2640 2206284 71499240 3002580 732644 220 6375500Slow for Seat XL 2618506334 71992100 3023580 732644 50 6425510Resume PadXL 2640 106344 7209420 3027780 732644 10 6435521ScourXL 2640 606404 72692520 3052982413 73505740/70-CL57 6493533ScourXL 2640 1206524 73895040 31033813348 74840640/70-CL106 6599540Resume PADXL 2640 506574 74392100 3124380 748406 50 6649551FlatXL 2640 2006774 76398400 3208388043 756448CSG-IV191 6840562FlatXL 2640 2256999 78649450 33028817358 773807CSG-IV207 7047574FlatXL 2640 2757274 813911550 34183839232 813038CSG-IV234 7280586FlatXL 2640 2607534 839910920 35275851736 864774CSG-IV205 7486598FlatXL 2640 2407774 863910080 36283859502 924277CSG-IV177 76636010FlatXL 2640 2007974 88398400 37123858170 982447CSG-IV138 7801610Clear Surface LinesXL 2640 157989 8854630 3718680 982447 15 7816620Spacer XL 2640158004 8869630 3724980 982447 15 7831630Drop Stage 5 Ball/Collet FP 04038007 8872126 3726240 982447 3 7834640Stage 5 PADXL 2640 2128219 90848904 3815280 982447 212 8046650Slow for Seat XL 2618508269 91342100 3836280 982447 50 8096660Resume PadXL 2640 1388407 92725796 3894240 982447 138 8234671FlatXL 2640 2008607 94728400 3978248043 990489CSG-IV191 8426682FlatXL 2640 2008807 96728400 40622415430 1005919CSG-IV184 8610694FlatXL 2640 2209027 98929240 41546431385 1037304CSG-IV187 8796706FlatXL 2640 2509277 1014210500 42596449746 1087051CSG-IV197 8994718FlatXL 2640 2209497 103629240 43520454544 1141594CSG-IV162 91567210FlatXL 2640 2009697 105628400 44360458170 1199764CSG-IV138 92957312FlatXL 2640 1609857 107226720 45032452608 1252372CSG-IV104 9399740Clear Surface LinesXL 2640 159872 10737630 4509540 1252372 15 9414 Well NameNDB-01107/16/25 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)FLUIDNeat Water750Spacer XL 2640159887 10752630 4515840 1252372 15 9429760Drop Stage 6 Ball/Collet FP 04039890 10755126 4517100 1252372 3 9432770Stage 6 PADXL 2640 20310093 109588526 4602360 1252372 203 9635780Slow for Seat XL 26185010143 110082100 4623360 1252372 50 9685790Resume PadXL 2640 14710290 111556174 4685100 1252372 147 9832801FlatXL 2640 20010490 113558400 4769108044 1260416CL-NRT192 10023812FlatXL 2640 20010690 115558400 48531015434 1275850CL-NRT184 10207824FlatXL 2640 22010910 117759240 49455031402 1307252CL-NRT187 10394836FlatXL 2640 25011160 1202510500 50505049783 1357035CL-NRT198 10592848FlatXL 2640 22011380 122459240 51429054595 1411630CL-NRT162 107548510FlatXL 2640 20011580 124458400 52269058233 1469863CL-NRT139 108938612FlatXL 2640 16011740 126056720 52941052672 1522535CL-NRT105 10997870Clear Surface LinesXL 2640 1511755 12620630 5300400 1522535 15 11012880Spacer XL 26401511770 12635630 5306700 1522535 15 11027890Drop Stage 7 Ball/Collet FP 040311773 12638126 5307960 1522535 3 11030900XL FlushDFIT FluidXL 264019411967128328148538944015225351941122491XL Flush (DFIT Fluid)XL 261856 12023 120812352 54129656 1128092Linear FlushWF 2640164 12187 122456888 548184164 11444933000 feet MD + Surface EqmtFP20 5812245 123032423 550607TOTALS13110 5506071522535 Well NameNDB-01107/16/25 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)aWF00000bPump Ball to SeatWF25 422422494089408224224cPump CheckWF25 401003244200136081003240324 PUMP DIRTY VOLUME DIRTY VOLUME PROPPANTCLEAN VOLUM STAGE AVERAGE FLUID RATE STAGE CUM TOT JOBSTAGE CUMSTAGE CUM Size or Stage Cum# PPA TYPE (BPM) (BBL) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) Type (BBL) (BBL)10Line out XL XL 26404040 3641680 1528800 4036420Stage 7 PADXL 2640 250290 61410500 2578800CSG-IV250 61431FlatXL 2640 60350 6742520 283082413 241340/70-CL57 67143FlatXL 2640 120470 7945040 3334813348 1576140/70-CL106 77750FlatXL 2640 50520 8442100 354480 15761 50 82761FlatXL 2640 195715 10398190 436387842 23603CSG-IV187 101473FlatXL 2640 220935 12599240 5287824461 48065CSG-IV194 120885FlatXL 2640 2501185 150910500 6337842961 91026CSG-IV205 141397FlatXL 2640 2501435 175910500 7387856071 147097CSG-IV191 1604109FlatXL 26402251660 19849450 8332860765 207863CSG-IV161 17641111FlatXL 2640 1901850 21747980 9130858974 266836CSG-IV128 1892120Clear Surface LinesXL 2640 151865 2189630 919380 266836 15 1907130Spacer XL 2640151880 2204630 925680 266836 15 1922140Drop Stage 8 Ball/Collet FP 04031883 2207126 926940 266836 3 1925150Stage 8 PADXL 2640 1852068 23927770 1004640 266836 185 2110160Slow for Seat XL 2618502118 24422100 1025640 266836 50 2160170Resume PADXL 2640 152133 2457630 1031940 266836 15 2175181ScourXL 2640 602193 25172520 1057142413 26925040/70-CL57 2232193ScourXL 2640 1202313 26375040 11075413348 28259840/70-CL106 2338200Resume PADXL 2640 502363 26872100 1128540 282598 50 2388211FlatXL 2640 1952558 28828190 1210447842 290440CSG-IV187 2575223FlatXL 2640 2202778 31029240 13028424461 314901CSG-IV194 2769235FlatXL 2640 2503028 335210500 14078442961 357862CSG-IV205 2974247FlatXL 2640 2503278 360210500 15128456071 413934CSG-IV191 3164259FlatXL 2640 2253503 38279450 16073460765 474699CSG-IV161 33252611FlatXL 2640 1903693 40177980 16871458974 533673CSG-IV128 3453270Clear Surface LinesXL 2640 153708 4032630 1693440 533673 15 3468280Spacer XL 2640153723 4047630 1699740 533673 15 3483290Drop Stage 9 Ball/Collet FP 04033726 4050126 1701000 533673 3 3486300Stage 9 PADXL 2640 1773903 42277434 1775340 533673 177 3663310Slow for Seat XL 2618503953 42772100 1796340 533673 50 3713320Resume PadXL 2640 233976 4300966 1806000 533673 23 3736331ScourXL 2640 604036 43602520 1831202413 53608640/70-CL57 3793343ScourXL 2640 1204156 44805040 18816013348 54943440/70-CL106 3899FLUIDNeat WaterCOMMENTSPrime and Pressure TestDrop Ball then load Stage 8 Ball/ColletStage to Line out XL Well NameNDB-01107/16/25 DesignSTAGE COMMENTS PUMP DIRTY VOLUME DIRTY VOLUME PROPPANT# TYPE PPT RATE STAGE CUMSTAGE CUMSTAGE CUM SIZE Stage CumPre Frac - Non Proppant stages(BPM) (BBL) (BBL)(GAL) (GAL)(LBS) (LBS) (BBL) (BBL)FLUIDNeat Water350Resume PADXL 2640 504206 45302100 1902600 549434 50 3949361FlatXL 2640 2004406 47308400 1986608044 557478CL-NRT192 4141372FlatXL 2640 2304636 49609660 20832017749 575228CL-NRT211 4352384FlatXL 2640 2804916 524011760 22008039966 615194CL-NRT238 4590396FlatXL 2640 2655181 550511130 23121052770 667964CL-NRT209 4799408FlatXL 2640 2455426 575010290 24150060798 728763CL-NRT181 49804110FlatXL 2640 2105636 59608820 25032061145 789907CL-NRT146 5126420Clear Surface LinesXL 2640 155651 5975630 2509500 789907 15 5141430Spacer XL 2640155666 5990630 2515800 789907 15 5156440Drop Stage 10 Ball/Collet FP 04035669 5993126 2517060 789907 3 5159450Stage 10 PADXL 2640 1685837 61617056 2587620 789907 168 5327460Slow for Seat XL 2618505887 62112100 2608620 789907 50 5377470Resume PadXL 2640 325919 62431344 2622060 789907 32 5409481ScourXL 2640 605979 63032520 2647262413 79232140/70-CL57 5466493ScourXL 2640 1206099 64235040 26976613348 80566940/70-CL106 5572500Resume PADXL 2640 506149 64732100 2718660 805669 50 5622511FlatXL 2640 2006349 66738400 2802668043 813712CSG-IV191 5814522FlatXL 2640 2256574 68989450 28971617358 831070CSG-IV207 6020534FlatXL 2640 2756849 717311550 30126639232 870302CSG-IV234 6254546FlatXL 2640 2607109 743310920 31218651736 922038CSG-IV205 6459558FlatXL 2640 2407349 767310080 32226659502 981540CSG-IV177 66365610FlatXL 2640200754978738400330666581701039710CSG-IV138677557XL FlushXL 264020 7569 7893840 33150620 679558Linear FlushWF 2640118 7687 80114956 336462118 6913593000 feet MD + Surface EqmtFP20 587745 80692423 338885TOTALS8069 3388851039710SD and obtain ISIP & 15 min SIP. 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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 NDB-011 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-011 4-1/2” Production Liner Section Summary Procedure: 1. Run 4-1/2” 12.6 ppf P-110S TSH563 lower completions per tally. 2. Circulate out 9.8 ppg OBM with 9.8 ppg NaCl brine up to 5 bpm, spotting the spacer train tail end near the liner hanger. 3. Drop 1.125” phenolic ball during circulation to close WIV collar. 4. Pressure up to close the WIV at 1,485 psi. 5. Continue increasing pressure to start setting the liner hanger/packer at 2,500 psi. 6. Set the openhole packers and neutralize pusher tool to 4,100 psi. a. Pressure did not hold once at 4,100 psi. Was able to set the liner hanger and openhole packers. 7. Before releasing, pressure test the IA to top liner hanger/packer to 3,500 psi for 10 min and passed. 8. Release running tool from liner hanger. 9. Circulate spacer train and 9.4 ppg NaCl Corrosion Inhibited with biocide to surface at 10 bpm pump rate. 10.Flow check for 10 minutes. 11.POOH with liner hanger running tool. 12.Prepare to run upper completion. NDB-011 4-1/2” Upper Completion Section Summary Procedure: 13.Run 4-1/2” 12.6 ppf P110S TSH563 tubing and downhole jewellery. 14.Land tubing hanger. 15.MIT-IA to 4,000 psi for 30 minutes (Post rig, pressure test to 4,300 psi MIT-IA for 30 mins) 16.MIT-T to 3,500 psi for 30 minutes (Pot rig, pressure test to 5,500 psi MIT-T for 30 mins) a. (8,800 psi MAWP – 3,800 psi IA hold during frac) * 1.1 = 5,500 psi tubing 17.Nipple down BOP stack and install 10k frac tree. 18.RDMO Attachment I Attachment J Tuluvak Sand @ 3,226' MD Top Nan 3.2 @12,542' MD Top Nanushuk @ 9,436' MD NDB-011 Well Schematic (As-Drill) 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2,578' MD 13-3/8" 68 ppf L-80 Surface Casing2,758' MD 9-5/8", 47ppf L-80 Production Liner12,419' MD 4-½”, 12.6ppf P-110S Production Liner 18,617' MD 4-½” Liner Hanger/ Top Packer12,228' MD GL 69.50' RKB – Bottom Flange July 25th, 2025 1 2 3 4 5 6 9-5/8" Tieback2,578' MD 9-5/8" Cflex Stage Tool (101' MD below TS790) 4,750' MD 9-5/8" Primary TOC (159' MD/35' TVD above top HC) 9,632' MD 8-½” Openhole TD TD 18,634' MD # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1505 1468 25 3.813 4.778 2 Gaslift Mandrel 1.5" 2229 2054 46 3.865 7.652 3 X Landing Nipple 2300 2102 48 3.813 4.778 4 SSD NERA Gaslift 12030 4341 86 3.813 7.000 5 D/H Psi-Temp Gauge 12095 4345 86 3.958 7.000 6 EGL Valve 12159 4349 87 3.918 6.173 7 Tieback Seal Assy 12269 4355 88 3.880 8.210 8 9.625" x 4.5" LH/Packer 12228 4353 87 6.030 8.430 9 #13 OH packer 12568 4362 90 3.918 8.000 10 #12 OH packer 12635 4362 90 3.735 5.624 11 #20 Tracer Carrier 12974 4355 92 3.958 5.720 12 Stg 10 - Collet Sleeve 10 13025 4353 92 3.735 5.624 13 #19 Tracer Carrier 13038 4353 92 3.958 5.720 14 #11 OH packer 13171 4349 92 3.918 8.000 15 #18 Tracer Carrier 13595 4337 92 3.958 5.720 16 Stg 9 - Collet Sleeve 9 13646 4335 92 3.735 5.624 17 #17 Tracer Carrier 13660 4335 92 3.958 5.720 18 #10 OH packer 13956 4326 92 3.918 8.000 19 #16 Tracer Carrier 14095 4322 92 3.958 5.720 20 Stg 8 - Collet Sleeve 8 14146 4321 92 3.735 5.624 21 #15 Tracer Carrier 14160 4320 92 3.958 5.720 22 #9 OH packer 14335 4315 92 3.918 8.000 23 #14 Tracer Carrier 14681 4305 92 3.958 5.720 24 Stg 7 - Collet Sleeve 7 14732 4304 92 3.735 5.624 25 #13 Tracer Carrier 14746 4303 92 3.958 5.720 26 #8 OH packer 15002 4296 92 3.918 8.000 27 #12 Tracer Carrier 15265 4288 92 3.958 5.720 28 Stg 6 - Collet Sleeve 6 15316 4287 92 3.735 5.625 29 #11 Tracer Carrier 15330 4287 92 3.958 5.720 30 #7 OH packer 15627 4278 92 3.918 8.000 31 #10 Tracer Carrier 15851 4271 92 3.958 5.720 32 Stg 5 - Collet Sleeve 5 15902 4270 92 3.735 5.624 33 #9 Tracer Carrier 15916 4270 92 3.958 5.720 34 #6 OH packer 16172 4247 92 3.918 8.000 35 #8 Tracer Carrier 16434 4255 92 3.958 5.720 36 Stg 4 - Collet Sleeve 4 16486 4253 92 3.735 5.624 37 #7 Tracer Carrier 16500 4253 92 3.958 5.720 38 #5 OH Packer 16796 4244 92 3.918 8.000 39 #4 OH packer 16944 4240 92 3.918 8.000 40 #6 Tracer Carrier 17122 4235 92 3.958 5.720 41 Stg 3 - Collet Sleeve 3 17174 4233 92 3.735 5.624 42 #5 Tracer Carrier 17188 4233 92 3.958 5.720 43 #3 OH packer 17444 4225 92 3.918 8.000 44 #4 Tracer Carrier 17704 4218 92 3.958 5.720 45 Stg 2 - Collet Sleeve 2 17755 4216 92 3.735 5.624 46 #3 Tracer Carrier 17768 4216 92 3.958 5.720 47 #2 OH packer 18023 4209 92 3.918 8.000 48 #2 Tracer Carrier 18244 4202 92 3.958 5.720 49 Stg 1 - Collet Sleeve 1 18296 4201 92 3.735 5.624 50 #1 Tracer Carrier 18310 4200 92 3.958 5.720 51 #1 OH packer 18480 4195 92 3.918 8.000 52 Toe Sleeve 18588 4192 92 3.500 5.750 53 WIV Collar 18602 4192 92 0.870 5.620 54 Eccentric shoe 18615 4191 92 3.840 5.200 12269 Attachment K FracCADE* STIMULATION PROPOSAL KƉĞƌĂƚŽƌ ͗Kŝů^ĞĂƌĐŚ tĞůů ͗EͲϬϭϭ &ŝĞůĚ ͗WŝŬŬĂ &ŽƌŵĂƚŝŽŶ ͗EĂŶƵƐŚƵŬ ^ƚĂŐĞƐϭƚŽϭϬ ŽƵŶƚLJ ͗EŽƌƚŚ^ůŽƉĞ ^ƚĂƚĞ ͗ůĂƐŬĂ ŽƵŶƚƌLJ ͗hŶŝƚĞĚ^ƚĂƚĞƐ WƌĞƉĂƌĞĚĨŽƌ͗^ĐŽƚƚ>ĞĂŚLJ ^ĞƌǀŝĐĞWŽŝŶƚ͗WƌƵĚŚŽĞĂLJ͕ůĂƐŬĂ ƵƐŝŶĞƐƐWŚŽŶĞ͗ϭϵϬϳϲϱϵϮϰϯϰ ĂƚĞWƌĞƉĂƌĞĚ͗ϬϳͲϮϯͲϮϬϮϱ WƌĞƉĂƌĞĚďLJ ͗>ĂƵƌĂĐŽƐƚĂ WŚŽŶĞ ͗ ͲDĂŝůĚĚƌĞƐƐ ͗EdƌĞǀŝŶŽϮΛƐůď͘ĐŽŵ * Mark of Schlumberger Disclaimer Notice: This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. ϭ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 1: Zone Data (Stage 1; 18296 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϭϬϱ͘ϳ ϭϬ͘Ϭ Ϭ͘ϳϭ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϭϭϱ͘ϳ ϭϱ͘Ϭ Ϭ͘ϳϬ Ϯϴϲϲ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ ϰϭϯϬ͘ϳ ϭϱ͘ϯ Ϭ͘ϲϴ ϮϴϬϲ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ ϰϭϰϲ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϮ Ϯϱϴϵ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ ϰϭϲϱ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϵ ϮϴϴϬ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϭϲϳ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ Ϯϲϱϵ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϭϲϵ͘Ϭ ϰ͘ϱ Ϭ͘ϲϮ Ϯϱϲϵ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϭϳϯ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϴϴϲ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϭϳϳ͘Ϭ ϭϰ͘ϱ Ϭ͘ϲϱ ϮϳϮϬ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϭϵϭ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ ϮϳϬϬ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϭϵϯ͘Ϭ ϭϮ͘ϱ Ϭ͘ϲϯ Ϯϲϰϲ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϬϱ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϳϯϬ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϬϳ͘ϱ ϵ͘Ϭ Ϭ͘ϲϭ Ϯϱϱϴ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϭϲ͘ϱ ϳ͘Ϭ Ϭ͘ϲϱ ϮϳϲϬ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϮϯ͘ϱ ϵ͘Ϭ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϮϯϮ͘ϱ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϮϬ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϯϲ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϯ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϰϭ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ Ϯϵϭϴ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ ϰϮϰϯ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϭ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϱϯ͘ϱ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϱϳ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϭϵ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϮϱϵ͘Ϭ ϱ͘ϱ Ϭ͘ϲϱ ϮϳϲϮ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϮϲϰ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϵϰϰ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϲϴ͘Ϭ ϯ͘ϱ Ϭ͘ϲϯ Ϯϲϵϰ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϮϳϭ͘ϱ ϱ͘ϱ Ϭ͘ϲϵ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϳϳ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϯ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϴϳ͘ϱ ϭ͘ϱ Ϭ͘ϲϱ ϮϴϬϱ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϴϵ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϲϱ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϮϵϰ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϲ Ϯϴϭϯ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϵϲ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϮ ϮϲϴϮ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϬϬ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϳ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϬϮ͘Ϭ ϭϬ͘Ϭ Ϭ͘ϲϯ ϮϳϬϬ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϭϮ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϱ ϮϴϮϭ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϭϲ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϵ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϮϬ͘Ϭ ϵ͘ϱ Ϭ͘ϲϰ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϮϵ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϭ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϯϭ͘ϱ ϵ͘ϱ Ϭ͘ϲϵ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϰϭ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϰϯ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϯϰϱ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϲϱ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϰϳ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϯϰϵ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϱ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϱϯ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϵ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϯϳϮ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϳϰ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϯϳϲ͘ϱ ϴ͘Ϭ Ϭ͘ϲϱ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϴϰ͘ϱ ϴ͘Ϭ Ϭ͘ϲϱ Ϯϴϯϱ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϵϮ͘ϱ ϮϬ͘Ϭ Ϭ͘ϲϵ ϯϬϰϳ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Zone Name Ratio Formation Mechanical Properties Ϯ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4105.7 10.0 0.001 1.0 1890 4115.7 15.0 0.001 1.0 1898 4130.7 15.3 0.005 10.0 1905 4146.0 19.5 30.655 23.7 1915 4165.5 2.0 5.000 10.0 1924 4167.5 1.5 2.095 16.9 1925 4169.0 4.5 48.388 26.6 1926 4173.5 3.5 0.478 12.4 1928 4177.0 14.5 15.008 17.7 1930 4191.5 1.5 3.661 17.6 1937 4193.0 12.5 34.723 23.9 1937 4205.5 2.0 1.697 15.6 1943 4207.5 9.0 54.319 24.4 1944 4216.5 7.0 3.610 14.8 1948 4223.5 9.0 22.986 20.4 1952 4232.5 3.5 0.835 14.0 1956 4236.0 5.0 65.392 23.4 1957 4241.0 2.0 0.006 10.5 1960 4243.0 10.5 100.832 25.6 1961 4253.5 3.5 17.434 20.5 1966 4257.0 2.0 161.343 26.3 1967 4259.0 5.5 4.627 18.4 1968 4264.5 3.5 5.075 14.8 1971 4268.0 3.5 8.651 19.4 1972 4271.5 5.5 10.205 16.0 1974 4277.0 10.5 17.356 20.1 1977 4287.5 1.5 3.106 14.8 1982 4289.0 5.0 52.863 20.6 1982 4294.0 2.0 2.277 14.1 1985 4296.0 4.0 122.778 23.1 1986 4300.0 2.0 0.333 12.5 1987 4302.0 10.0 39.939 21.2 1988 4312.0 4.0 0.748 13.3 1993 4316.0 4.0 0.009 10.9 1995 4320.0 9.5 5.399 16.7 1997 4329.5 2.0 160.618 24.9 2001 4331.5 9.5 0.033 11.5 2002 4341.0 2.0 6.733 16.2 2007 4343.0 2.0 0.001 1.0 2008 4345.0 2.0 29.480 19.6 2009 4347.0 2.0 0.001 1.0 2009 4349.0 4.0 8.473 16.6 2010 4353.0 19.5 0.001 1.0 2012 4372.5 2.0 2.185 16.4 2021 4374.5 2.0 0.001 1.0 2022 4376.5 8.0 2.645 15.9 2023 4384.5 8.0 2.026 14.4 2027 4392.5 20.0 0.001 10.0 2031 Nan CS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Zone Name Formation Transmissibility Properties Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Shale Nan DS Nan DS Shale Nan DS Nan DS Shale ϯ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 2: Propped Fracture Schedule (Stage 1; 18296 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF126ST 300.0 26 0 1.0 PPA 40 YF126ST 57.5 26 1 3.0 PPA 40 YF126ST 105.9 26 3 Resume PAD 40 YF126ST 50.0 26 0 1.0 PPA 40 YF126ST 158.0 26 1 2.0 PPA 40 YF126ST 165.3 26 2 3.0 PPA 40 YF126ST 172.1 26 3 4.0 PPA 40 YF126ST 165.6 26 4 5.0 PPA 40 YF126ST 159.6 26 5 6.0 PPA 40 YF126ST 154.0 26 6 7.0 PPA 40 YF126ST 141.2 26 7 8.0 PPA 40 YF126ST 125.5 26 8 Flush 40 YF126ST 278.7 26 0 Please note that this pumping schedule is under-displaced by 0 bbl. 2033.3 bbl of YF126ST 0 bbl of WF126 225999 lb of 15763 lb of % PAD Clean 17.1 % PAD Dirty 14.9 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 300.0 300 300 300 0 0 4408 7.5 7.5 1.0 PPA 57.5 357 60 360 2413 2413 4408 1.5 9.0 3.0 PPA 105.9 463 120 480 13349 15763 4335 3.0 12.0 Resume PAD 50.0 513 50 530 0 15763 4230 1.3 13.3 1.0 PPA 158.0 671 165 695 6636 22398 4193 4.1 17.4 2.0 PPA 165.3 837 180 875 13887 36285 4198 4.5 21.9 3.0 PPA 172.1 1009 195 1070 21683 57968 4124 4.9 26.8 4.0 PPA 165.6 1174 195 1265 27821 85790 4180 4.9 31.6 5.0 PPA 159.6 1334 195 1460 33513 119303 4264 4.9 36.5 6.0 PPA 154.0 1488 195 1655 38807 158110 4454 4.9 41.4 7.0 PPA 141.2 1629 185 1840 41498 199608 4697 4.6 46.0 8.0 PPA 125.5 1755 170 2010 42154 241761 4919 4.3 50.3 The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 383.2 ft with an average conductivity (Kfw) of 13366.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV 0 Fluid Totals Pad Percentages Job Execution Step Name 0 Carbolite 40/70 Carbolite 40/70 0 Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV ϰ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Flush 278.7 2033 279 2289 0 241761 4983 7.0 57.2 ϱ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 3: Propped Fracture Simulation (Stage 1; 18296 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϭϭϬ͘ϳĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϯϱϳĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϴϯ͘ϮĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϰϲ͘ϯĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϱϴŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϳϬƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϱϬϵϭƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 95.8 7.4 0.202 146.4 1.75 258.7 17942 95.8 191.6 6 0.195 223.5 1.75 278.8 16981 191.6 287.4 4.9 0.16 202.1 1.46 331 13518 287.4 383.2 1.9 0.085 147.7 0.79 582.1 6623 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment ϲ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< ϱϬϵϭƉƐŝ Section 4: Zone Data (Stage 2; 17755 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϭϭϵ͘ϳ ϭϬ͘Ϭ Ϭ͘ϳϭ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϭϮϵ͘ϳ ϭϱ͘Ϭ Ϭ͘ϳϬ Ϯϴϳϱ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ ϰϭϰϰ͘ϳ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϴϭϱ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ ϰϭϲϬ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϮ Ϯϱϵϴ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ ϰϭϳϵ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϵ ϮϴϴϬ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϭϴϭ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ Ϯϲϲϴ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϭϴϯ͘Ϭ ϰ͘ϱ Ϭ͘ϲϮ Ϯϱϳϴ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϭϴϳ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϴϴϲ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϭϵϭ͘Ϭ ϭϰ͘ϱ Ϭ͘ϲϱ ϮϳϮϵ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϬϱ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ ϮϳϬϵ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϬϳ͘Ϭ ϭϮ͘ϱ Ϭ͘ϲϯ Ϯϲϱϰ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϭϵ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϳϯϵ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϮϭ͘ϱ ϵ͘Ϭ Ϭ͘ϲϭ Ϯϱϱϴ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϯϬ͘ϱ ϳ͘Ϭ Ϭ͘ϲϱ Ϯϳϲϵ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϯϳ͘ϱ ϵ͘Ϭ Ϭ͘ϲϰ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϮϰϲ͘ϱ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϮϬ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϱϬ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϯ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϱϱ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϮϵϮϴ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ ϰϮϱϳ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϭ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϲϳ͘ϱ ϯ͘ϱ Ϭ͘ϲϯ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϳϭ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϮ ϮϲϮϳ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϮϳϯ͘Ϭ ϱ͘ϱ Ϭ͘ϲϱ Ϯϳϳϭ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϮϳϴ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϵϱϯ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϴϮ͘Ϭ ϯ͘ϱ Ϭ͘ϲϯ ϮϳϬϯ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϮϴϱ͘ϱ ϱ͘ϱ Ϭ͘ϲϴ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϵϭ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϯ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϬϭ͘ϱ ϭ͘ϱ Ϭ͘ϲϱ Ϯϴϭϰ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϬϯ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϳϰ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϬϴ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϲ ϮϴϮϮ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϭϬ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϮ Ϯϲϵϭ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϭϰ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϳ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϭϲ͘Ϭ ϭϬ͘Ϭ Ϭ͘ϲϯ ϮϳϬϵ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϮϲ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϱ Ϯϴϯϭ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϯϬ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϵ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϯϰ͘Ϭ ϵ͘ϱ Ϭ͘ϲϰ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϰϯ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϭ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϰϱ͘ϱ ϵ͘ϱ Ϭ͘ϲϴ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϱϱ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϱ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϱϳ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϯϱϵ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϲϱ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϲϭ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϯϲϯ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϱ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϲϳ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϵ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϯϴϲ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϴϴ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϯϵϬ͘ϱ ϴ͘Ϭ Ϭ͘ϲϱ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϵϴ͘ϱ ϴ͘Ϭ Ϭ͘ϲϱ Ϯϴϰϰ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϬϲ͘ϱ ϮϬ͘Ϭ Ϭ͘ϲϵ ϯϬϱϲ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Ratio ϳ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4119.7 10.0 0.001 1.0 1890 4129.7 15.0 0.001 1.0 1898 4144.7 15.3 0.005 10.0 1905 4160.0 19.5 30.655 23.7 1915 4179.5 2.0 5.000 10.0 1924 4181.5 1.5 2.095 16.9 1925 4183.0 4.5 48.388 26.6 1926 4187.5 3.5 0.478 12.4 1928 4191.0 14.5 15.008 17.7 1930 4205.5 1.5 3.661 17.6 1937 4207.0 12.5 34.723 23.9 1937 4219.5 2.0 1.697 15.6 1943 4221.5 9.0 54.319 24.4 1944 4230.5 7.0 3.610 14.8 1948 4237.5 9.0 22.986 20.4 1952 4246.5 3.5 0.835 14.0 1956 4250.0 5.0 65.392 23.4 1957 4255.0 2.0 0.006 10.5 1960 4257.0 10.5 100.832 25.6 1961 4267.5 3.5 17.434 20.5 1966 4271.0 2.0 161.343 26.3 1967 4273.0 5.5 4.627 18.4 1968 4278.5 3.5 5.075 14.8 1971 4282.0 3.5 8.651 19.4 1972 4285.5 5.5 10.205 16.0 1974 4291.0 10.5 17.356 20.1 1977 4301.5 1.5 3.106 14.8 1982 4303.0 5.0 52.863 20.6 1982 4308.0 2.0 2.277 14.1 1985 4310.0 4.0 122.778 23.1 1986 4314.0 2.0 0.333 12.5 1987 4316.0 10.0 39.939 21.2 1988 4326.0 4.0 0.748 13.3 1993 4330.0 4.0 0.009 10.9 1995 4334.0 9.5 5.399 16.7 1997 4343.5 2.0 160.618 24.9 2001 4345.5 9.5 0.033 11.5 2002 4355.0 2.0 6.733 16.2 2007 4357.0 2.0 0.001 1.0 2008 4359.0 2.0 29.480 19.6 2009 4361.0 2.0 0.001 1.0 2009 4363.0 4.0 8.473 16.6 2010 4367.0 19.5 0.001 1.0 2012 4386.5 2.0 2.185 16.4 2021 4388.5 2.0 0.001 1.0 2022 4390.5 8.0 2.645 15.9 2023 4398.5 8.0 2.026 14.4 2027 4406.5 20.0 0.001 10.0 2031 Nan DS Formation Transmissibility Properties Zone Name Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan CS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS Nan DS Shale ϴ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 5: Propped Fracture Schedule (Stage 2; 17755 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF126ST 425.0 26 0 1.0 PPA 40 YF126ST 162.8 26 1 2.0 PPA 40 YF126ST 174.5 26 2 3.0 PPA 40 YF126ST 185.3 26 3 4.0 PPA 40 YF126ST 178.3 26 4 5.0 PPA 40 YF126ST 171.9 26 5 6.0 PPA 40 YF126ST 165.8 26 6 7.0 PPA 40 YF126ST 152.6 26 7 8.0 PPA 40 YF126ST 129.1 26 8 Flush 40 YF126ST 270.5 26 0 Please note that this pumping schedule is under-displaced by 0 bbl. 2015.9 bbl of YF126ST 0 bbl of WF126 240947 lb of 0 lb of % PAD Clean 24.3 % PAD Dirty 21.3 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 425.0 425 425 425 0 0 4320 10.6 10.6 1.0 PPA 162.8 588 170 595 6837 6837 4275 4.3 14.9 2.0 PPA 174.5 762 190 785 14659 21495 4088 4.8 19.6 3.0 PPA 185.3 948 210 995 23351 44846 4054 5.3 24.9 4.0 PPA 178.3 1126 210 1205 29961 74808 4106 5.3 30.1 5.0 PPA 171.9 1298 210 1415 36091 110899 4184 5.3 35.4 6.0 PPA 165.8 1464 210 1625 41792 152691 4372 5.3 40.6 7.0 PPA 152.6 1616 200 1825 44863 197553 4597 5.0 45.6 8.0 PPA 129.1 1745 175 2000 43393 240947 4813 4.4 50.0 Flush 270.5 2016 270 2270 0 240947 4850 6.8 56.8 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 412.6 ft with an average conductivity (Kfw) of 12262.5 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Job Execution Step Name ϵ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 6: Propped Fracture Simulation (Stage 2; 17755 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϭϮϯ͘ϲĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϯϳϯ͘ϴĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϰϭϮ͘ϲĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů ϮϱϬ͘ϮĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϰϲŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϱϭƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϰϵϲϳƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 103.1 7.8 0.167 136.2 1.44 280.5 14566 103.1 206.3 6.4 0.162 202.9 1.45 291.1 13812 206.3 309.4 5.2 0.142 197.6 1.25 318.6 11865 309.4 412.6 2.7 0.117 163 1.09 351.7 9522 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment ϭϬ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 7: Zone Data (Stage 3; 17174 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϭϯϳ͘ϳ ϭϬ͘Ϭ Ϭ͘ϳϭ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϭϰϳ͘ϳ ϭϱ͘Ϭ Ϭ͘ϳϬ Ϯϴϴϴ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ ϰϭϲϮ͘ϳ ϭϱ͘ϯ Ϭ͘ϲϴ ϮϴϮϳ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ ϰϭϳϴ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϮ ϮϲϬϵ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ ϰϭϵϳ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϵ ϮϴϴϬ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϭϵϵ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ ϮϲϴϬ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϮϬϭ͘Ϭ ϰ͘ϱ Ϭ͘ϲϮ Ϯϱϴϵ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϮϬϱ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϴϴϲ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϬϵ͘Ϭ ϭϰ͘ϱ Ϭ͘ϲϱ Ϯϳϰϭ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϮϯ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ ϮϳϮϬ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϮϱ͘Ϭ ϭϮ͘ϱ Ϭ͘ϲϯ Ϯϲϲϲ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϯϳ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϳϱϭ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϯϵ͘ϱ ϵ͘Ϭ Ϭ͘ϲϬ Ϯϱϱϴ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϰϴ͘ϱ ϳ͘Ϭ Ϭ͘ϲϱ Ϯϳϴϭ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϱϱ͘ϱ ϵ͘Ϭ Ϭ͘ϲϯ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϮϲϰ͘ϱ ϯ͘ϱ Ϭ͘ϲϰ ϮϳϮϬ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϲϴ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϳϯ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ Ϯϵϰϭ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ ϰϮϳϱ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϭ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϴϱ͘ϱ ϯ͘ϱ Ϭ͘ϲϯ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϴϵ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϯϴ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϮϵϭ͘Ϭ ϱ͘ϱ Ϭ͘ϲϱ ϮϳϴϮ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϮϵϲ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϵϲϲ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϬϬ͘Ϭ ϯ͘ϱ Ϭ͘ϲϯ Ϯϳϭϰ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϬϯ͘ϱ ϱ͘ϱ Ϭ͘ϲϴ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϬϵ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϮ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϭϵ͘ϱ ϭ͘ϱ Ϭ͘ϲϱ ϮϴϮϱ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϮϭ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϴϱ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϮϲ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϲ Ϯϴϯϰ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϮϴ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϮ ϮϳϬϮ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϯϮ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϲ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϯϰ͘Ϭ ϭϬ͘Ϭ Ϭ͘ϲϯ ϮϳϮϭ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϰϰ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϱ ϮϴϰϮ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϰϴ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϴ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϱϮ͘Ϭ ϵ͘ϱ Ϭ͘ϲϰ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϲϭ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϭ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϲϯ͘ϱ ϵ͘ϱ Ϭ͘ϲϴ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϳϯ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϳϱ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϯϳϳ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϲϱ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϳϵ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϯϴϭ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϱ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϯϴϱ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϵ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϬϰ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϬϲ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϬϴ͘ϱ ϴ͘Ϭ Ϭ͘ϲϱ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϭϲ͘ϱ ϴ͘Ϭ Ϭ͘ϲϱ Ϯϴϱϲ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϮϰ͘ϱ ϮϬ͘Ϭ Ϭ͘ϲϵ ϯϬϲϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name s Ratio ϭϭ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4137.7 10.0 0.001 1.0 1890 4147.7 15.0 0.001 1.0 1898 4162.7 15.3 0.005 10.0 1905 4178.0 19.5 30.655 23.7 1915 4197.5 2.0 5.000 10.0 1924 4199.5 1.5 2.095 16.9 1925 4201.0 4.5 48.388 26.6 1926 4205.5 3.5 0.478 12.4 1928 4209.0 14.5 15.008 17.7 1930 4223.5 1.5 3.661 17.6 1937 4225.0 12.5 34.723 23.9 1937 4237.5 2.0 1.697 15.6 1943 4239.5 9.0 54.319 24.4 1944 4248.5 7.0 3.610 14.8 1948 4255.5 9.0 22.986 20.4 1952 4264.5 3.5 0.835 14.0 1956 4268.0 5.0 65.392 23.4 1957 4273.0 2.0 0.006 10.5 1960 4275.0 10.5 100.832 25.6 1961 4285.5 3.5 17.434 20.5 1966 4289.0 2.0 161.343 26.3 1967 4291.0 5.5 4.627 18.4 1968 4296.5 3.5 5.075 14.8 1971 4300.0 3.5 8.651 19.4 1972 4303.5 5.5 10.205 16.0 1974 4309.0 10.5 17.356 20.1 1977 4319.5 1.5 3.106 14.8 1982 4321.0 5.0 52.863 20.6 1982 4326.0 2.0 2.277 14.1 1985 4328.0 4.0 122.778 23.1 1986 4332.0 2.0 0.333 12.5 1987 4334.0 10.0 39.939 21.2 1988 4344.0 4.0 0.748 13.3 1993 4348.0 4.0 0.009 10.9 1995 4352.0 9.5 5.399 16.7 1997 4361.5 2.0 160.618 24.9 2001 4363.5 9.5 0.033 11.5 2002 4373.0 2.0 6.733 16.2 2007 4375.0 2.0 0.001 1.0 2008 4377.0 2.0 29.480 19.6 2009 4379.0 2.0 0.001 1.0 2009 4381.0 4.0 8.473 16.6 2010 4385.0 19.5 0.001 1.0 2012 4404.5 2.0 2.185 16.4 2021 4406.5 2.0 0.001 1.0 2022 4408.5 8.0 2.645 15.9 2023 4416.5 8.0 2.026 14.4 2027 4424.5 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS ϭϮ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 8: Propped Fracture Schedule (Stage 3; 17174 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF126ST 280.0 26 0 1.0 PPA Scour 40 YF126ST 57.5 26 1 3.0 PPA Scour 40 YF126ST 105.9 26 3 Resume PAD 40 YF126ST 50.0 26 0 1.0 PPA 40 YF126ST 191.5 26 1 2.0 PPA 40 YF126ST 206.7 26 2 4.0 PPA 40 YF126ST 233.7 26 4 6.0 PPA 40 YF126ST 205.5 26 6 8.0 PPA 40 YF126ST 177.3 26 8 10.0 PPA 40 YF126ST 138.7 26 10 Flush 40 YF126ST 261.6 26 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1908.4 bbl of YF126ST 0 bbl of WF126 15763 lb of 234262 lb of % PAD Clean 17.0 % PAD Dirty 14.7 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 280.0 280 280 280 0 0 4226 7.0 7.0 1.0 PPA Scour 57.5 337 60 340 2413 2413 4226 1.5 8.5 3.0 PPA Scour 105.9 443 120 460 13349 15763 4160 3.0 11.5 Resume PAD 50.0 493 50 510 0 15763 4035 1.3 12.8 1.0 PPA 191.5 685 200 710 8044 23807 4047 5.0 17.8 2.0 PPA 206.7 892 225 935 17364 41171 3978 5.6 23.4 4.0 PPA 233.7 1125 275 1210 39257 80428 3969 6.9 30.3 6.0 PPA 205.5 1331 260 1470 51782 132210 4160 6.5 36.8 8.0 PPA 177.3 1508 240 1710 59569 191779 4548 6.0 42.8 10.0 PPA 138.7 1647 200 1910 58246 250025 4993 5.0 47.8 Flush 261.6 1908 262 2172 0 250025 5056 6.5 54.3 Carbolite 16/20 NRT The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 366.6 ft with an average conductivity (Kfw) of 16044 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 NRT Pad Percentages Carbolite 16/20 NRT Carbolite 16/20 NRT Carbolite 16/20 NRT Carbolite 16/20 NRT Fluid Totals Proppant Totals Carbolite 40/70 Carbolite 16/20 NRT Job Execution Step Name ϭϯ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 9: Propped Fracture Simulation (Stage 3; 17174 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϭϰϰĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϯϵϬ͘ϲĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϲϲ͘ϲĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϰϲ͘ϳĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϲϴŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϲϲƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϱϮϳϮƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 91.6 9 0.222 145.4 1.9 230.2 21659 91.6 183.3 6.9 0.203 217.2 1.81 258 19408 183.3 274.9 4.9 0.171 201.1 1.53 297.8 16415 274.9 366.6 1.8 0.088 150.3 0.86 590.3 8456 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment ϭϰ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 10: Zone Data (Stage 4; 16487 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϭϲϮ͘ϳ ϭϬ͘Ϭ Ϭ͘ϳϬ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϭϳϮ͘ϳ ϭϱ͘Ϭ Ϭ͘ϳϬ ϮϵϬϱ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ ϰϭϴϳ͘ϳ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϴϰϰ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ ϰϮϬϯ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϮ ϮϲϮϱ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ ϰϮϮϮ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϴ ϮϴϴϬ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϮϮϰ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ Ϯϲϵϲ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϮϮϲ͘Ϭ ϰ͘ϱ Ϭ͘ϲϮ ϮϲϬϱ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϮϯϬ͘ϱ ϯ͘ϱ Ϭ͘ϲϴ Ϯϴϴϲ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϯϰ͘Ϭ ϭϰ͘ϱ Ϭ͘ϲϱ Ϯϳϱϳ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϰϴ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ Ϯϳϯϳ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϱϬ͘Ϭ ϭϮ͘ϱ Ϭ͘ϲϯ Ϯϲϴϭ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϲϮ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϳϲϳ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϲϰ͘ϱ ϵ͘Ϭ Ϭ͘ϲϬ Ϯϱϱϴ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϳϯ͘ϱ ϳ͘Ϭ Ϭ͘ϲϱ Ϯϳϵϳ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϴϬ͘ϱ ϵ͘Ϭ Ϭ͘ϲϯ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϮϴϵ͘ϱ ϯ͘ϱ Ϭ͘ϲϯ ϮϳϮϬ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϵϯ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϵϴ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ Ϯϵϱϴ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ ϰϯϬϬ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϭ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϭϬ͘ϱ ϯ͘ϱ Ϭ͘ϲϯ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϭϰ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϱϰ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϯϭϲ͘Ϭ ϱ͘ϱ Ϭ͘ϲϱ Ϯϳϵϵ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϯϮϭ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϵϴϯ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϮϱ͘Ϭ ϯ͘ϱ Ϭ͘ϲϯ ϮϳϯϬ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϮϴ͘ϱ ϱ͘ϱ Ϭ͘ϲϴ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϯϰ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϮ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϰϰ͘ϱ ϭ͘ϱ Ϭ͘ϲϱ ϮϴϰϮ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϰϲ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϮ ϮϳϬϬ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϱϭ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϲ Ϯϴϱϭ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϱϯ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϮ Ϯϳϭϴ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϱϳ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϲ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϱϵ͘Ϭ ϭϬ͘Ϭ Ϭ͘ϲϯ Ϯϳϯϲ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϲϵ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϱ Ϯϴϱϵ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϳϯ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϴ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϳϳ͘Ϭ ϵ͘ϱ Ϭ͘ϲϰ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϴϲ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϬ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϴϴ͘ϱ ϵ͘ϱ Ϭ͘ϲϴ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϵϴ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϬϬ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϬϮ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϲϱ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϬϰ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϬϲ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϱ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϭϬ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϴ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϮϵ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϯϭ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϯϯ͘ϱ ϴ͘Ϭ Ϭ͘ϲϰ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϰϭ͘ϱ ϴ͘Ϭ Ϭ͘ϲϱ ϮϴϳϮ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϰϵ͘ϱ ϮϬ͘Ϭ Ϭ͘ϲϵ ϯϬϴϲ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Ratio ϭϱ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4162.7 10.0 0.001 1.0 1890 4172.7 15.0 0.001 1.0 1898 4187.7 15.3 0.005 10.0 1905 4203.0 19.5 30.655 23.7 1915 4222.5 2.0 5.000 10.0 1924 4224.5 1.5 2.095 16.9 1925 4226.0 4.5 48.388 26.6 1926 4230.5 3.5 0.478 12.4 1928 4234.0 14.5 15.008 17.7 1930 4248.5 1.5 3.661 17.6 1937 4250.0 12.5 34.723 23.9 1937 4262.5 2.0 1.697 15.6 1943 4264.5 9.0 54.319 24.4 1944 4273.5 7.0 3.610 14.8 1948 4280.5 9.0 22.986 20.4 1952 4289.5 3.5 0.835 14.0 1956 4293.0 5.0 65.392 23.4 1957 4298.0 2.0 0.006 10.5 1960 4300.0 10.5 100.832 25.6 1961 4310.5 3.5 17.434 20.5 1966 4314.0 2.0 161.343 26.3 1967 4316.0 5.5 4.627 18.4 1968 4321.5 3.5 5.075 14.8 1971 4325.0 3.5 8.651 19.4 1972 4328.5 5.5 10.205 16.0 1974 4334.0 10.5 17.356 20.1 1977 4344.5 1.5 3.106 14.8 1982 4346.0 5.0 52.863 20.6 1982 4351.0 2.0 2.277 14.1 1985 4353.0 4.0 122.778 23.1 1986 4357.0 2.0 0.333 12.5 1987 4359.0 10.0 39.939 21.2 1988 4369.0 4.0 0.748 13.3 1993 4373.0 4.0 0.009 10.9 1995 4377.0 9.5 5.399 16.7 1997 4386.5 2.0 160.618 24.9 2001 4388.5 9.5 0.033 11.5 2002 4398.0 2.0 6.733 16.2 2007 4400.0 2.0 0.001 1.0 2008 4402.0 2.0 29.480 19.6 2009 4404.0 2.0 0.001 1.0 2009 4406.0 4.0 8.473 16.6 2010 4410.0 19.5 0.001 1.0 2012 4429.5 2.0 2.185 16.4 2021 4431.5 2.0 0.001 1.0 2022 4433.5 8.0 2.645 15.9 2023 4441.5 8.0 2.026 14.4 2027 4449.5 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS ϭϲ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 11: Propped Fracture Schedule (Stage 4; 16487 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF126ST 280.0 26 0 1.0 PPA Scour 40 YF126ST 57.5 26 1 3.0 PPA Scour 40 YF126ST 106.0 26 3 Resume PAD 40 YF126ST 50.0 26 0 1.0 PPA 40 YF126ST 191.5 26 1 2.0 PPA 40 YF126ST 206.7 26 2 4.0 PPA 40 YF126ST 233.7 26 4 6.0 PPA 40 YF126ST 205.5 26 6 8.0 PPA 40 YF126ST 177.3 26 8 10.0 PPA 40 YF126ST 138.7 26 10 Flush 40 YF126ST 251.2 26 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1897.9 bbl of YF126ST 0 bbl of WF126 234264 lb of 15763 lb of % PAD Clean 17.0 % PAD Dirty 14.7 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 280.0 280 280 280 0 0 4116 7.0 7.0 1.0 PPA Scour 57.5 337 60 340 2413 2413 4098 1.5 8.5 3.0 PPA Scour 106.0 443 120 460 13350 15763 4019 3.0 11.5 Resume PAD 50.0 493 50 510 0 15763 3916 1.3 12.8 1.0 PPA 191.5 685 200 710 8044 23807 3938 5.0 17.8 2.0 PPA 206.7 892 225 935 17364 41172 3877 5.6 23.4 4.0 PPA 233.7 1125 275 1210 39257 80428 3864 6.9 30.3 6.0 PPA 205.5 1331 260 1470 51783 132212 4062 6.5 36.8 8.0 PPA 177.3 1508 240 1711 59569 191781 4439 6.0 42.8 10.0 PPA 138.7 1647 200 1911 58246 250027 4821 5.0 47.8 Flush 251.2 1898 251 2162 0 250027 4903 6.3 54.1 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 356.7 ft with an average conductivity (Kfw) of 14810.2 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Job Execution Step Name ϭϳ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 12: Propped Fracture Simulation (Stage 4; 16487 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϭϲϵ͘ϲĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϰϭϳ͘ϳĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϱϲ͘ϳĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϰϴ͘ϭĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϳϰŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϲϭƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϱϭϮϬƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 89.2 8.8 0.229 204.4 1.98 227.7 20405 89.2 178.4 6.9 0.216 204.4 1.93 248.6 18808 178.4 267.5 5.1 0.18 203.5 1.65 295.7 15307 267.5 356.7 1.8 0.085 183 0.79 546.6 6399 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment ϭϴ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 13: Zone Data (Stage 5; 15903 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϭϳϵ͘ϳ ϭϬ͘Ϭ Ϭ͘ϳϬ Ϯϵϯϳ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϭϴϵ͘ϳ ϭϱ͘Ϭ Ϭ͘ϳϬ Ϯϵϭϳ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ EĂŶƵƐŚƵŬϯ^^ ϰϮϬϰ͘ϳ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϴϱϲ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ ϰϮϮϬ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϮ Ϯϲϯϱ ϵ͘ϬϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^^ ϰϮϯϵ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϴ ϮϴϴϬ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϮϰϭ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ ϮϳϬϳ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϮϰϯ͘Ϭ ϰ͘ϱ Ϭ͘ϲϮ Ϯϲϭϱ ϲ͘ϰϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϮϰϳ͘ϱ ϯ͘ϱ Ϭ͘ϲϴ Ϯϴϴϲ ϭ͘ϳϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϱϭ͘Ϭ ϭϰ͘ϱ Ϭ͘ϲϱ Ϯϳϲϴ ϭ͘ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϲϱ͘ϱ ϭ͘ϱ Ϭ͘ϲϰ Ϯϳϰϳ ϭ͘ϭϱ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϲϳ͘Ϭ ϭϮ͘ϱ Ϭ͘ϲϯ ϮϲϵϮ ϴ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϳϵ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϱ Ϯϳϳϴ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϴϭ͘ϱ ϵ͘Ϭ Ϭ͘ϲϬ Ϯϱϱϴ ϴ͘ϱϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϵϬ͘ϱ ϳ͘Ϭ Ϭ͘ϲϱ ϮϴϬϴ ϭ͘ϰϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϵϳ͘ϱ ϵ͘Ϭ Ϭ͘ϲϯ ϮϳϬϱ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϬϲ͘ϱ ϯ͘ϱ Ϭ͘ϲϯ ϮϳϮϬ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϭϬ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϲϱ ϳ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϭϱ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϵ Ϯϵϲϵ ϭ͘ϴϬ нϬϲ Ϭ͘ϮϱϬ ϭϱϬϬ EĂŶ^ ϰϯϭϳ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϬ ϮϲϬϳ ϳ͘ϯϲ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϮϳ͘ϱ ϯ͘ϱ Ϭ͘ϲϮ ϮϳϬϱ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϯϭ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϲϲϰ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϯϯϯ͘Ϭ ϱ͘ϱ Ϭ͘ϲϱ ϮϴϭϬ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϯϯϴ͘ϱ ϯ͘ϱ Ϭ͘ϲϵ Ϯϵϵϱ ϭ͘ϱϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϰϮ͘Ϭ ϯ͘ϱ Ϭ͘ϲϯ Ϯϳϰϭ ϭ͘ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϰϱ͘ϱ ϱ͘ϱ Ϭ͘ϲϳ ϮϵϮϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϱϭ͘Ϭ ϭϬ͘ϱ Ϭ͘ϲϮ Ϯϲϵϯ ϭ͘ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϲϭ͘ϱ ϭ͘ϱ Ϭ͘ϲϱ Ϯϴϱϯ ϭ͘ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϲϯ͘Ϭ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϳϭϭ ϭ͘ϭϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϲϴ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϲ ϮϴϲϮ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϳϬ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϮ ϮϳϮϴ ϴ͘ϵϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϳϰ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϲ Ϯϴϳϲ ϭ͘ϲϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϳϲ͘Ϭ ϭϬ͘Ϭ Ϭ͘ϲϯ Ϯϳϰϳ ϵ͘ϴϭ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϴϲ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϱ ϮϴϳϬ ϭ͘ϲϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϵϬ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϴ Ϯϵϳϰ ϭ͘ϳϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϵϰ͘Ϭ ϵ͘ϱ Ϭ͘ϲϯ Ϯϳϴϰ ϭ͘ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϬϯ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϬ Ϯϲϰϵ ϳ͘ϴϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϰϬϱ͘ϱ ϵ͘ϱ Ϭ͘ϲϳ Ϯϵϳϱ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϭϱ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϴϭϮ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϭϳ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϬϮ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϭϵ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϲϱ ϭ͘Ϭϵ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϮϭ͘Ϭ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϬϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϮϯ͘Ϭ ϰ͘Ϭ Ϭ͘ϲϰ Ϯϴϰϰ ϭ͘Ϯϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϮϳ͘Ϭ ϭϵ͘ϱ Ϭ͘ϲϴ ϯϬϭϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϰϲ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϯ ϮϴϮϬ ϭ͘ϯϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϰϴ͘ϱ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϱϬ͘ϱ ϴ͘Ϭ Ϭ͘ϲϰ Ϯϴϱϱ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϱϴ͘ϱ ϴ͘Ϭ Ϭ͘ϲϱ Ϯϴϴϯ ϭ͘ϱϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^ŚĂůĞ ϰϰϲϲ͘ϱ ϮϬ͘Ϭ Ϭ͘ϲϵ ϯϬϵϴ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Ratio ϭϵ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4179.7 10.0 0.001 1.0 1890 4189.7 15.0 0.001 1.0 1898 4204.7 15.3 0.005 10.0 1905 4220.0 19.5 30.655 23.7 1915 4239.5 2.0 5.000 10.0 1924 4241.5 1.5 2.095 16.9 1925 4243.0 4.5 48.388 26.6 1926 4247.5 3.5 0.478 12.4 1928 4251.0 14.5 15.008 17.7 1930 4265.5 1.5 3.661 17.6 1937 4267.0 12.5 34.723 23.9 1937 4279.5 2.0 1.697 15.6 1943 4281.5 9.0 54.319 24.4 1944 4290.5 7.0 3.610 14.8 1948 4297.5 9.0 22.986 20.4 1952 4306.5 3.5 0.835 14.0 1956 4310.0 5.0 65.392 23.4 1957 4315.0 2.0 0.006 10.5 1960 4317.0 10.5 100.832 25.6 1961 4327.5 3.5 17.434 20.5 1966 4331.0 2.0 161.343 26.3 1967 4333.0 5.5 4.627 18.4 1968 4338.5 3.5 5.075 14.8 1971 4342.0 3.5 8.651 19.4 1972 4345.5 5.5 10.205 16.0 1974 4351.0 10.5 17.356 20.1 1977 4361.5 1.5 3.106 14.8 1982 4363.0 5.0 52.863 20.6 1982 4368.0 2.0 2.277 14.1 1985 4370.0 4.0 122.778 23.1 1986 4374.0 2.0 0.333 12.5 1987 4376.0 10.0 39.939 21.2 1988 4386.0 4.0 0.748 13.3 1993 4390.0 4.0 0.009 10.9 1995 4394.0 9.5 5.399 16.7 1997 4403.5 2.0 160.618 24.9 2001 4405.5 9.5 0.033 11.5 2002 4415.0 2.0 6.733 16.2 2007 4417.0 2.0 0.001 1.0 2008 4419.0 2.0 29.480 19.6 2009 4421.0 2.0 0.001 1.0 2009 4423.0 4.0 8.473 16.6 2010 4427.0 19.5 0.001 1.0 2012 4446.5 2.0 2.185 16.4 2021 4448.5 2.0 0.001 1.0 2022 4450.5 8.0 2.645 15.9 2023 4458.5 8.0 2.026 14.4 2027 4466.5 20.0 0.001 10.0 2031 Formation Transmissibility Properties Zone Name Nan DS Shale Shale Nanushuk 3 SS Top Nan CS Nan SS Nan CS Nan CS Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan CS Nan CS Nan CS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Shale Nan DS Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Shale Nan DS Nan DS ϮϬ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 14: Propped Fracture Schedule (Stage 5; 15903 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF126ST 400.0 26 0 1.0 PPA 40 YF126ST 191.5 26 1 2.0 PPA 40 YF126ST 183.7 26 2 4.0 PPA 40 YF126ST 186.8 26 4 6.0 PPA 40 YF126ST 197.4 26 6 8.0 PPA 40 YF126ST 162.4 26 8 10.0 PPA 40 YF126ST 138.5 26 10 12.0 PPA 40 YF126ST 104.4 26 12 Flush 40 YF126ST 242.3 26 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1807 bbl of YF126ST 0 bbl of WF126 269963 lb of 0 lb of % PAD Clean 25.6 % PAD Dirty 21.6 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 400.0 400 400 400 0 0 4022 10.0 10.0 1.0 PPA 191.5 592 200 600 8043 8043 3972 5.0 15.0 2.0 PPA 183.7 775 200 800 15430 23473 3789 5.0 20.0 4.0 PPA 186.8 962 220 1020 31388 54861 3777 5.5 25.5 6.0 PPA 197.4 1159 250 1270 49752 104613 3954 6.3 31.8 8.0 PPA 162.4 1322 220 1490 54552 159165 4324 5.5 37.3 10.0 PPA 138.5 1460 200 1690 58180 217345 4700 5.0 42.3 12.0 PPA 104.4 1565 160 1850 52618 269963 5098 4.0 46.3 Flush 242.3 1807 242 2092 0 269963 5179 6.1 52.3 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 380.4 ft with an average conductivity (Kfw) of 14709.6 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Job Execution Step Name Ϯϭ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 15: Propped Fracture Simulation (Stage 5; 15903 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϭϴϰ͘ϴĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϰϯϴ͘ϴĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϴϬ͘ϰĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů ϮϱϰĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϳϮŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϰϮƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϱϱϰϮƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 95.1 11.1 0.212 141.8 1.83 217.2 18864 95.1 190.2 8.4 0.203 218.7 1.8 232.3 17610 190.2 285.3 6.1 0.177 205.8 1.58 251.2 14902 285.3 380.4 2.7 0.106 173 0.97 475 8403 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment ϮϮ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 16: Zone Data (Stage 6; 15317 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϮϬϬ͘ϵ ϭϬ͘Ϭ Ϭ͘ϳϬ Ϯϵϱϱ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϮϭϬ͘ϵ ϭϱ͘Ϭ Ϭ͘ϳϬ ϮϵϯϮ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŝůƚƐƚŽŶĞ ϰϮϮϱ͘ϵ ϭϱ͘ϯ Ϭ͘ϲϴ ϮϴϳϬ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ ϰϮϰϭ͘Ϯ ϭϳ͘ϱ Ϭ͘ϲϮ Ϯϲϰϴ ϴ͘ϭϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϱϴ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϬ Ϯϱϰϵ ϳ͘ϴϱ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϲϬ͘ϳ ϱ͘ϱ Ϭ͘ϲϯ Ϯϲϳϯ ϭ͘Ϯϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϮϲϲ͘Ϯ ϯ͘ϱ Ϭ͘ϲϴ ϮϵϬϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϮϲϵ͘ϳ ϭ͘ϱ Ϭ͘ϲϯ Ϯϲϳϲ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϮϳϭ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϭϯ ϵ͘ϭϰ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϮϳϯ͘Ϯ ϭ͘ϱ Ϭ͘ϲϭ ϮϲϬϱ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϮϳϰ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϰϭ ϭ͘Ϯϱ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϮϳϲ͘ϳ ϯ͘ϱ Ϭ͘ϲϬ ϮϱϲϬ ϳ͘ϳϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϴϬ͘Ϯ ϰ͘ϱ Ϭ͘ϲϭ ϮϲϬϱ ϴ͘ϳϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϴϰ͘ϳ ϳ͘Ϭ Ϭ͘ϲϱ Ϯϳϲϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϮϵϭ͘ϳ ϰ͘ϱ Ϭ͘ϲϭ Ϯϲϭϭ ϳ͘ϱϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϵϲ͘Ϯ ϱ͘Ϭ Ϭ͘ϲϭ ϮϲϮϳ ϵ͘ϵϴ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϬϭ͘Ϯ ϰ͘ϱ Ϭ͘ϲϰ Ϯϳϱϵ ϭ͘ϭϮ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϬϱ͘ϳ ϵ͘ϱ Ϭ͘ϲϬ Ϯϱϵϯ ϳ͘ϳϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϭϱ͘Ϯ Ϯ͘ϱ Ϭ͘ϲϰ Ϯϳϲϳ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϭϳ͘ϳ ϭϮ͘Ϭ Ϭ͘ϲϮ Ϯϲϴϱ ϵ͘ϲϱ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϮϵ͘ϳ Ϯ͘ϱ Ϭ͘ϲϱ ϮϴϬϭ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϯϮ͘Ϯ ϵ͘ϱ Ϭ͘ϲϮ ϮϳϬϲ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϰϭ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϲϱ ϭ͘ϰϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϰϯ͘ϳ ϰϭ͘Ϭ Ϭ͘ϲϯ ϮϳϮϵ ϭ͘ϬϮ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϴϰ͘ϳ ϭ͘ϱ Ϭ͘ϲϮ ϮϳϯϮ ϴ͘ϲϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϴϲ͘Ϯ ϲ͘Ϭ Ϭ͘ϲϭ Ϯϲϵϱ ϳ͘ϲϱ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϯϵϮ͘Ϯ ϲ͘Ϭ Ϭ͘ϲϲ Ϯϴϵϵ ϭ͘Ϯϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϵϴ͘Ϯ ϰ͘Ϭ Ϭ͘ϲϴ Ϯϵϵϭ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϬϮ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϴϭϴ ϭ͘Ϭϭ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϰϬϰ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϮϲ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϬϲ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϴϲ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϰϬϴ͘Ϯ ϱ͘ϱ Ϭ͘ϲϴ Ϯϵϵϰ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϭϯ͘ϳ ϰ͘Ϭ Ϭ͘ϲϮ ϮϳϮϬ ϵ͘ϱϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϰϭϳ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ Ϯϵϵϲ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϭϵ͘ϳ ϭϮ͘Ϭ Ϭ͘ϲϯ Ϯϳϴϰ ϵ͘ϮϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϰϯϭ͘ϳ ϰ͘Ϭ Ϭ͘ϲϵ ϯϬϯϳ ϭ͘ϰϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϯϱ͘ϳ ϰ͘Ϭ Ϭ͘ϲϯ ϮϴϭϬ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϯϵ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϮϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϰϭ͘ϳ ϭ͘ϱ Ϭ͘ϲϰ Ϯϴϰϵ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϰϯ͘Ϯ ϴ͘Ϭ Ϭ͘ϲϴ ϯϬϮϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϱϭ͘Ϯ ϴ͘Ϭ Ϭ͘ϲϮ ϮϳϳϮ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϰϱϵ͘Ϯ ϭ͘ϱ Ϭ͘ϲϯ ϮϳϵϮ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϲϬ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϯϴ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϲϮ͘ϳ ϰ͘Ϭ Ϭ͘ϲϰ Ϯϴϰϰ ϭ͘Ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϲϲ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϰϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϲϴ͘ϳ ϲ͘Ϭ Ϭ͘ϲϯ ϮϴϬϭ ϭ͘Ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^,> ϰϰϳϰ͘ϳ ϮϬ͘Ϭ Ϭ͘ϲϴ ϯϬϱϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name s Ratio Ϯϯ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4200.9 10.0 0.001 1.0 1913 4210.9 15.0 0.001 1.0 1918 4225.9 15.3 0.005 10.0 1925 4241.2 17.5 39.470 24.9 1932 4258.7 2.0 113.240 25.3 1940 4260.7 5.5 22.020 19.7 1941 4266.2 3.5 0.001 1.0 1944 4269.7 1.5 21.670 21.3 1945 4271.2 2.0 159.890 23.6 1946 4273.2 1.5 110.140 27.0 1947 4274.7 2.0 2.870 19.7 1948 4276.7 3.5 94.750 25.5 1949 4280.2 4.5 44.130 24.1 1950 4284.7 7.0 4.280 17.9 1952 4291.7 4.5 91.630 25.7 1956 4296.2 5.0 31.600 22.6 1958 4301.2 4.5 3.110 21.1 1960 4305.7 9.5 131.710 25.4 1962 4315.2 2.5 1.000 15.1 1967 4317.7 12.0 104.140 23.0 1968 4329.7 2.5 2.350 17.3 1974 4332.2 9.5 31.760 19.2 1975 4341.7 2.0 3.790 17.6 1979 4343.7 41.0 72.280 22.4 1980 4384.7 1.5 68.110 24.3 1999 4386.2 6.0 156.150 26.2 2000 4392.2 6.0 40.960 19.9 2003 4398.2 4.0 0.020 15.0 2006 4402.2 2.0 17.850 22.4 2008 4404.2 2.0 0.010 15.0 2009 4406.2 2.0 22.090 21.0 2010 4408.2 5.5 0.020 15.0 2011 4413.7 4.0 63.420 23.1 2013 4417.7 2.0 0.020 15.0 2015 4419.7 12.0 74.620 23.5 2016 4431.7 4.0 11.770 17.8 2022 4435.7 4.0 2.490 17.3 2023 4439.7 2.0 0.001 1.0 2025 4441.7 1.5 3.220 18.4 2026 4443.2 8.0 0.001 1.0 2027 4451.2 8.0 65.690 21.2 2031 4459.2 1.5 4.800 17.8 2035 4460.7 2.0 0.001 1.0 2035 4462.7 4.0 11.980 19.3 2036 4466.7 2.0 0.001 1.0 2038 4468.7 6.0 60.610 22.1 2039 4474.7 20.0 0.001 1.0 2042 Formation Transmissibility Properties Zone Name Nan CS Shale Shale Siltstone Top Nan CS Nan DS Nan DS SHALE Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan CS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS SHALE Nan DS SHALE Nan DS Nan DS SHALE Nan DS SHALE Nan DS SHALE Ϯϰ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 17: Propped Fracture Schedule (Stage 6; 15317 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF126ST 400.0 26 0 1.0 PPA 40 YF126ST 191.5 26 1 2.0 PPA 40 YF126ST 183.8 26 2 4.0 PPA 40 YF126ST 186.9 26 4 6.0 PPA 40 YF126ST 197.6 26 6 8.0 PPA 40 YF126ST 162.5 26 8 10.0 PPA 40 YF126ST 138.7 26 10 12.0 PPA 40 YF126ST 104.5 26 12 Flush 40 YF126ST 233.3 26 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1798.9 bbl of YF126ST 0 bbl of WF126 0 lb of 270211 lb of % PAD Clean 25.6 % PAD Dirty 21.6 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 400.0 400 400 400 0 0 3894 10.0 10.0 1.0 PPA 191.5 592 200 600 8044 8044 3823 5.0 15.0 2.0 PPA 183.8 775 200 800 15435 23479 3662 5.0 20.0 4.0 PPA 186.9 962 220 1020 31405 54885 3669 5.5 25.5 6.0 PPA 197.6 1160 250 1270 49791 104675 3822 6.3 31.8 8.0 PPA 162.5 1322 220 1490 54605 159280 4170 5.5 37.3 10.0 PPA 138.7 1461 200 1690 58246 217526 4524 5.0 42.3 12.0 PPA 104.5 1566 160 1850 52685 270211 4962 4.0 46.3 Flush 233.3 1799 233 2083 0 270211 4986 5.8 52.1 Carbolite 16/20 NRT The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 402.4 ft with an average conductivity (Kfw) of 15074.7 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 16/20 NRT Carbolite 16/20 NRT Carbolite 16/20 NRT Carbolite 16/20 NRT Pad Percentages Carbolite 16/20 NRT Carbolite 16/20 NRT Fluid Totals Proppant Totals Carbolite 40/70 Carbolite 16/20 NRT Job Execution Step Name Ϯϱ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 18: Propped Fracture Simulation (Stage 6; 15317 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϮϬϱ͘ϳĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϰϳϴ͘ϴĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϰϬϮ͘ϰĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů ϮϳϯĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϱϲŝŶ EĞƚWƌĞƐƐƵƌĞ ϭϰϴƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϱϯϯϲƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 100.6 11.7 0.199 152.7 1.72 208.7 19577 100.6 201.2 7.8 0.187 214.7 1.65 231 18183 201.2 301.8 4.9 0.169 200.4 1.48 251.7 16240 301.8 402.4 21.8 0.078 127.1 0.72 480.8 7523 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment Ϯϲ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 19: Zone Data (Stage 7; 14733 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϮϭϲ͘ϵ ϭϬ͘Ϭ Ϭ͘ϳϬ Ϯϵϱϱ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϮϮϲ͘ϵ ϭϱ͘Ϭ Ϭ͘ϳϬ Ϯϵϰϯ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŝůƚƐƚŽŶĞ ϰϮϰϭ͘ϵ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϴϴϭ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ ϰϮϱϳ͘Ϯ ϭϳ͘ϱ Ϭ͘ϲϮ Ϯϲϰϴ ϴ͘ϭϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϳϰ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϬ Ϯϱϰϵ ϳ͘ϴϱ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϳϲ͘ϳ ϱ͘ϱ Ϭ͘ϲϯ Ϯϲϴϯ ϭ͘Ϯϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϮϴϮ͘Ϯ ϯ͘ϱ Ϭ͘ϲϴ ϮϵϬϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϮϴϱ͘ϳ ϭ͘ϱ Ϭ͘ϲϮ Ϯϲϳϲ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϮϴϳ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϳϮϯ ϵ͘ϭϰ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϮϴϵ͘Ϯ ϭ͘ϱ Ϭ͘ϲϭ ϮϲϬϱ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϮϵϬ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϱϭ ϭ͘Ϯϱ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϮϵϮ͘ϳ ϯ͘ϱ Ϭ͘ϲϬ ϮϱϲϬ ϳ͘ϳϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϵϲ͘Ϯ ϰ͘ϱ Ϭ͘ϲϭ ϮϲϬϱ ϴ͘ϳϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϬϬ͘ϳ ϳ͘Ϭ Ϭ͘ϲϰ Ϯϳϲϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϬϳ͘ϳ ϰ͘ϱ Ϭ͘ϲϭ Ϯϲϭϭ ϳ͘ϱϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϭϮ͘Ϯ ϱ͘Ϭ Ϭ͘ϲϭ ϮϲϮϳ ϵ͘ϵϴ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϭϳ͘Ϯ ϰ͘ϱ Ϭ͘ϲϰ Ϯϳϲϵ ϭ͘ϭϮ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϮϭ͘ϳ ϵ͘ϱ Ϭ͘ϲϬ Ϯϱϵϯ ϳ͘ϳϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϯϭ͘Ϯ Ϯ͘ϱ Ϭ͘ϲϰ Ϯϳϲϳ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϯϯ͘ϳ ϭϮ͘Ϭ Ϭ͘ϲϮ Ϯϲϴϱ ϵ͘ϲϱ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϰϱ͘ϳ Ϯ͘ϱ Ϭ͘ϲϰ ϮϴϬϭ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϰϴ͘Ϯ ϵ͘ϱ Ϭ͘ϲϮ Ϯϳϭϲ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϱϳ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϲϱ ϭ͘ϰϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϱϵ͘ϳ ϰϭ͘Ϭ Ϭ͘ϲϮ ϮϳϮϵ ϭ͘ϬϮ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϰϬϬ͘ϳ ϭ͘ϱ Ϭ͘ϲϮ ϮϳϯϮ ϴ͘ϲϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϰϬϮ͘Ϯ ϲ͘Ϭ Ϭ͘ϲϭ Ϯϲϵϱ ϳ͘ϲϱ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϰϬϴ͘Ϯ ϲ͘Ϭ Ϭ͘ϲϲ Ϯϴϵϵ ϭ͘Ϯϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϭϰ͘Ϯ ϰ͘Ϭ Ϭ͘ϲϴ Ϯϵϵϭ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϭϴ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϰ ϮϴϮϴ ϭ͘Ϭϭ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϰϮϬ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϯϳ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϮϮ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϴϲ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϰϮϰ͘Ϯ ϱ͘ϱ Ϭ͘ϲϴ Ϯϵϵϰ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϮϵ͘ϳ ϰ͘Ϭ Ϭ͘ϲϭ ϮϳϮϬ ϵ͘ϱϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϰϯϯ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϬϳ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϯϱ͘ϳ ϭϮ͘Ϭ Ϭ͘ϲϯ Ϯϳϵϰ ϵ͘ϮϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϰϰϳ͘ϳ ϰ͘Ϭ Ϭ͘ϲϵ ϯϬϰϴ ϭ͘ϰϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϱϭ͘ϳ ϰ͘Ϭ Ϭ͘ϲϯ ϮϴϭϬ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϱϱ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϯϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϱϳ͘ϳ ϭ͘ϱ Ϭ͘ϲϰ Ϯϴϰϵ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϱϵ͘Ϯ ϴ͘Ϭ Ϭ͘ϲϴ ϯϬϯϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϲϳ͘Ϯ ϴ͘Ϭ Ϭ͘ϲϮ ϮϳϳϮ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϰϳϱ͘Ϯ ϭ͘ϱ Ϭ͘ϲϮ ϮϳϵϮ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϳϲ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϰϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϳϴ͘ϳ ϰ͘Ϭ Ϭ͘ϲϰ Ϯϴϱϰ ϭ͘Ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϴϮ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϱϯ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϴϰ͘ϳ ϲ͘Ϭ Ϭ͘ϲϮ ϮϴϬϭ ϭ͘Ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^,> ϰϰϵϬ͘ϳ ϮϬ͘Ϭ Ϭ͘ϲϴ ϯϬϱϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Ratio Ϯϳ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4216.9 10.0 0.001 1.0 1913 4226.9 15.0 0.001 1.0 1918 4241.9 15.3 0.005 10.0 1925 4257.2 17.5 39.470 24.9 1932 4274.7 2.0 113.240 25.3 1940 4276.7 5.5 22.020 19.7 1941 4282.2 3.5 0.001 1.0 1944 4285.7 1.5 21.670 21.3 1945 4287.2 2.0 159.890 23.6 1946 4289.2 1.5 110.140 27.0 1947 4290.7 2.0 2.870 19.7 1948 4292.7 3.5 94.750 25.5 1949 4296.2 4.5 44.130 24.1 1950 4300.7 7.0 4.280 17.9 1952 4307.7 4.5 91.630 25.7 1956 4312.2 5.0 31.600 22.6 1958 4317.2 4.5 3.110 21.1 1960 4321.7 9.5 131.710 25.4 1962 4331.2 2.5 1.000 15.1 1967 4333.7 12.0 104.140 23.0 1968 4345.7 2.5 2.350 17.3 1974 4348.2 9.5 31.760 19.2 1975 4357.7 2.0 3.790 17.6 1979 4359.7 41.0 72.280 22.4 1980 4400.7 1.5 68.110 24.3 1999 4402.2 6.0 156.150 26.2 2000 4408.2 6.0 40.960 19.9 2003 4414.2 4.0 0.020 15.0 2006 4418.2 2.0 17.850 22.4 2008 4420.2 2.0 0.010 15.0 2009 4422.2 2.0 22.090 21.0 2010 4424.2 5.5 0.020 15.0 2011 4429.7 4.0 63.420 23.1 2013 4433.7 2.0 0.020 15.0 2015 4435.7 12.0 74.620 23.5 2016 4447.7 4.0 11.770 17.8 2022 4451.7 4.0 2.490 17.3 2023 4455.7 2.0 0.001 1.0 2025 4457.7 1.5 3.220 18.4 2026 4459.2 8.0 0.001 1.0 2027 4467.2 8.0 65.690 21.2 2031 4475.2 1.5 4.800 17.8 2035 4476.7 2.0 0.001 1.0 2035 4478.7 4.0 11.980 19.3 2036 4482.7 2.0 0.001 1.0 2038 4484.7 6.0 60.610 22.1 2039 4490.7 20.0 0.001 1.0 2042 Formation Transmissibility Properties Zone Name Nan CS Shale Shale Siltstone Top Nan CS Nan DS Nan DS SHALE Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan CS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS SHALE Nan DS SHALE Nan DS Nan DS SHALE Nan DS SHALE Nan DS SHALE Ϯϴ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 20: Propped Fracture Schedule (Stage 7; 14733 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF126ST 250.0 26 0 1.0 PPA 40 YF126ST 57.5 26 1 3.0 PPA 40 YF126ST 105.9 26 3 Resume PAD 40 YF126ST 50.0 26 0 1.0 PPA 40 YF126ST 186.7 26 1 3.0 PPA 40 YF126ST 194.2 26 3 5.0 PPA 40 YF126ST 204.6 26 5 7.0 PPA 40 YF126ST 190.7 26 7 9.0 PPA 40 YF126ST 160.8 26 9 11.0 PPA 40 YF126ST 127.7 26 11 Flush 40 YF126ST 224.4 26 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1752.4 bbl of YF126ST 0 bbl of WF126 251109 lb of 15756 lb of % PAD Clean 16.4 % PAD Dirty 13.8 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 250.0 250 250 250 0 0 3791 6.3 6.3 1.0 PPA 57.5 307 60 310 2413 2413 3771 1.5 7.7 3.0 PPA 105.9 413 120 430 13343 15756 3709 3.0 10.7 Resume PAD 50.0 463 50 480 0 15756 3609 1.3 12.0 1.0 PPA 186.7 650 195 675 7842 23598 3635 4.9 16.9 3.0 PPA 194.2 844 220 895 24463 48061 3572 5.5 22.4 5.0 PPA 204.6 1049 250 1145 42966 91027 3630 6.3 28.6 7.0 PPA 190.7 1240 250 1395 56079 147106 3882 6.3 34.9 9.0 PPA 160.8 1400 225 1620 60775 207881 4240 5.6 40.5 11.0 PPA 127.7 1528 190 1810 58985 266865 4649 4.8 45.2 Flush 224.4 1752 224 2034 0 266865 4656 5.6 50.9 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 333 ft with an average conductivity (Kfw) of 16837.7 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Job Execution Step Name Ϯϵ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 21: Propped Fracture Simulation (Stage 7; 14733 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϮϮϱ͘ϱĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϰϲϲ͘ϴĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϯϯĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϰϭ͘ϯĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϵϰŝŶ EĞƚWƌĞƐƐƵƌĞ ϭϲϵƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϰϵϱϰƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 83.2 10.4 0.244 205.8 2.07 206.8 22227 83.2 166.5 8.1 0.242 205.8 2.13 220.8 21317 166.5 249.7 5.8 0.202 205.8 1.78 258.4 17537 249.7 333 1.7 0.098 170 0.91 421.5 7915 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment ϯϬ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 22: Zone Data (Stage 8; 14148 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϮϯϵ͘ϵ ϭϬ͘Ϭ Ϭ͘ϳϬ Ϯϵϱϱ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŚĂůĞ ϰϮϰϵ͘ϵ ϭϱ͘Ϭ Ϭ͘ϳϬ Ϯϵϱϵ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^ŝůƚƐƚŽŶĞ ϰϮϲϰ͘ϵ ϭϱ͘ϯ Ϭ͘ϲϴ Ϯϴϵϳ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ ϰϮϴϬ͘Ϯ ϭϳ͘ϱ Ϭ͘ϲϮ Ϯϲϰϴ ϴ͘ϭϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϵϳ͘ϳ Ϯ͘Ϭ Ϭ͘ϱϵ Ϯϱϰϵ ϳ͘ϴϱ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϮϵϵ͘ϳ ϱ͘ϱ Ϭ͘ϲϯ Ϯϲϵϴ ϭ͘Ϯϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϯϬϱ͘Ϯ ϯ͘ϱ Ϭ͘ϲϴ ϮϵϬϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϯϬϴ͘ϳ ϭ͘ϱ Ϭ͘ϲϮ Ϯϲϳϲ ϭ͘ϭϬ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϭϬ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϯϴ ϵ͘ϭϰ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϭϮ͘Ϯ ϭ͘ϱ Ϭ͘ϲϬ ϮϲϬϱ ϲ͘ϳϬ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϯϭϯ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϲϲ ϭ͘Ϯϱ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ EĂŶ^ ϰϯϭϱ͘ϳ ϯ͘ϱ Ϭ͘ϱϵ ϮϱϲϬ ϳ͘ϳϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϭϵ͘Ϯ ϰ͘ϱ Ϭ͘ϲϬ ϮϲϬϱ ϴ͘ϳϰ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϮϯ͘ϳ ϳ͘Ϭ Ϭ͘ϲϰ Ϯϳϲϴ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϯϬ͘ϳ ϰ͘ϱ Ϭ͘ϲϬ Ϯϲϭϭ ϳ͘ϱϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϯϱ͘Ϯ ϱ͘Ϭ Ϭ͘ϲϭ ϮϲϮϳ ϵ͘ϵϴ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϰϬ͘Ϯ ϰ͘ϱ Ϭ͘ϲϰ Ϯϳϴϰ ϭ͘ϭϮ нϬϲ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϰϰ͘ϳ ϵ͘ϱ Ϭ͘ϲϬ Ϯϱϵϯ ϳ͘ϳϴ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϯϱϰ͘Ϯ Ϯ͘ϱ Ϭ͘ϲϰ Ϯϳϲϳ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϱϲ͘ϳ ϭϮ͘Ϭ Ϭ͘ϲϮ Ϯϲϴϱ ϵ͘ϲϱ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϯϲϴ͘ϳ Ϯ͘ϱ Ϭ͘ϲϰ ϮϴϬϭ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϳϭ͘Ϯ ϵ͘ϱ Ϭ͘ϲϮ Ϯϳϯϭ ϭ͘ϯϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϴϬ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϲϱ ϭ͘ϰϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϯϴϮ͘ϳ ϰϭ͘Ϭ Ϭ͘ϲϮ ϮϳϮϵ ϭ͘ϬϮ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϰϮϯ͘ϳ ϭ͘ϱ Ϭ͘ϲϮ ϮϳϯϮ ϴ͘ϲϮ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϰϮϱ͘Ϯ ϲ͘Ϭ Ϭ͘ϲϭ Ϯϲϵϱ ϳ͘ϲϱ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ EĂŶ^ ϰϰϯϭ͘Ϯ ϲ͘Ϭ Ϭ͘ϲϱ Ϯϴϵϵ ϭ͘Ϯϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϯϳ͘Ϯ ϰ͘Ϭ Ϭ͘ϲϳ Ϯϵϵϭ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϰϭ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϴϰϯ ϭ͘Ϭϭ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϰϰϯ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϱϯ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϰϱ͘Ϯ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϴϲ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϰϰϳ͘Ϯ ϱ͘ϱ Ϭ͘ϲϳ Ϯϵϵϰ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϱϮ͘ϳ ϰ͘Ϭ Ϭ͘ϲϭ ϮϳϮϬ ϵ͘ϱϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϰϱϲ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϮϮ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϱϴ͘ϳ ϭϮ͘Ϭ Ϭ͘ϲϯ ϮϴϬϴ ϵ͘ϮϬ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ EĂŶ^ ϰϰϳϬ͘ϳ ϰ͘Ϭ Ϭ͘ϲϵ ϯϬϲϰ ϭ͘ϰϯ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ EĂŶ^ ϰϰϳϰ͘ϳ ϰ͘Ϭ Ϭ͘ϲϯ ϮϴϭϬ ϭ͘ϰϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϳϴ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϱϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϴϬ͘ϳ ϭ͘ϱ Ϭ͘ϲϰ Ϯϴϰϵ ϭ͘ϯϳ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϴϮ͘Ϯ ϴ͘Ϭ Ϭ͘ϲϴ ϯϬϱϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϰϵϬ͘Ϯ ϴ͘Ϭ Ϭ͘ϲϮ ϮϳϳϮ ϭ͘ϭϯ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ EĂŶ^ ϰϰϵϴ͘Ϯ ϭ͘ϱ Ϭ͘ϲϮ ϮϳϵϮ ϭ͘ϰϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϵϵ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϲϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϱϬϭ͘ϳ ϰ͘Ϭ Ϭ͘ϲϰ Ϯϴϲϵ ϭ͘Ϯϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϱϬϱ͘ϳ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϲϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ EĂŶ^ ϰϱϬϳ͘ϳ ϲ͘Ϭ Ϭ͘ϲϮ ϮϴϬϭ ϭ͘Ϭϳ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^,> ϰϱϭϯ͘ϳ ϮϬ͘Ϭ Ϭ͘ϲϴ ϯϬϱϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Ratio ϯϭ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4239.9 10.0 0.001 1.0 1913 4249.9 15.0 0.001 1.0 1918 4264.9 15.3 0.005 10.0 1925 4280.2 17.5 39.470 24.9 1932 4297.7 2.0 113.240 25.3 1940 4299.7 5.5 22.020 19.7 1941 4305.2 3.5 0.001 1.0 1944 4308.7 1.5 21.670 21.3 1945 4310.2 2.0 159.890 23.6 1946 4312.2 1.5 110.140 27.0 1947 4313.7 2.0 2.870 19.7 1948 4315.7 3.5 94.750 25.5 1949 4319.2 4.5 44.130 24.1 1950 4323.7 7.0 4.280 17.9 1952 4330.7 4.5 91.630 25.7 1956 4335.2 5.0 31.600 22.6 1958 4340.2 4.5 3.110 21.1 1960 4344.7 9.5 131.710 25.4 1962 4354.2 2.5 1.000 15.1 1967 4356.7 12.0 104.140 23.0 1968 4368.7 2.5 2.350 17.3 1974 4371.2 9.5 31.760 19.2 1975 4380.7 2.0 3.790 17.6 1979 4382.7 41.0 72.280 22.4 1980 4423.7 1.5 68.110 24.3 1999 4425.2 6.0 156.150 26.2 2000 4431.2 6.0 40.960 19.9 2003 4437.2 4.0 0.020 15.0 2006 4441.2 2.0 17.850 22.4 2008 4443.2 2.0 0.010 15.0 2009 4445.2 2.0 22.090 21.0 2010 4447.2 5.5 0.020 15.0 2011 4452.7 4.0 63.420 23.1 2013 4456.7 2.0 0.020 15.0 2015 4458.7 12.0 74.620 23.5 2016 4470.7 4.0 11.770 17.8 2022 4474.7 4.0 2.490 17.3 2023 4478.7 2.0 0.001 1.0 2025 4480.7 1.5 3.220 18.4 2026 4482.2 8.0 0.001 1.0 2027 4490.2 8.0 65.690 21.2 2031 4498.2 1.5 4.800 17.8 2035 4499.7 2.0 0.001 1.0 2035 4501.7 4.0 11.980 19.3 2036 4505.7 2.0 0.001 1.0 2038 4507.7 6.0 60.610 22.1 2039 4513.7 20.0 0.001 1.0 2042 Formation Transmissibility Properties Zone Name Nan CS Shale Shale Siltstone Top Nan CS Nan DS Nan DS SHALE Nan DS Nan DS Nan CS Nan CS Nan DS Nan CS Nan DS Nan DS Nan DS Nan CS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan CS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS Nan DS SHALE Nan DS SHALE Nan DS Nan DS SHALE Nan DS SHALE Nan DS SHALE ϯϮ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 23: Propped Fracture Schedule (Stage 8; 14148 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF126ST 250.0 26 0 1.0 PPA 40 YF126ST 57.5 26 1 3.0 PPA 40 YF126ST 105.9 26 3 Resume PAD 40 YF126ST 50.0 26 0 1.0 PPA 40 YF126ST 186.7 26 1 3.0 PPA 40 YF126ST 194.2 26 3 5.0 PPA 40 YF126ST 204.6 26 5 7.0 PPA 40 YF126ST 190.7 26 7 9.0 PPA 40 YF126ST 160.8 26 9 11.0 PPA 40 YF126ST 127.7 26 11 Flush 40 YF126ST 215.5 26 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1743.6 bbl of YF126ST 0 bbl of WF126 251109 lb of 15763 lb of % PAD Clean 16.4 % PAD Dirty 13.8 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 250.0 250 250 250 0 0 3689 6.3 6.3 1.0 PPA 57.5 307 60 310 2413 2413 3676 1.5 7.8 3.0 PPA 105.9 413 120 430 13349 15763 3596 3.0 10.8 Resume PAD 50.0 463 50 480 0 15763 3492 1.3 12.0 1.0 PPA 186.7 650 195 675 7842 23604 3532 4.9 16.9 3.0 PPA 194.2 844 220 895 24463 48067 3463 5.5 22.4 5.0 PPA 204.6 1049 250 1145 42966 91033 3528 6.3 28.6 7.0 PPA 190.7 1240 250 1395 56079 147112 3748 6.3 34.9 9.0 PPA 160.8 1400 225 1620 60775 207887 4090 5.6 40.5 11.0 PPA 127.7 1528 190 1810 58985 266872 4481 4.8 45.3 Flush 215.5 1744 216 2026 0 266872 4507 5.4 50.6 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 315.7 ft with an average conductivity (Kfw) of 24341.8 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Job Execution Step Name ϯϯ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 24: Propped Fracture Simulation (Stage 8; 14148 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϮϱϳĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϰϴϯĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϯϴϵ͘ϭĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů ϮϮϱ͘ϵĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϵϱŝŶ EĞƚWƌĞƐƐƵƌĞ ϯϰϭƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϰϳϳϴƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 97.3 10 0.26 129.5 2.26 204.2 23392 97.3 194.6 7.7 0.245 202.9 2.19 221.8 21097 194.6 291.8 5.5 0.199 169.1 1.83 277.7 17152 291.8 389.1 1.4 0.092 126.2 0.86 487.7 6904 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment ϯϰ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 25: Zone Data (Stage 9; 13647 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϮϭϮ͘ϴ ϰϭ͘ϳ Ϭ͘ϳϬ Ϯϵϲϱ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^,> ϰϮϱϰ͘ϱ ϭϱ͘Ϭ Ϭ͘ϳϬ ϮϵϲϮ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^/>d^dKE ϰϮϲϵ͘ϱ Ϯϰ͘ϭ Ϭ͘ϲϴ ϮϵϬϯ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ ϰϮϵϯ͘ϲ ϳ͘Ϭ Ϭ͘ϲϮ Ϯϲϱϰ Ϯ͘ϯϳ нϬϲ Ϭ͘ϮϰϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϯϬϬ͘ϲ ϭ͘ϱ Ϭ͘ϲϳ ϮϴϴϬ ϭ͘ϱϬ нϬϲ Ϭ͘ϮϰϬ ϭϬϬϬ ^,> ϰϯϬϮ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϴ Ϯϵϭϳ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ > EͲ^E^dKE ϰϯϬϰ͘ϭ ϭϬ͘ϱ Ϭ͘ϲϭ ϮϲϮϮ ϲ͘ϴϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϯϭϰ͘ϲ ϲ͘ϱ Ϭ͘ϲϯ Ϯϳϭϭ ϭ͘ϬϮ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϮϭ͘ϭ ϱ͘ϱ Ϭ͘ϲϯ Ϯϳϯϵ ϭ͘ϱϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϮϲ͘ϲ ϱ͘Ϭ Ϭ͘ϲϮ ϮϲϲϮ ϭ͘Ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϯϯϭ͘ϲ ϭ͘ϱ Ϭ͘ϲϰ Ϯϳϳϳ ϭ͘ϰϭ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϯϯ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϰ Ϯϳϲϳ ϭ͘ϳϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϯϱ͘ϭ ϭ͘ϱ Ϭ͘ϱϵ Ϯϱϳϲ ϱ͘ϳϳ нϬϱ Ϭ͘ϮϴϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϯϲ͘ϲ ϭϭ͘ϱ Ϭ͘ϲϰ Ϯϳϲϳ ϭ͘ϯϭ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϰϴ͘ϭ ϭ͘ϴ Ϭ͘ϲϲ Ϯϴϳϴ ϭ͘Ϯϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϰϵ͘ϵ Ϯ͘ϭ Ϭ͘ϲϳ ϮϵϮϵ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϱϮ͘Ϭ ϴ͘Ϯ Ϭ͘ϲϮ Ϯϲϴϴ ϵ͘ϲϱ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϯϲϬ͘Ϯ ϰ͘ϵ Ϭ͘ϲϰ Ϯϳϳϱ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϲϱ͘ϭ ϭ͘ϱ Ϭ͘ϲϲ ϮϴϵϬ ϭ͘ϲϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϲϲ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϯ ϮϳϯϮ ϭ͘ϱϭ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϯϲϴ͘ϲ ϯ͘ϱ Ϭ͘ϲϵ ϯϬϭϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϯϳϮ͘ϭ ϭ͘ϱ Ϭ͘ϲϰ Ϯϴϭϰ ϭ͘ϲϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϯϳϯ͘ϲ ϭ͘ϱ Ϭ͘ϲϴ Ϯϵϲϲ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϯϳϱ͘ϭ ϯ͘ϱ Ϭ͘ϲϮ Ϯϳϭϳ ϭ͘ϰϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϯϳϴ͘ϲ ϱ͘Ϭ Ϭ͘ϲϴ Ϯϵϳϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϯϴϯ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϭ Ϯϲϵϲ ϭ͘ϭϮ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^,> ϰϯϴϱ͘ϲ ϱ͘Ϭ Ϭ͘ϲϴ Ϯϵϳϲ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ ^,> ϰϯϵϬ͘ϲ ϯ͘ϱ Ϭ͘ϲϴ Ϯϵϳϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϯϵϰ͘ϭ ϭ͘ϱ Ϭ͘ϲϰ Ϯϴϭϵ ϭ͘ϯϭ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϯϵϱ͘ϲ ϭϭ͘Ϭ Ϭ͘ϲϴ Ϯϵϴϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϰϬϲ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϳϯϳ ϴ͘ϯϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ ^,> ϰϰϬϴ͘ϲ ϭ͘ϱ Ϭ͘ϲϴ ϮϵϵϬ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϰϭϬ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϲϭ ϵ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϰϭϮ͘ϭ ϰ͘Ϭ Ϭ͘ϲϴ Ϯϵϴϰ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϭϲ͘ϭ ϱ͘ϱ Ϭ͘ϲϯ Ϯϳϲϵ ϭ͘ϮϬ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϮϭ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϮ ϮϳϮϴ ϵ͘ϯϯ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϰϮϯ͘ϲ ϲ͘Ϭ Ϭ͘ϲϴ ϮϵϵϮ ϭ͘ϳϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϮϵ͘ϲ Ϯϭ͘ϱ Ϭ͘ϲϯ Ϯϳϴϳ ϭ͘Ϭϴ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϱϭ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϱϵ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϱϯ͘ϭ ϰ͘Ϭ Ϭ͘ϲϰ ϮϴϰϮ ϭ͘ϭϲ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϱϳ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϬ ϮϲϲϬ ϴ͘ϳϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ ^,> ϰϰϱϵ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϮϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϰϲϭ͘ϭ ϰ͘Ϭ Ϭ͘ϲϯ ϮϴϮϴ ϭ͘ϱϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϲϱ͘ϭ ϰ͘Ϭ Ϭ͘ϲϮ Ϯϳϲϴ ϭ͘ϭϮ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϲϵ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϮϭ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϳϭ͘ϭ ϳ͘ϱ Ϭ͘ϲϯ ϮϴϮϰ ϭ͘ϭϴ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^,> ϰϰϳϴ͘ϲ ϵ͘ϱ Ϭ͘ϲϴ ϯϬϰϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϰϴϴ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϲϲ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϵϬ͘ϭ ϱϬ͘Ϭ Ϭ͘ϲϴ ϯϬϴϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name s Ratio ϯϱ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4212.8 41.7 0.010 1.0 1918 4254.5 15.0 0.010 1.0 1923 4269.5 24.1 0.050 10.0 1929 4293.6 7.0 6.009 4.1 1940 4300.6 1.5 0.192 12.0 1944 4302.1 2.0 0.010 1.0 1944 4304.1 10.5 100.314 26.7 1945 4314.6 6.5 21.598 22.3 1950 4321.1 5.5 1.009 16.6 1953 4326.6 5.0 3.544 19.9 1956 4331.6 1.5 5.023 17.9 1958 4333.1 2.0 0.319 14.9 1959 4335.1 1.5 236.504 28.4 1960 4336.6 11.5 21.887 19.1 1960 4348.1 1.8 50.818 20.1 1966 4349.9 2.1 0.026 15.0 1968 4352.0 8.2 62.684 23.0 1970 4360.2 4.9 4.489 17.4 1970 4365.1 1.5 0.488 15.1 1974 4366.6 2.0 1.982 16.9 1974 4368.6 3.5 0.010 1.0 1975 4372.1 1.5 0.552 15.4 1977 4373.6 1.5 0.010 1.0 1978 4375.1 3.5 3.859 17.2 1978 4378.6 5.0 0.010 1.0 1980 4383.6 2.0 41.288 21.2 1982 4385.6 5.0 0.010 1.0 1983 4390.6 3.5 0.010 1.0 1986 4394.1 1.5 5.111 19.0 1987 4395.6 11.0 0.010 1.0 1988 4406.6 2.0 111.829 24.6 1993 4408.6 1.5 0.010 1.0 1994 4410.1 2.0 102.765 23.1 1995 4412.1 4.0 0.016 15.0 1996 4416.1 5.5 24.191 20.3 1997 4421.6 2.0 33.759 23.4 2000 4423.6 6.0 0.015 14.5 2001 4429.6 21.5 82.778 21.8 2004 4451.1 2.0 0.014 15.0 2014 4453.1 4.0 26.711 20.7 2015 4457.1 2.0 162.436 24.1 2017 4459.1 2.0 0.010 1.0 2018 4461.1 4.0 1.983 16.8 2019 4465.1 4.0 30.725 21.1 2020 4469.1 2.0 0.009 15.0 2022 4471.1 7.5 8.533 20.5 2023 4478.6 9.5 0.010 1.0 2027 4488.1 2.0 15.000 10.0 2096 4490.1 50.0 0.010 1.0 2113 Formation Transmissibility Properties Zone Name DIRTY-SANDSTONE Shale SHALE SILTSTONE Top Nan CS DIRTY-SANDSTONE SHALE CLEAN-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE SHALE ϯϲ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 26: Propped Fracture Schedule (Stage 9; 13647 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF126ST 250.0 26 0 1.0 PPA Scour 40 YF126ST 57.5 26 1 3.0 PPA Scour 40 YF126ST 105.9 26 3 Resume PAD 40 YF126ST 50.0 26 0 1.0 PPA 40 YF126ST 191.5 26 1 2.0 PPA 40 YF126ST 211.3 26 2 4.0 PPA 40 YF126ST 237.9 26 4 6.0 PPA 40 YF126ST 209.4 26 6 8.0 PPA 40 YF126ST 181.0 26 8 10.0 PPA 40 YF126ST 145.6 26 10 Flush 40 YF126ST 207.9 26 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1848.1 bbl of YF126ST 0 bbl of WF126 15762 lb of 240511 lb of % PAD Clean 15.2 % PAD Dirty 13.1 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 250.0 250 250 250 0 0 3711 6.3 6.3 1.0 PPA Scour 57.5 307 60 310 2413 2413 3709 1.5 7.7 3.0 PPA Scour 105.9 413 120 430 13349 15762 3652 3.0 10.7 Resume PAD 50.0 463 50 480 0 15762 3550 1.3 12.0 1.0 PPA 191.5 655 200 680 8044 23806 3561 5.0 17.0 2.0 PPA 211.3 866 230 910 17750 41557 3491 5.8 22.7 4.0 PPA 237.9 1104 280 1190 39971 81527 3481 7.0 29.7 6.0 PPA 209.4 1314 265 1455 52778 134305 3620 6.6 36.4 8.0 PPA 181.0 1495 245 1700 60810 195115 3904 6.1 42.5 10.0 PPA 145.6 1640 210 1910 61158 256273 4218 5.3 47.7 Flush 207.9 1848 208 2118 0 256273 4249 5.2 52.9 Carbolite 16/20 NRT The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 457.2 ft with an average conductivity (Kfw) of 11425 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 NRT Pad Percentages Carbolite 16/20 NRT Carbolite 16/20 NRT Carbolite 16/20 NRT Carbolite 16/20 NRT Fluid Totals Proppant Totals Carbolite 40/70 Carbolite 16/20 NRT Job Execution Step Name ϯϳ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 27: Propped Fracture Simulation (Stage 9; 13647 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϮϮϯ͘ϮĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϱϭϴ͘ϴĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϰϱϳ͘ϮĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů Ϯϵϱ͘ϱĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϭϵŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϰϰƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϰϰϴϰƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 114.3 8.7 0.157 206.7 1.3 222 15547 114.3 228.6 5.6 0.144 206.7 1.24 251.7 13994 228.6 342.9 3.7 0.122 206.8 1.06 300 11834 342.9 457.2 1.1 0.06 160.4 0.51 412.6 5428 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment ϯϴ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 28: Zone Data (Stage 10; 13026 ft MD) Top TVD Zone Height Frac Grad. Insitu Stress Modulus Toughness (ft) (ft) (psi/ft) (psi) (psi) (psi.in 0.5) ^ŚĂůĞ ϰϮϯϵ͘ϴ ϰϭ͘ϳ Ϭ͘ϳϬ Ϯϵϲϱ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^,> ϰϮϴϭ͘ϱ ϭϱ͘Ϭ Ϭ͘ϳϬ Ϯϵϴϭ ϭ͘ϳϲ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ ^/>d^dKE ϰϮϵϲ͘ϱ Ϯϰ͘ϭ Ϭ͘ϲϴ ϮϵϮϭ ϭ͘ϵϬ нϬϲ Ϭ͘ϮϮϬ ϭϬϬϬ dŽƉEĂŶ^ ϰϯϮϬ͘ϲ ϳ͘Ϭ Ϭ͘ϲϭ Ϯϲϱϰ Ϯ͘ϯϳ нϬϲ Ϭ͘ϮϰϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϯϮϳ͘ϲ ϭ͘ϱ Ϭ͘ϲϳ ϮϴϴϬ ϭ͘ϱϬ нϬϲ Ϭ͘ϮϰϬ ϭϬϬϬ ^,> ϰϯϮϵ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϳ Ϯϵϭϳ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ > EͲ^E^dKE ϰϯϯϭ͘ϭ ϭϬ͘ϱ Ϭ͘ϲϬ ϮϲϮϮ ϲ͘ϴϰ нϬϱ Ϭ͘ϮϴϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϯϰϭ͘ϲ ϲ͘ϱ Ϭ͘ϲϮ Ϯϳϭϭ ϭ͘ϬϮ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϰϴ͘ϭ ϱ͘ϱ Ϭ͘ϲϯ Ϯϳϯϵ ϭ͘ϱϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϱϯ͘ϲ ϱ͘Ϭ Ϭ͘ϲϮ Ϯϲϳϵ ϭ͘Ϯϯ нϬϲ Ϭ͘ϮϲϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϯϱϴ͘ϲ ϭ͘ϱ Ϭ͘ϲϰ Ϯϳϵϰ ϭ͘ϰϭ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϲϬ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϲϳ ϭ͘ϳϬ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϲϮ͘ϭ ϭ͘ϱ Ϭ͘ϱϵ Ϯϱϳϲ ϱ͘ϳϳ нϬϱ Ϭ͘ϮϴϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϲϯ͘ϲ ϭϭ͘ϱ Ϭ͘ϲϯ Ϯϳϲϳ ϭ͘ϯϭ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϳϱ͘ϭ ϭ͘ϴ Ϭ͘ϲϲ Ϯϴϳϴ ϭ͘Ϯϰ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϳϲ͘ϵ Ϯ͘ϭ Ϭ͘ϲϳ ϮϵϮϵ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϳϵ͘Ϭ ϴ͘Ϯ Ϭ͘ϲϮ ϮϳϬϰ ϵ͘ϲϱ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϯϴϳ͘Ϯ ϰ͘ϵ Ϭ͘ϲϰ ϮϳϵϮ ϭ͘ϰϲ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϵϮ͘ϭ ϭ͘ϱ Ϭ͘ϲϲ ϮϵϬϴ ϭ͘ϲϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϯϵϯ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϮ ϮϳϯϮ ϭ͘ϱϭ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϯϵϱ͘ϲ ϯ͘ϱ Ϭ͘ϲϵ ϯϬϯϬ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϯϵϵ͘ϭ ϭ͘ϱ Ϭ͘ϲϰ Ϯϴϭϰ ϭ͘ϲϱ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϬϬ͘ϲ ϭ͘ϱ Ϭ͘ϲϴ Ϯϵϴϰ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϰϬϮ͘ϭ ϯ͘ϱ Ϭ͘ϲϮ Ϯϳϭϳ ϭ͘ϰϴ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϬϱ͘ϲ ϱ͘Ϭ Ϭ͘ϲϳ Ϯϵϳϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϰϭϬ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϭ Ϯϲϵϲ ϭ͘ϭϮ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^,> ϰϰϭϮ͘ϲ ϱ͘Ϭ Ϭ͘ϲϳ Ϯϵϳϲ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ ^,> ϰϰϭϳ͘ϲ ϯ͘ϱ Ϭ͘ϲϳ Ϯϵϳϵ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϰϮϭ͘ϭ ϭ͘ϱ Ϭ͘ϲϰ Ϯϴϭϵ ϭ͘ϯϭ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϰϮϮ͘ϲ ϭϭ͘Ϭ Ϭ͘ϲϳ Ϯϵϴϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϰϯϯ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϮ Ϯϳϱϰ ϴ͘ϯϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ ^,> ϰϰϯϱ͘ϲ ϭ͘ϱ Ϭ͘ϲϴ ϯϬϬϴ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϰϯϳ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϯ Ϯϳϳϴ ϵ͘ϱϳ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϰϯϵ͘ϭ ϰ͘Ϭ Ϭ͘ϲϴ ϯϬϬϮ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϰϯ͘ϭ ϱ͘ϱ Ϭ͘ϲϮ Ϯϳϲϵ ϭ͘ϮϬ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϰϴ͘ϲ Ϯ͘Ϭ Ϭ͘ϲϭ ϮϳϮϴ ϵ͘ϯϯ нϬϱ Ϭ͘ϮϳϬ ϭϬϬϬ /ZdzͲ^E^dKE ϰϰϱϬ͘ϲ ϲ͘Ϭ Ϭ͘ϲϴ ϯϬϭϭ ϭ͘ϳϰ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϱϲ͘ϲ Ϯϭ͘ϱ Ϭ͘ϲϮ Ϯϳϴϳ ϭ͘Ϭϴ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϳϴ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϵ ϯϬϳϳ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϴϬ͘ϭ ϰ͘Ϭ Ϭ͘ϲϰ ϮϴϲϬ ϭ͘ϭϲ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϴϰ͘ϭ Ϯ͘Ϭ Ϭ͘ϱϵ ϮϲϲϬ ϴ͘ϳϲ нϬϱ Ϭ͘ϮϳϬ ϭϱϬϬ ^,> ϰϰϴϲ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϳ ϯϬϮϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϰϴϴ͘ϭ ϰ͘Ϭ Ϭ͘ϲϯ ϮϴϮϴ ϭ͘ϱϮ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϵϮ͘ϭ ϰ͘Ϭ Ϭ͘ϲϮ Ϯϳϲϴ ϭ͘ϭϮ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϵϲ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϳ ϯϬϮϭ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ /ZdzͲ^E^dKE ϰϰϵϴ͘ϭ ϳ͘ϱ Ϭ͘ϲϯ Ϯϴϰϭ ϭ͘ϭϴ нϬϲ Ϭ͘ϮϳϬ ϭϱϬϬ ^,> ϰϱϬϱ͘ϲ ϵ͘ϱ Ϭ͘ϲϳ ϯϬϰϭ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ /ZdzͲ^E^dKE ϰϱϭϱ͘ϭ Ϯ͘Ϭ Ϭ͘ϲϴ ϯϬϴϰ ϭ͘ϲϵ нϬϲ Ϭ͘ϮϲϬ ϭϱϬϬ ^,> ϰϱϭϳ͘ϭ ϱϬ͘Ϭ Ϭ͘ϲϴ ϯϬϴϱ Ϯ͘ϲϳ нϬϲ Ϭ͘ϮϯϬ ϮϱϬϬ Formation Mechanical Properties Zone Name Ratio ϯϵ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Top TVD Net Perm Porosity Res. Pressure (ft)Height (md) (%) (psi) (ft) 4239.8 41.7 0.010 1.0 1918 4281.5 15.0 0.010 1.0 1923 4296.5 24.1 0.050 10.0 1929 4320.6 7.0 6.009 4.1 1940 4327.6 1.5 0.192 12.0 1944 4329.1 2.0 0.010 1.0 1944 4331.1 10.5 100.314 26.7 1945 4341.6 6.5 21.598 22.3 1950 4348.1 5.5 1.009 16.6 1953 4353.6 5.0 3.544 19.9 1956 4358.6 1.5 5.023 17.9 1958 4360.1 2.0 0.319 14.9 1959 4362.1 1.5 236.504 28.4 1960 4363.6 11.5 21.887 19.1 1960 4375.1 1.8 50.818 20.1 1966 4376.9 2.1 0.026 15.0 1968 4379.0 8.2 62.684 23.0 1970 4387.2 4.9 4.489 17.4 1970 4392.1 1.5 0.488 15.1 1974 4393.6 2.0 1.982 16.9 1974 4395.6 3.5 0.010 1.0 1975 4399.1 1.5 0.552 15.4 1977 4400.6 1.5 0.010 1.0 1978 4402.1 3.5 3.859 17.2 1978 4405.6 5.0 0.010 1.0 1980 4410.6 2.0 41.288 21.2 1982 4412.6 5.0 0.010 1.0 1983 4417.6 3.5 0.010 1.0 1986 4421.1 1.5 5.111 19.0 1987 4422.6 11.0 0.010 1.0 1988 4433.6 2.0 111.829 24.6 1993 4435.6 1.5 0.010 1.0 1994 4437.1 2.0 102.765 23.1 1995 4439.1 4.0 0.016 15.0 1996 4443.1 5.5 24.191 20.3 1997 4448.6 2.0 33.759 23.4 2000 4450.6 6.0 0.015 14.5 2001 4456.6 21.5 82.778 21.8 2004 4478.1 2.0 0.014 15.0 2014 4480.1 4.0 26.711 20.7 2015 4484.1 2.0 162.436 24.1 2017 4486.1 2.0 0.010 1.0 2018 4488.1 4.0 1.983 16.8 2019 4492.1 4.0 30.725 21.1 2020 4496.1 2.0 0.009 15.0 2022 4498.1 7.5 8.533 20.5 2023 4505.6 9.5 0.010 1.0 2027 4515.1 2.0 15.000 10.0 2096 4517.1 50.0 0.010 1.0 2126 Formation Transmissibility Properties Zone Name DIRTY-SANDSTONE Shale SHALE SILTSTONE Top Nan CS DIRTY-SANDSTONE SHALE CLEAN-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE DIRTY-SANDSTONE SHALE SHALE ϰϬ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 29: Propped Fracture Schedule (Stage 10; 13026 ft MD) Pumping Schedule Step Pump Step Fluid Gel Prop. Name Rate Volume Conc. Conc. (bbl/min) (bbl) (lb/mgal) (PPA) PAD 40 YF126ST 250.0 26 0 1.0 PPA Scour 40 YF126ST 57.5 26 1 3.0 PPA Scour 40 YF126ST 105.9 26 3 Resume PAD 40 YF126ST 50.0 26 0 1.0 PPA 40 YF126ST 191.5 26 1 2.0 PPA 40 YF126ST 206.7 26 2 4.0 PPA 40 YF126ST 233.5 26 4 6.0 PPA 40 YF126ST 205.3 26 6 8.0 PPA 40 YF126ST 177.1 26 8 10.0 PPA 40 YF126ST 138.5 26 10 Flush 40 YF126ST 198.4 26 0 Please note that this pumping schedule is under-displaced by 0 bbl. 1814.5 bbl of YF126ST 0 bbl of WF126 234070 lb of 15762 lb of % PAD Clean 15.5 % PAD Dirty 13.3 Step Fluid Cum. Fluid Step Slurry Cum. Slurry Step Prop Cum. Avg. Surface Step Time Cum. Volume Volume Volume Volume (lb)Prop. Pressure (min)Time (bbl) (bbl) (bbl) (bbl) (lb) (psi) (min) PAD 250.0 250 250 250 0 0 3618 6.3 6.3 1.0 PPA Scour 57.5 307 60 310 2413 2413 3618 1.5 7.7 3.0 PPA Scour 105.9 413 120 430 13349 15762 3564 3.0 10.7 Resume PAD 50.0 463 50 480 0 15762 3464 1.3 12.0 1.0 PPA 191.5 655 200 680 8043 23805 3453 5.0 17.0 2.0 PPA 206.7 862 225 905 17359 41164 3381 5.6 22.6 4.0 PPA 233.5 1095 275 1180 39235 80399 3381 6.9 29.5 6.0 PPA 205.3 1300 260 1440 51742 132141 3502 6.5 36.0 8.0 PPA 177.1 1478 240 1680 59511 191652 3797 6.0 42.0 10.0 PPA 138.5 1616 200 1880 58180 249832 4084 5.0 47.0 Flush 198.4 1814 198 2078 0 249832 4084 5.0 52.0 Carbolite 16/20 + 6wt% ScaleGuard IV The following is the Pumping Schedule to achieve a propped fracture half-length (Xf) of 451.8 ft with an average conductivity (Kfw) of 10027.1 md.ft. Job Description Fluid Name Prop. Type and Mesh Carbolite 40/70 Carbolite 40/70 Carbolite 16/20 + 6wt% ScaleGuard IV Pad Percentages Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 16/20 + 6wt% ScaleGuard IV Fluid Totals Proppant Totals Carbolite 16/20 + 6wt% ScaleGuard IV Carbolite 40/70 Job Execution Step Name ϰϭ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Section 30: Propped Fracture Simulation (Stage 10; 13026 ft MD) /ŶŝƚŝĂů&ƌĂĐƚƵƌĞdŽƉdsϰϮϱϮ͘ϰĨƚ /ŶŝƚŝĂů&ƌĂĐƚƵƌĞŽƚƚŽŵdsϰϱϰϱ͘ϭĨƚ WƌŽƉƉĞĚ&ƌĂĐƚƵƌĞ,ĂůĨͲ>ĞŶŐƚŚ ϰϱϭ͘ϴĨƚ K:,LJĚ,ĞŝŐŚƚĂƚtĞůů ϮϵϮ͘ϲĨƚ ǀĞƌĂŐĞWƌŽƉƉĞĚtŝĚƚŚ Ϭ͘ϭϮŝŶ EĞƚWƌĞƐƐƵƌĞ ϮϴϯƉƐŝ DĂdž^ƵƌĨĂĐĞWƌĞƐƐƵƌĞ ϰϯϭϬƉƐŝ From To Prop. Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Pumping Width Height Prop. Conc. Gel Conc. Conductivity (PPA) (in) (ft) (lb/ft2) (lb/mgal) (md.ft) 0 113 8.7 0.162 209.2 1.37 217.9 14355 113 225.9 5.6 0.145 209.2 1.26 251.8 12472 225.9 338.9 3.7 0.116 209.2 1.02 313.6 9629 338.9 451.8 1.3 0.067 163.2 0.58 453.5 4908 The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Simulation Results by Fracture Segment ϰϮ ^>WƌŝǀĂƚĞ ƚƚĂĐŚŵĞŶƚ< Proposed Variance Request NDB-011 Well PTD 225-048 API 50-103-20916-00-00 Proposed Variance Request 20 AAC 25.283. Hydraulic fracturing. (l) Upon written request of the operator, the commission may modify a deadline in this section upon a showing of good cause, approve a variance from any other requirement of this section if the variance provides at least an equally effective means of complying with the requirement, or approve a waiver of a requirement of this section if the waiver will not promote waste, is based on sound engineering and geoscience principles, will not jeopardize the ultimate recovery of hydrocarbons, will not jeopardize correlative rights, and will not result in an increased risk to health, safety, or the environment, including freshwater. (a)(6)(B) an assessment of each casing and cementing operation performed to construct or repair the well; the assessment must include sufficient supporting information, including cement evaluation logs and other evaluation logs approved by the commission, to demonstrate that (A) casing is cemented (i) below the base of the lowermost freshwater aquifer; and (ii) in accordance with 20 AAC 25.030; and (B) each hydrocarbon zone penetrated by the well is isolated; Oil Search Alaska, LLC (OSA) hereby submits a request for a Variance to allow the fracture stimulation and operation of the Pikka development production well NDB-011. The 9-5/8” liner was run and cemented as per the permit conditions outlined in PTD 225-048. No losses were observed, and the plug was bumped during the first stage primary cement job. Upon reviewing top of cement logging results, it was noted that top of cement was above the upper most hydrocarbon zone in the Nanushuk formations but was below top of the Nanuhsuk formation and below the planned permit to drill top of cement. OSA presents the evidence below to demonstrate that the well can still be safely fracture stimulated, operated, and ultimately abandoned in compliance with AOGCC regulations. 1. Well Design and Geology: x 9-5/8” Liner Top at 2,578’ MD x 13-3/8” Shoe at 2,758’ MD x TS790 at 4,649’ MD x CFLEX Stage Tool at 4,750’ MD x Top Nanushuk 9436’ MD x Top Hydrocarbons in NT8 9791’ MD x 9-5/8” Shoe at 12,419’ MD See Attachment 1 for schematic. Recommend approving variance request. -A.Dewhurst 18AUG25 2. Cement Job Planning / Execution: 9-5/8” Intermediate Liner: x 1st stage of the cement job planned with 15.3 ppg tail slurry with 57% excess, targeting TOC 100’ TVD above top Nanushuk formation. x During execution of the 1st stage cement, plug was bumped, displacement lift pressure and no losses were observed. x After drilling out the 9-5/8” shoe a LOT was conducted to 14.0ppg with no leak off observed. x 2nd Stage of cement job planned with CFLEX ~100’ below the TS790. Also planned with 15.3 ppg tail slurry with 145% excess, targeting TOC at the 9-5/8” liner top. x During execution of the 2nd stage cement job, no losses and good lift pressure was observed. A large interface (~195bbl) of spacer/mud/cement was circulated off the top of liner in addition to 60bbl of neat green cement. 3. Observations / Conclusions: 9-5/8” Intermediate Liner 1st Stage Cement Job: x The Baker LWD TOC log indicates top of cement at ~9632’ MD (3917’ TVD) with partial bonds observed sporadically from 8700’ to 9598’ MD above that point. x The 9632’ MD top of cement would indicate that the Nanushuk formation has not been covered. x Density Neutron LWD logs across the upper Nanushuk formations indicate that top of potential hydrocarbons in the NT8 in the NDB-011 well is ~9791’ MD / 3952’ TVD. x This would place top of cement ~159’ MD / 35’ TVD above the top of potential hydrocarbons observed on LWD logs. 9-5/8” Intermediate Liner 2nd Stage Cement Job: x Based on job execution results, cement isolation was achieved across the significant hydrocarbon zone within the upper Tuluvak formation. The 12-1/4” hole section was drilled with 11.0ppg mud weight in an effort to combat low fracture gradients, high ECDs and cementing losses observed on recent offset wells. Wellbore stability became an issue and the hole required significant circulation and clean up in order to trip the BHA out of the hole. No losses were observed running the 9-5/8” liner or during the first stage cement job. Drilling and cementing observations suggest that the hole was much larger than expected and despite pumping additional excess cement it was not sufficient to meet the target top of cement. The Baker LWD TOC cement log is included in this submission for additional information. Due the hole conditions in this well, the top of the Nanushuk pool has not been cemented as per the approved PTD however, OSA’s assessment is that adequate isolation to prevent crossflow of the Nanushuk to any shallower permeable formations, as well as adequate isolation across the 9-5/8” shoe for frac operations has been achieved. In addition, the trajectory of the NDB-011 well is also positioned so that there are no other wells within the vicinity of the 9-5/8” liner first stage cement job. 4. Future P&A Considerations: x During the final permanent abandonment of NDB-011 well, the well will be P&A’d in accordance with AOGCC requirements in 20 AAC 25.112 Well Plugging Requirements and OSA’s Technical Standards. x Current well conditions retain the ability during the P&A to ensure that all hydrocarbons are confined to their respective strata and are prevented from migrating into other strata or to the surface. x A full P&A can be achieved in various ways to comply with regulations. A potential P&A strategy is shown in the schematic that is included in Attachment 10. 5. Attachments: Attached are the following documents in support of the variance application: 1. As-drilled Schematic 2. Cement Summary Schematic 3. As drilled well path 4. NDB-011 well trajectory with plan view and closest offsets 5. Baker LWD Sonic TOC Log 6. Baker LWD Sonic TOC Log Interpretation 7. Intermediate Casing Cement Report 8. NT4-8 Petrophysical Analysis 9. NT4-8 1200 Petrophysics Log 10. NDB-011 Potential Plug & Abandonment Schematic Conclusions: x Lighter mud weight(11.0ppg)in the intermediatehole sectionwasused to mitigate losses observed on offset wells. The lighter mud weight well caused additional instability and hole enlargement. x The 9-5/8” stage 1 cement job was pumped ǁŝƚŚ313bbls cement with 57% excess cement. x Top of cement was logged ~159’ MD / 35’ TVD above the top of potential hydrocarbons observed on LWD logs indicating that all hydrocarbons are isolated. x The top of cement was logged ~196’ MD / 44’ TVD below the top of the Nanushuk pool. x The permanent P&A of the well will be in accordance with the AOGCC requirements in 20 AAC 25.112 Well Plugging Requirements and OSA’s Technical Standards and prevent hydrocarbon migration into other strata. Considering the evidence presented above, OSA requests a Variance to allow fracture stimulation and operation of the Pikka development production well NDB-011. Tuluvak Sand @ 3,226' MD Top Nan 3.2 @12,' MD Top Nanushuk @ 9,436' MD NDB-011 Well Schematic (As-Drill) 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2,578' MD 13-3/8" 68 ppf L-80 Surface Casing2,758' MD 9-5/8", 47ppf L-80 Production Liner12,419' MD 4-½”, 12.6ppf P-110S Production Liner 18,617' MD 4-½” Liner Hanger/ Top Packer12,228' MD GL 69.50' RKB – Bottom Flange July 25th, 2025 1 2 3 4 5 6 9-5/8" Tieback2,578' MD 9-5/8" Cflex Stage Tool (101' MD below TS790) 4,750' MD 9-5/8" Primary TOC (159' MD/35' TVD above top HC) 9,632' MD 8-½” Openhole TD TD 18,634' MD # Completion Item Top Depth (MD') Depth (TVD') Inc ID" OD" 1 X Landing Nipple 1505 1468 25 3.813 4.778 2 Gaslift Mandrel 1.5" 2229 2054 46 3.865 7.652 3 X Landing Nipple 2300 2102 48 3.813 4.778 4 SSD NERA Gaslift 12030 4341 86 3.813 7.000 5 D/H Psi-Temp Gauge 12095 4345 86 3.958 7.000 6 EGL Valve 12159 4349 87 3.918 6.173 7 Tieback Seal Assy 12269 4355 88 3.880 8.210 8 9.625" x 4.5" LH/Packer 12228 4353 87 6.030 8.430 9 #13 OH packer 12568 4362 90 3.918 8.000 10 #12 OH packer 12635 4362 90 3.735 5.624 11 #20 Tracer Carrier 12974 4355 92 3.958 5.720 12 Stg 10 - Collet Sleeve 10 13025 4353 92 3.735 5.624 13 #19 Tracer Carrier 13038 4353 92 3.958 5.720 14 #11 OH packer 13171 4349 92 3.918 8.000 15 #18 Tracer Carrier 13595 4337 92 3.958 5.720 16 Stg 9 - Collet Sleeve 9 13646 4335 92 3.735 5.624 17 #17 Tracer Carrier 13660 4335 92 3.958 5.720 18 #10 OH packer 13956 4326 92 3.918 8.000 19 #16 Tracer Carrier 14095 4322 92 3.958 5.720 20 Stg 8 - Collet Sleeve 8 14146 4321 92 3.735 5.624 21 #15 Tracer Carrier 14160 4320 92 3.958 5.720 22 #9 OH packer 14335 4315 92 3.918 8.000 23 #14 Tracer Carrier 14681 4305 92 3.958 5.720 24 Stg 7 - Collet Sleeve 7 14732 4304 92 3.735 5.624 25 #13 Tracer Carrier 14746 4303 92 3.958 5.720 26 #8 OH packer 15002 4296 92 3.918 8.000 27 #12 Tracer Carrier 15265 4288 92 3.958 5.720 28 Stg 6 - Collet Sleeve 6 15316 4287 92 3.735 5.625 29 #11 Tracer Carrier 15330 4287 92 3.958 5.720 30 #7 OH packer 15627 4278 92 3.918 8.000 31 #10 Tracer Carrier 15851 4271 92 3.958 5.720 32 Stg 5 - Collet Sleeve 5 15902 4270 92 3.735 5.624 33 #9 Tracer Carrier 15916 4270 92 3.958 5.720 34 #6 OH packer 16172 4247 92 3.918 8.000 35 #8 Tracer Carrier 16434 4255 92 3.958 5.720 36 Stg 4 - Collet Sleeve 4 16486 4253 92 3.735 5.624 37 #7 Tracer Carrier 16500 4253 92 3.958 5.720 38 #5 OH Packer 16796 4244 92 3.918 8.000 39 #4 OH packer 16944 4240 92 3.918 8.000 40 #6 Tracer Carrier 17122 4235 92 3.958 5.720 41 Stg 3 - Collet Sleeve 3 17174 4233 92 3.735 5.624 42 #5 Tracer Carrier 17188 4233 92 3.958 5.720 43 #3 OH packer 17444 4225 92 3.918 8.000 44 #4 Tracer Carrier 17704 4218 92 3.958 5.720 45 Stg 2 - Collet Sleeve 2 17755 4216 92 3.735 5.624 46 #3 Tracer Carrier 17768 4216 92 3.958 5.720 47 #2 OH packer 18023 4209 92 3.918 8.000 48 #2 Tracer Carrier 18244 4202 92 3.958 5.720 49 Stg 1 - Collet Sleeve 1 18296 4201 92 3.735 5.624 50 #1 Tracer Carrier 18310 4200 92 3.958 5.720 51 #1 OH packer 18480 4195 92 3.918 8.000 52 Toe Sleeve 18588 4192 92 3.500 5.750 53 WIV Collar 18602 4192 92 0.870 5.620 54 Eccentric shoe 18615 4191 92 3.840 5.200 Field : Pikka Well : NDB-011 Operator : Santos Rig : Parker 272 Drill Floor 0 ft MD Top of Liner 2578 ft MD Stage 2 Cement Job 13-3/8" Shoe 2758 ft MD 285bbl cement pumped No losses 60bbl neat green cement circulated off liner top TS790 4649 ft MD in addition to large interface volumes Cflex Stage Tool 4750 ft MD Delta TOC Delta TOC Expected TOC Stage 1 (based on 30% excess) 8280 ft MD -1352 ft MD 3623 ft TVD -294 ft TVD Top of Logged Interval 8860 ft MD Planned TOC Stage 1 (100' TVD above Nan.) 8976 ft MD -656 ft MD 3773 ft TVD -144 ft TVD Top Nanusuk 9436 ft MD -196 ft MD 3873 ft TVD -44 ft TVD Logged TOC Stage 1 9632 ft MD 3917 ft TVD NT8 MFS 9734 ft MD 102 ft MD 3939 ft TVD 22 ft TVD Top of potential HC 9791 ft MD 159 ft MD 3952 ft TVD 35 ft TVD NT7 MFS 9987 ft MD 3996 ft TVD ft TVD NT6 MFS 10242 ft MD 4052 ft TVD ft TVD NT5 MFS 10561 ft MD 4121 ft TVD ft TVD NT4 MFS 10985 ft MD 4204 ft TVD ft TVD NT3 MFS 12ft MD 4352 ft TVD ft TVD 97% Excess back calculated Landing Collar Depth N/A ft MD 14.4 inch average hole size back calculated Float Collar 12333 ft MD 9-5/8" Casing Shoe 12419 ft MD Stage 1 Cement Job Hole Section TD 12427 ft MD 313 bbl cement pumped Plug bumped No losses MD TVD Santos Definitive Survey Report28 July, 2025Design: NDB-011Santos NAD27 ConversionPikkaNDBB-11NDB-011 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueMap System:Geo Datum:ProjectMap Zone:System Datum:US State Plane 1983North American Datum 1983Pikka, North Slope Alaska, United StatesAlaska Zone 4Mean Sea LevelUsing Well Reference PointUsing geodetic scale factorSite Position:From:SiteLatitude:Longitude:Position Uncertainty:Northing:Easting:Grid Convergence:NDBusftMapusftusft°-0.59Slot Radius:"365,972,657.911,563,416.330.970° 20' 8.990 N150° 37' 29.073 WWellWell PositionLongitude:Latitude:Easting:Northing:usft+E/-W+N/-SPosition UncertaintyusftusftusftGround Level:B-11usftusft0.00.05,972,608.231,562,553.6422.8Wellhead Elevation:usft0.570° 20' 8.413 N150° 37' 54.254 WWellboreDeclination(°)Field Strength(nT)Sample Date Dip Angle(°)NDB-011Model NameMagneticsBGGM2025 17/07/2025 13.63 80.53 57,110.55017581Phase:Version:Audit Notes:DesignNDB-0111.0 ACTUALVertical Section: Depth From (TVD)(usft)+N/-S(usft)Direction(°)+E/-W(usft)Tie On Depth:47.0263.530.00.047.028/07/2025 17:46:16COMPASS 5000.17 Build Page 2 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueFrom(usft)Survey ProgramDescriptionTool NameSurvey (Wellbore)To(usft)Date28/07/2025SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISCWSA Rev 4)128.0 659.001 SDI GyroMWD 16in Hole <46-658> (ND3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag694.2 2,683.802 BH OntraK 16in Hole <694-2683> (NDB3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,783.4 12,387.503 BH OntraK 12.25in Hole <2783-12387>3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag12,446.6 18,610.604 BH OntraK 8.5in Hole <12446-18610> MD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)47.0 0.00 0.00 47.0 -22.8 0.0 0.0 5,972,608.23 1,562,553.64 0.00 0.0128.0 0.44 2.11 128.0 58.2 0.3 0.0 5,972,608.54 1,562,553.65 0.54 0.020" Conductor Casing187.4 0.44 3.16 187.4 117.6 0.8 0.0 5,972,609.00 1,562,553.68 0.01 -0.1281.6 0.44 356.48 281.6 211.8 1.5 0.0 5,972,609.72 1,562,553.69 0.05 -0.2376.3 0.70 174.73 376.3 306.5 1.3 0.1 5,972,609.50 1,562,553.71 1.20 -0.2471.0 2.45 172.62 471.0 401.2 -1.3 0.4 5,972,606.92 1,562,554.00 1.85 -0.2564.6 4.62 184.92 564.4 494.6 -7.1 0.3 5,972,601.18 1,562,553.87 2.44 0.5659.0 6.87 187.73 658.3 588.5 -16.4 -0.8 5,972,591.81 1,562,552.69 2.40 2.6694.2 7.28 189.38 693.3 623.5 -20.7 -1.4 5,972,587.53 1,562,552.00 1.30 3.8788.1 9.08 188.11 786.1 716.3 -33.9 -3.4 5,972,574.35 1,562,549.85 1.93 7.2881.7 11.79 189.64 878.3 808.5 -50.7 -6.1 5,972,557.63 1,562,547.03 2.91 11.8978.7 14.88 194.59 972.6 902.8 -72.5 -10.9 5,972,535.86 1,562,542.01 3.39 19.01,049.0 14.87 194.40 1,040.5 970.7 -90.0 -15.4 5,972,518.44 1,562,537.31 0.07 25.4Upper Shradder Bluff1,073.2 14.86 194.33 1,063.9 994.1 -96.0 -16.9 5,972,512.44 1,562,535.71 0.08 27.61,168.5 15.33 196.35 1,156.0 1,086.2 -119.9 -23.5 5,972,488.58 1,562,528.89 0.74 36.91,262.6 17.71 201.14 1,246.1 1,176.3 -145.2 -32.2 5,972,463.39 1,562,519.97 2.91 48.31,358.4 20.67 204.37 1,336.6 1,266.8 -174.2 -44.4 5,972,434.52 1,562,507.43 3.28 63.828/07/2025 17:46:16COMPASS 5000.17 Build Page 3 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)1,418.0 22.49 204.38 1,392.0 1,322.2 -194.2 -53.5 5,972,414.65 1,562,498.18 3.05 75.0Base Permafrost Transition1,453.3 23.56 204.38 1,424.5 1,354.7 -206.7 -59.2 5,972,402.14 1,562,492.35 3.03 82.11,547.8 26.38 205.20 1,510.2 1,440.4 -242.9 -75.9 5,972,366.10 1,562,475.23 3.01 102.81,642.1 29.27 204.75 1,593.6 1,523.8 -282.8 -94.5 5,972,326.40 1,562,456.25 3.07 125.71,737.0 32.50 205.49 1,675.0 1,605.2 -326.9 -115.2 5,972,282.55 1,562,435.11 3.43 151.31,811.0 35.10 204.41 1,736.5 1,666.7 -364.3 -132.5 5,972,245.40 1,562,417.37 3.60 172.7Middle Shradder Bluff1,832.1 35.84 204.13 1,753.7 1,683.9 -375.4 -137.5 5,972,234.29 1,562,412.22 3.59 179.01,926.3 38.28 204.71 1,828.8 1,759.0 -427.1 -161.0 5,972,182.87 1,562,388.22 2.62 208.12,021.0 40.46 206.30 1,902.1 1,832.3 -481.3 -186.9 5,972,128.91 1,562,361.76 2.53 240.02,115.6 43.38 206.41 1,972.5 1,902.7 -538.0 -215.0 5,972,072.58 1,562,333.12 3.09 274.22,210.2 46.59 205.97 2,039.3 1,969.5 -597.9 -244.4 5,972,012.93 1,562,303.02 3.41 310.32,304.0 50.10 206.46 2,101.7 2,031.9 -660.8 -275.4 5,971,950.37 1,562,271.40 3.76 348.12,388.0 51.47 207.36 2,154.8 2,085.0 -718.8 -304.9 5,971,892.67 1,562,241.35 1.83 383.9MCU2,399.3 51.65 207.48 2,161.8 2,092.0 -726.7 -309.0 5,971,884.82 1,562,237.17 1.79 388.92,494.2 53.47 208.30 2,219.5 2,149.7 -793.2 -344.2 5,971,818.67 1,562,201.27 2.04 431.42,589.2 55.88 210.01 2,274.4 2,204.6 -861.0 -382.0 5,971,751.35 1,562,162.77 2.93 476.62,683.8 58.90 212.20 2,325.4 2,255.6 -929.1 -423.1 5,971,683.64 1,562,120.92 3.74 525.12,758.0 61.28 213.22 2,362.4 2,292.6 -983.3 -457.9 5,971,629.87 1,562,085.59 3.42 565.813-3/8" Surface Casing2,783.4 62.09 213.56 2,374.4 2,304.6 -1,001.9 -470.2 5,971,611.34 1,562,073.09 3.42 580.12,846.8 64.09 213.16 2,403.2 2,333.4 -1,049.2 -501.3 5,971,564.41 1,562,041.49 3.20 616.42,941.9 67.59 214.83 2,442.0 2,372.2 -1,121.0 -549.8 5,971,493.06 1,561,992.27 4.02 672.62,999.0 69.48 215.41 2,463.0 2,393.2 -1,164.5 -580.4 5,971,449.90 1,561,961.24 3.44 707.9Tuluvak Shale28/07/2025 17:46:16COMPASS 5000.17 Build Page 4 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)3,036.7 70.72 215.78 2,475.8 2,406.0 -1,193.3 -601.0 5,971,421.32 1,561,940.33 3.42 731.63,130.9 73.33 214.97 2,504.9 2,435.1 -1,266.4 -652.9 5,971,348.75 1,561,887.67 2.89 791.53,226.0 76.16 215.23 2,529.9 2,460.1 -1,341.5 -705.6 5,971,274.30 1,561,834.18 2.99 852.3Tuluvak Sans3,226.3 76.17 215.23 2,529.9 2,460.1 -1,341.7 -705.8 5,971,274.09 1,561,834.03 3.85 852.53,320.6 77.32 215.06 2,551.6 2,481.8 -1,416.8 -758.7 5,971,199.55 1,561,780.39 1.23 913.53,415.7 77.32 214.82 2,572.4 2,502.6 -1,492.8 -811.8 5,971,124.06 1,561,726.47 0.25 974.83,509.8 77.29 214.95 2,593.1 2,523.3 -1,568.1 -864.3 5,971,049.30 1,561,673.18 0.14 1,035.53,604.7 77.25 213.88 2,614.0 2,544.2 -1,644.5 -916.6 5,970,973.48 1,561,620.08 1.10 1,096.13,699.9 77.35 214.21 2,635.0 2,565.2 -1,721.4 -968.6 5,970,897.10 1,561,567.30 0.35 1,156.43,794.6 77.32 214.93 2,655.7 2,585.9 -1,797.5 -1,021.0 5,970,821.56 1,561,514.08 0.74 1,217.13,889.5 77.37 215.30 2,676.5 2,606.7 -1,873.2 -1,074.3 5,970,746.42 1,561,460.07 0.38 1,278.53,984.3 77.34 215.01 2,697.3 2,627.5 -1,948.9 -1,127.6 5,970,671.31 1,561,406.00 0.30 1,340.04,079.2 77.36 213.64 2,718.1 2,648.3 -2,025.3 -1,179.8 5,970,595.43 1,561,353.03 1.41 1,400.44,173.9 77.31 212.85 2,738.8 2,669.0 -2,102.6 -1,230.4 5,970,518.71 1,561,301.59 0.82 1,459.54,269.0 77.42 212.25 2,759.6 2,689.8 -2,180.8 -1,280.3 5,970,441.02 1,561,250.86 0.63 1,517.94,363.3 77.50 212.91 2,780.1 2,710.3 -2,258.4 -1,329.9 5,970,363.93 1,561,200.46 0.69 1,575.94,458.2 77.51 213.09 2,800.6 2,730.8 -2,336.1 -1,380.4 5,970,286.77 1,561,149.21 0.19 1,634.84,552.6 77.66 212.69 2,820.9 2,751.1 -2,413.6 -1,430.5 5,970,209.87 1,561,098.34 0.44 1,693.34,647.3 77.70 211.73 2,841.1 2,771.3 -2,491.8 -1,479.7 5,970,132.18 1,561,048.26 0.99 1,751.14,649.0 77.70 211.73 2,841.5 2,771.7 -2,493.2 -1,480.6 5,970,130.75 1,561,047.36 0.00 1,752.1TS_7904,741.5 77.67 211.64 2,861.2 2,791.4 -2,570.1 -1,528.1 5,970,054.33 1,560,999.08 0.10 1,808.04,836.6 77.71 211.99 2,881.5 2,811.7 -2,649.1 -1,577.1 5,969,975.90 1,560,949.29 0.36 1,865.54,931.8 77.66 213.03 2,901.8 2,832.0 -2,727.5 -1,627.1 5,969,897.99 1,560,898.49 1.07 1,924.05,026.6 77.66 213.50 2,922.1 2,852.3 -2,805.0 -1,677.9 5,969,821.09 1,560,846.89 0.48 1,983.25,121.8 77.68 212.96 2,942.4 2,872.6 -2,882.7 -1,728.8 5,969,743.90 1,560,795.17 0.56 2,042.628/07/2025 17:46:16COMPASS 5000.17 Build Page 5 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)5,215.6 77.67 213.53 2,962.4 2,892.6 -2,959.4 -1,779.1 5,969,667.73 1,560,744.10 0.59 2,101.25,310.5 77.67 214.76 2,982.7 2,912.9 -3,036.1 -1,831.1 5,969,591.60 1,560,691.31 1.27 2,161.55,405.2 77.51 215.27 3,003.0 2,933.2 -3,111.8 -1,884.1 5,969,516.42 1,560,637.47 0.55 2,222.85,500.4 77.51 215.52 3,023.6 2,953.8 -3,187.6 -1,938.0 5,969,441.22 1,560,582.85 0.26 2,284.85,594.6 77.51 215.81 3,044.0 2,974.2 -3,262.3 -1,991.6 5,969,367.06 1,560,528.45 0.30 2,346.55,689.5 77.50 215.28 3,064.5 2,994.7 -3,337.8 -2,045.5 5,969,292.21 1,560,473.79 0.55 2,408.55,784.2 77.55 213.72 3,085.0 3,015.2 -3,413.9 -2,097.8 5,969,216.60 1,560,420.66 1.61 2,469.15,879.2 77.51 213.80 3,105.5 3,035.7 -3,491.0 -2,149.4 5,969,140.02 1,560,368.32 0.09 2,529.15,973.7 77.49 213.91 3,126.0 3,056.2 -3,567.7 -2,200.8 5,969,063.90 1,560,316.10 0.12 2,588.86,024.0 77.50 213.83 3,136.8 3,067.0 -3,608.4 -2,228.2 5,969,023.46 1,560,288.34 0.16 2,620.5Seabee6,069.1 77.51 213.75 3,146.6 3,076.8 -3,645.1 -2,252.7 5,968,987.09 1,560,263.45 0.17 2,649.06,164.0 77.52 213.20 3,167.1 3,097.3 -3,722.4 -2,303.8 5,968,910.34 1,560,211.55 0.57 2,708.56,258.8 77.46 213.17 3,187.6 3,117.8 -3,799.8 -2,354.4 5,968,833.48 1,560,160.13 0.07 2,767.56,353.0 77.47 213.53 3,208.1 3,138.3 -3,876.5 -2,404.9 5,968,757.22 1,560,108.80 0.37 2,826.46,448.3 77.45 213.44 3,228.8 3,159.0 -3,954.2 -2,456.3 5,968,680.13 1,560,056.65 0.09 2,886.26,542.7 77.47 213.71 3,249.3 3,179.5 -4,030.9 -2,507.2 5,968,603.93 1,560,004.92 0.28 2,945.46,637.7 77.54 213.89 3,269.8 3,200.0 -4,108.0 -2,558.8 5,968,527.39 1,559,952.52 0.20 3,005.46,732.4 77.52 213.78 3,290.3 3,220.5 -4,184.8 -2,610.3 5,968,451.13 1,559,900.25 0.12 3,065.26,827.1 77.50 214.15 3,310.8 3,241.0 -4,261.5 -2,662.0 5,968,374.96 1,559,847.78 0.38 3,125.26,922.0 77.52 213.89 3,331.3 3,261.5 -4,338.3 -2,713.8 5,968,298.72 1,559,795.15 0.27 3,185.47,016.4 77.58 213.74 3,351.6 3,281.8 -4,414.9 -2,765.1 5,968,222.73 1,559,743.11 0.17 3,244.97,111.1 77.44 214.56 3,372.1 3,302.3 -4,491.4 -2,817.0 5,968,146.73 1,559,690.39 0.86 3,305.27,206.8 77.51 214.27 3,392.9 3,323.1 -4,568.5 -2,869.8 5,968,070.20 1,559,636.79 0.30 3,366.37,301.0 77.51 214.25 3,413.3 3,343.5 -4,644.5 -2,921.6 5,967,994.72 1,559,584.22 0.02 3,426.37,395.1 77.49 214.01 3,433.6 3,363.8 -4,720.5 -2,973.2 5,967,919.24 1,559,531.91 0.25 3,486.17,490.1 77.48 214.32 3,454.2 3,384.4 -4,797.3 -3,025.2 5,967,843.06 1,559,479.04 0.32 3,546.528/07/2025 17:46:16COMPASS 5000.17 Build Page 6 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)7,584.9 77.65 214.28 3,474.6 3,404.8 -4,873.7 -3,077.4 5,967,767.15 1,559,426.09 0.18 3,606.97,679.5 77.70 214.45 3,494.8 3,425.0 -4,950.1 -3,129.6 5,967,691.40 1,559,373.13 0.18 3,667.47,775.1 77.60 214.67 3,515.3 3,445.5 -5,027.0 -3,182.6 5,967,615.04 1,559,319.36 0.25 3,728.77,869.5 77.67 214.31 3,535.5 3,465.7 -5,102.9 -3,234.7 5,967,539.63 1,559,266.39 0.38 3,789.17,964.8 77.65 213.43 3,555.8 3,486.0 -5,180.3 -3,286.6 5,967,462.86 1,559,213.69 0.90 3,849.48,059.0 77.64 213.87 3,576.0 3,506.2 -5,256.8 -3,337.6 5,967,386.83 1,559,161.94 0.46 3,908.78,153.5 77.74 213.38 3,596.1 3,526.3 -5,333.7 -3,388.7 5,967,310.51 1,559,110.03 0.52 3,968.18,248.2 77.66 214.00 3,616.3 3,546.5 -5,410.7 -3,440.1 5,967,234.03 1,559,057.89 0.64 4,027.88,343.0 77.70 213.44 3,636.5 3,566.7 -5,487.8 -3,491.5 5,967,157.50 1,559,005.65 0.58 4,087.68,437.4 77.71 213.40 3,656.6 3,586.8 -5,564.7 -3,542.3 5,967,081.08 1,558,954.08 0.04 4,146.88,532.8 77.48 213.42 3,677.1 3,607.3 -5,642.5 -3,593.6 5,967,003.90 1,558,902.01 0.24 4,206.58,627.5 77.54 213.84 3,697.6 3,627.8 -5,719.4 -3,644.8 5,966,927.46 1,558,850.02 0.44 4,266.08,721.3 77.52 213.82 3,717.9 3,648.1 -5,795.6 -3,695.8 5,966,851.88 1,558,798.22 0.03 4,325.38,815.9 77.52 213.78 3,738.3 3,668.5 -5,872.3 -3,747.2 5,966,775.70 1,558,746.06 0.04 4,385.08,910.5 77.48 214.65 3,758.8 3,689.0 -5,948.7 -3,799.1 5,966,699.83 1,558,693.31 0.90 4,445.29,005.4 77.51 215.07 3,779.3 3,709.5 -6,024.7 -3,852.1 5,966,624.37 1,558,639.57 0.43 4,506.49,100.5 77.51 215.41 3,799.9 3,730.1 -6,100.5 -3,905.6 5,966,549.15 1,558,585.25 0.35 4,568.19,194.8 77.52 215.94 3,820.3 3,750.5 -6,175.3 -3,959.3 5,966,474.91 1,558,530.78 0.55 4,629.99,290.0 77.33 215.99 3,841.0 3,771.2 -6,250.5 -4,013.9 5,966,400.29 1,558,475.44 0.21 4,692.69,384.5 77.16 218.46 3,861.9 3,792.1 -6,324.0 -4,069.7 5,966,327.46 1,558,418.91 2.55 4,756.39,436.0 77.16 219.81 3,873.3 3,803.5 -6,362.9 -4,101.3 5,966,288.87 1,558,386.84 2.56 4,792.2Nanushuk9,478.9 77.16 220.93 3,882.9 3,813.1 -6,394.8 -4,128.5 5,966,257.26 1,558,359.39 2.54 4,822.79,573.2 77.19 223.03 3,903.8 3,834.0 -6,463.1 -4,189.9 5,966,189.60 1,558,297.24 2.17 4,891.59,668.7 77.23 225.35 3,924.9 3,855.1 -6,529.9 -4,254.8 5,966,123.51 1,558,231.64 2.37 4,963.59,734.0 77.19 227.26 3,939.4 3,869.6 -6,573.9 -4,300.9 5,966,079.99 1,558,185.14 2.85 5,014.2NT8 MFS28/07/2025 17:46:16COMPASS 5000.17 Build Page 7 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)9,763.9 77.18 228.13 3,946.0 3,876.2 -6,593.5 -4,322.5 5,966,060.58 1,558,163.36 2.84 5,037.89,859.1 77.17 231.69 3,967.2 3,897.4 -6,653.3 -4,393.5 5,966,001.57 1,558,091.76 3.65 5,115.19,954.0 77.13 235.63 3,988.3 3,918.5 -6,708.0 -4,467.9 5,965,947.57 1,558,016.73 4.05 5,195.39,987.0 77.13 236.88 3,995.6 3,925.8 -6,725.9 -4,494.7 5,965,929.95 1,557,989.76 3.69 5,223.9NT7 MFS10,048.2 77.13 239.19 4,009.3 3,939.5 -6,757.5 -4,545.3 5,965,898.92 1,557,938.86 3.68 5,277.710,142.7 77.16 242.84 4,030.3 3,960.5 -6,802.1 -4,625.9 5,965,855.11 1,557,857.81 3.76 5,362.910,237.5 77.18 245.40 4,051.3 3,981.5 -6,842.5 -4,709.0 5,965,815.64 1,557,774.25 2.63 5,450.010,242.0 77.18 245.60 4,052.4 3,982.6 -6,844.3 -4,713.1 5,965,813.86 1,557,770.22 4.31 5,454.2NT6 MFS10,334.1 77.16 249.60 4,072.8 4,003.0 -6,878.5 -4,796.0 5,965,780.52 1,557,686.89 4.24 5,540.510,428.6 77.55 252.49 4,093.5 4,023.7 -6,908.5 -4,883.3 5,965,751.47 1,557,599.36 3.01 5,630.610,522.6 78.04 255.79 4,113.4 4,043.6 -6,933.6 -4,971.6 5,965,727.29 1,557,510.76 3.47 5,721.210,561.0 78.27 256.87 4,121.3 4,051.5 -6,942.5 -5,008.1 5,965,718.79 1,557,474.16 2.82 5,758.5NT5 MFS10,616.9 78.61 258.45 4,132.5 4,062.7 -6,954.2 -5,061.6 5,965,707.65 1,557,420.56 2.84 5,812.910,712.0 78.67 261.23 4,151.2 4,081.4 -6,970.6 -5,153.4 5,965,692.16 1,557,328.63 2.87 5,906.010,807.2 78.58 264.38 4,170.0 4,100.2 -6,982.3 -5,246.0 5,965,681.43 1,557,235.92 3.24 5,999.310,900.1 78.89 268.23 4,188.1 4,118.3 -6,988.2 -5,336.9 5,965,676.50 1,557,144.95 4.08 6,090.310,985.0 79.06 271.14 4,204.4 4,134.6 -6,988.6 -5,420.2 5,965,676.91 1,557,061.67 3.37 6,173.1NT4 MFS10,996.7 79.08 271.54 4,206.6 4,136.8 -6,988.4 -5,431.7 5,965,677.30 1,557,050.23 3.37 6,184.511,091.3 80.11 274.04 4,223.7 4,153.9 -6,983.8 -5,524.6 5,965,682.79 1,556,957.35 2.82 6,276.311,185.3 80.60 277.57 4,239.4 4,169.6 -6,974.4 -5,616.8 5,965,693.13 1,556,865.21 3.74 6,366.911,277.9 80.98 280.60 4,254.3 4,184.5 -6,960.0 -5,707.0 5,965,708.49 1,556,775.18 3.26 6,454.911,375.5 81.46 282.56 4,269.2 4,199.4 -6,940.6 -5,801.5 5,965,728.83 1,556,680.89 2.04 6,546.611,469.9 82.22 285.74 4,282.6 4,212.8 -6,917.8 -5,892.1 5,965,752.62 1,556,590.54 3.43 6,634.128/07/2025 17:46:16COMPASS 5000.17 Build Page 8 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)11,564.7 82.75 287.50 4,295.0 4,225.2 -6,890.9 -5,982.2 5,965,780.42 1,556,500.79 1.92 6,720.511,658.2 83.29 289.86 4,306.3 4,236.5 -6,861.2 -6,070.1 5,965,811.06 1,556,413.19 2.57 6,804.511,752.9 83.83 293.72 4,317.0 4,247.2 -6,826.3 -6,157.5 5,965,846.89 1,556,326.19 4.09 6,887.411,847.7 84.33 296.74 4,326.7 4,256.9 -6,786.1 -6,242.8 5,965,887.97 1,556,241.32 3.21 6,967.611,942.4 85.07 299.73 4,335.5 4,265.7 -6,741.5 -6,325.8 5,965,933.41 1,556,158.77 3.24 7,045.112,037.3 85.81 304.22 4,343.0 4,273.2 -6,691.4 -6,406.1 5,965,984.33 1,556,079.06 4.78 7,119.212,131.9 86.55 307.55 4,349.3 4,279.5 -6,636.1 -6,482.5 5,966,040.44 1,556,003.17 3.60 7,189.012,226.7 87.25 311.86 4,354.5 4,284.7 -6,575.6 -6,555.3 5,966,101.65 1,555,931.00 4.60 7,254.512,321.7 88.12 314.21 4,358.3 4,288.5 -6,510.9 -6,624.7 5,966,167.08 1,555,862.36 2.64 7,316.112,353.0 88.50 315.41 4,359.2 4,289.4 -6,488.8 -6,646.9 5,966,189.39 1,555,840.37 4.01 7,335.7NT3 MFS12,387.5 88.91 316.72 4,360.0 4,290.2 -6,464.0 -6,670.8 5,966,214.43 1,555,816.73 3.98 7,356.612,419.0 89.25 316.46 4,360.5 4,290.7 -6,441.1 -6,692.5 5,966,237.57 1,555,795.30 1.34 7,375.69-5/8" Intermediate Liner12,446.6 89.54 316.24 4,360.8 4,291.0 -6,421.1 -6,711.5 5,966,257.77 1,555,776.43 1.34 7,392.312,541.8 90.58 319.14 4,360.7 4,290.9 -6,350.7 -6,775.6 5,966,328.77 1,555,713.14 3.24 7,448.012,636.9 90.67 321.06 4,359.7 4,289.9 -6,277.7 -6,836.6 5,966,402.38 1,555,652.87 2.02 7,500.412,702.0 90.74 322.93 4,358.9 4,289.1 -6,226.5 -6,876.7 5,966,454.06 1,555,613.35 2.88 7,534.4NT3.2 Top Reservoir12,731.4 90.77 323.77 4,358.5 4,288.7 -6,202.9 -6,894.2 5,966,477.84 1,555,596.03 2.86 7,549.212,826.6 91.44 326.85 4,356.6 4,286.8 -6,124.7 -6,948.4 5,966,556.61 1,555,542.72 3.31 7,594.212,921.4 91.38 329.83 4,354.3 4,284.5 -6,044.0 -6,998.1 5,966,637.75 1,555,493.83 3.14 7,634.513,016.6 91.50 330.50 4,351.9 4,282.1 -5,961.4 -7,045.5 5,966,720.85 1,555,447.32 0.71 7,672.313,111.9 91.47 330.56 4,349.4 4,279.6 -5,878.5 -7,092.3 5,966,804.24 1,555,401.33 0.07 7,709.513,206.8 91.41 330.47 4,347.1 4,277.3 -5,795.9 -7,139.0 5,966,887.31 1,555,355.49 0.11 7,746.613,302.0 91.47 330.44 4,344.7 4,274.9 -5,713.1 -7,185.9 5,966,970.56 1,555,309.44 0.07 7,783.913,397.1 91.69 330.45 4,342.0 4,272.2 -5,630.4 -7,232.9 5,967,053.78 1,555,263.39 0.23 7,821.228/07/2025 17:46:16COMPASS 5000.17 Build Page 9 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)13,492.3 91.69 330.66 4,339.2 4,269.4 -5,547.6 -7,279.6 5,967,137.05 1,555,217.51 0.22 7,858.313,587.4 91.75 330.57 4,336.4 4,266.6 -5,464.7 -7,326.2 5,967,220.35 1,555,171.74 0.11 7,895.313,682.6 91.75 330.40 4,333.5 4,263.7 -5,381.9 -7,373.1 5,967,303.65 1,555,125.71 0.18 7,932.613,777.3 91.72 330.07 4,330.6 4,260.8 -5,299.7 -7,420.2 5,967,386.34 1,555,079.56 0.35 7,970.013,872.5 91.66 330.17 4,327.8 4,258.0 -5,217.2 -7,467.5 5,967,469.29 1,555,033.04 0.12 8,007.813,967.9 91.75 330.26 4,325.0 4,255.2 -5,134.5 -7,514.9 5,967,552.55 1,554,986.52 0.13 8,045.614,062.9 91.66 330.24 4,322.1 4,252.3 -5,052.0 -7,562.0 5,967,635.49 1,554,940.25 0.10 8,083.114,157.8 91.78 329.80 4,319.3 4,249.5 -4,969.9 -7,609.4 5,967,718.07 1,554,893.75 0.48 8,120.914,253.0 91.66 328.98 4,316.4 4,246.6 -4,888.0 -7,657.9 5,967,800.46 1,554,846.15 0.87 8,159.814,348.2 91.75 329.21 4,313.6 4,243.8 -4,806.3 -7,706.7 5,967,882.62 1,554,798.12 0.26 8,199.214,443.6 91.84 328.37 4,310.6 4,240.8 -4,724.8 -7,756.2 5,967,964.69 1,554,749.56 0.88 8,239.114,538.5 91.75 328.52 4,307.6 4,237.8 -4,643.9 -7,805.8 5,968,046.05 1,554,700.75 0.18 8,279.414,633.9 91.72 328.35 4,304.7 4,234.9 -4,562.7 -7,855.7 5,968,127.76 1,554,651.71 0.18 8,319.814,728.3 91.78 328.74 4,301.9 4,232.1 -4,482.2 -7,905.0 5,968,208.78 1,554,603.30 0.42 8,359.714,823.1 91.75 329.01 4,298.9 4,229.1 -4,401.1 -7,954.0 5,968,290.40 1,554,555.17 0.29 8,399.214,918.3 91.81 329.34 4,296.0 4,226.2 -4,319.3 -8,002.7 5,968,372.61 1,554,507.26 0.35 8,438.415,013.0 91.75 329.74 4,293.0 4,223.2 -4,237.8 -8,050.7 5,968,454.61 1,554,460.17 0.43 8,476.915,108.6 91.38 329.59 4,290.4 4,220.6 -4,155.3 -8,098.9 5,968,537.61 1,554,412.75 0.42 8,515.615,204.1 91.47 329.75 4,288.1 4,218.3 -4,072.9 -8,147.1 5,968,620.50 1,554,365.41 0.19 8,554.215,298.6 91.38 329.72 4,285.7 4,215.9 -3,991.3 -8,194.7 5,968,702.56 1,554,318.66 0.10 8,592.315,393.6 91.53 329.77 4,283.3 4,213.5 -3,909.3 -8,242.6 5,968,785.10 1,554,271.65 0.17 8,630.615,489.0 91.60 329.96 4,280.7 4,210.9 -3,826.8 -8,290.5 5,968,868.09 1,554,224.63 0.21 8,668.915,583.8 91.56 330.16 4,278.1 4,208.3 -3,744.7 -8,337.8 5,968,950.69 1,554,178.18 0.22 8,706.615,679.4 91.47 330.04 4,275.6 4,205.8 -3,661.9 -8,385.4 5,969,033.97 1,554,131.44 0.16 8,744.615,773.8 91.44 329.32 4,273.2 4,203.4 -3,580.3 -8,433.1 5,969,115.97 1,554,084.62 0.76 8,782.815,868.9 91.53 328.67 4,270.7 4,200.9 -3,498.9 -8,482.0 5,969,197.90 1,554,036.53 0.69 8,822.228/07/2025 17:46:16COMPASS 5000.17 Build Page 10 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)15,964.1 91.63 328.70 4,268.1 4,198.3 -3,417.6 -8,531.5 5,969,279.71 1,553,987.92 0.11 8,862.216,058.9 91.63 328.53 4,265.4 4,195.6 -3,336.7 -8,580.8 5,969,361.09 1,553,939.43 0.18 8,902.216,153.9 91.63 328.68 4,262.7 4,192.9 -3,255.6 -8,630.3 5,969,442.68 1,553,890.79 0.16 8,942.216,249.1 91.59 329.16 4,260.0 4,190.2 -3,174.2 -8,679.4 5,969,524.65 1,553,842.53 0.51 8,981.816,343.8 91.60 329.16 4,257.4 4,187.6 -3,092.9 -8,728.0 5,969,606.42 1,553,794.85 0.01 9,020.916,438.9 91.69 329.53 4,254.6 4,184.8 -3,011.1 -8,776.4 5,969,688.72 1,553,747.23 0.40 9,059.816,534.2 91.50 329.57 4,252.0 4,182.2 -2,929.0 -8,824.7 5,969,771.32 1,553,699.81 0.20 9,098.516,628.9 91.56 330.04 4,249.4 4,179.6 -2,847.1 -8,872.3 5,969,853.65 1,553,653.04 0.50 9,136.616,724.0 91.50 329.46 4,246.9 4,177.1 -2,765.0 -8,920.2 5,969,936.21 1,553,606.04 0.61 9,175.016,819.7 91.66 329.31 4,244.3 4,174.5 -2,682.7 -8,968.9 5,970,019.07 1,553,558.16 0.23 9,214.116,914.7 91.56 329.49 4,241.6 4,171.8 -2,601.0 -9,017.3 5,970,101.26 1,553,510.70 0.22 9,252.917,010.0 91.72 328.98 4,238.9 4,169.1 -2,519.1 -9,066.0 5,970,183.66 1,553,462.80 0.56 9,292.117,105.2 91.72 328.85 4,236.0 4,166.2 -2,437.6 -9,115.1 5,970,265.62 1,553,414.54 0.14 9,331.717,200.5 91.57 329.07 4,233.3 4,163.5 -2,356.0 -9,164.3 5,970,347.74 1,553,366.27 0.28 9,371.417,295.4 91.60 328.92 4,230.7 4,160.9 -2,274.7 -9,213.1 5,970,429.53 1,553,318.26 0.16 9,410.717,390.3 91.57 328.61 4,228.0 4,158.2 -2,193.6 -9,262.3 5,970,511.15 1,553,269.92 0.33 9,450.517,485.6 91.63 328.65 4,225.4 4,155.6 -2,112.2 -9,311.9 5,970,592.99 1,553,221.18 0.08 9,490.617,580.6 91.57 328.71 4,222.7 4,152.9 -2,031.1 -9,361.3 5,970,674.60 1,553,172.68 0.09 9,530.517,675.6 91.72 329.44 4,220.0 4,150.2 -1,949.6 -9,410.1 5,970,756.58 1,553,124.72 0.78 9,569.817,770.6 91.66 329.30 4,217.2 4,147.4 -1,867.9 -9,458.5 5,970,838.81 1,553,077.17 0.16 9,608.717,866.0 91.81 329.55 4,214.3 4,144.5 -1,785.8 -9,507.0 5,970,921.37 1,553,029.54 0.31 9,647.617,961.0 91.75 329.27 4,211.3 4,141.5 -1,704.1 -9,555.3 5,971,003.57 1,552,982.10 0.30 9,686.418,056.3 91.72 329.28 4,208.5 4,138.7 -1,622.2 -9,604.0 5,971,086.02 1,552,934.24 0.03 9,725.618,150.8 91.81 329.52 4,205.5 4,135.7 -1,540.9 -9,652.0 5,971,167.77 1,552,887.03 0.27 9,764.218,245.8 91.72 329.89 4,202.6 4,132.8 -1,458.9 -9,699.9 5,971,250.20 1,552,840.02 0.40 9,802.518,341.1 91.60 330.09 4,199.9 4,130.1 -1,376.4 -9,747.6 5,971,333.23 1,552,793.20 0.24 9,840.628/07/2025 17:46:16COMPASS 5000.17 Build Page 11 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueMD(usft)Inc(°)Azi (azimuth)(°)N/S(usft)E/W(usft)Northing(usft)TVDSS(usft)Easting(usft)SurveyTVD(usft)DLeg(°/100usft)V. Sec(usft)18,436.5 91.53 330.09 4,197.3 4,127.5 -1,293.8 -9,795.1 5,971,416.35 1,552,746.53 0.07 9,878.518,531.5 91.59 330.85 4,194.7 4,124.9 -1,211.2 -9,841.9 5,971,499.42 1,552,700.61 0.80 9,915.718,610.6 91.60 330.76 4,192.5 4,122.7 -1,142.1 -9,880.5 5,971,568.90 1,552,662.72 0.11 9,946.318,617.0 91.60 330.76 4,192.3 4,122.5 -1,136.5 -9,883.6 5,971,574.48 1,552,659.68 0.00 9,948.74-1/2" Production Liner18,634.0 91.60 330.76 4,191.8 4,122.0 -1,121.7 -9,891.9 5,971,589.39 1,552,651.53 0.00 9,955.3Projection to TDVertical Depth(usft)Measured Depth(usft)CasingDiameter(")HoleDiameter(")NameCasing Points20" Conductor Casing128.0128.020 2013-3/8" Surface Casing2,362.42,758.013-3/8 169-5/8" Intermediate Liner4,360.512,419.09-5/8 12-1/44-1/2" Production Liner4,192.318,617.04-1/2 8-1/228/07/2025 17:46:16COMPASS 5000.17 Build Page 12 Project:Company:Local Co-ordinate Reference:TVD Reference:Site:Santos NAD27 ConversionPikkaNDBSantos LtdSantos Definitive Survey ReportWell:Wellbore:B-11NDB-011Survey Calculation Method:Minimum CurvatureParker 272 @ 69.8usftDesign:NDB-011Database:EDMMD Reference:Parker 272 @ 69.8usftNorth Reference:Well B-11TrueMeasuredDepth(usft)VerticalDepth(usft)DipDirection(°)Name LithologyDip(°)Formations10,242.0 4,052.4 NT6 MFS 0.0012,702.0 4,358.9 NT3.2 Top Reservoir 0.001,811.0 1,736.5 Middle Shradder Bluff 0.003,226.0 2,529.9 Tuluvak Sans 0.009,734.0 3,939.4 NT8 MFS 0.001,049.0 1,040.5 Upper Shradder Bluff 0.001,418.0 1,392.0 Base Permafrost Transition 0.006,024.0 3,136.8 Seabee 0.009,987.0 3,995.6 NT7 MFS 0.004,649.0 2,841.5 TS_790 0.002,388.0 2,154.8 MCU 0.0010,985.0 4,204.4 NT4 MFS 0.002,999.0 2,463.0 Tuluvak Shale 0.0010,561.0 4,121.3 NT5 MFS 0.0012,353.0 4,359.2 NT3 MFS 0.009,436.0 3,873.3 Nanushuk 0.00MeasuredDepth(usft)VerticalDepth(usft)+E/-W(usft)+N/-S(usft)Local CoordinatesCommentDesign Annotations18,634.0 4,191.8 -9,891.9-1,121.7 Projection to TDApproved By:Checked By:Date:28/07/2025 17:46:16COMPASS 5000.17 Build Page 1314th August 2025 Attachment 4 NDB-0119632’ MD / 3917’ TVD9-5/8” Stage 1 Top of Cement Santos and Baker Hughes Confidential Page 1 © 2018 Baker Hughes, LLC - All rights reserved. SSoundTrak Top of Cement Evaluation Report Well Name: NDB-011 Field Name: Pikka Company: Santos Rig: Parker 272 Region: North Slope State: Alaska Country: United States Prepared by: GCEA Version: Preliminary Report Santos and Baker Hughes Confidential Page 2 Contents Baker Hughes Legal Disclaimer ................................................................................................................................................................ 3 Executive Summary ........................................................................................................................................................................................... 4 Appendix I: Methodology of Cement Evaluation .........................................................................................................................6 Santos and Baker Hughes Confidential Page 3 Baker Hughes Legal Disclaimer IN MAKING INTERPRETATIONS OF LOGS OUR EMPLOYEES WILL GIVE CUSTOMERS THE BENEFIT OF THEIR BEST JUDGMENT. BUT SINCE ALL INTERPRETATIONS ARE OPINIONS BASED ON ELECTRICAL OR OTHER MEASUREMENTS, WE CANNOT, AND WE DO NOT GUARANTEE THE ACCURACY OR CORRECTNESS OF ANY INTERPRETATION. WE SHALL NOT BE LIABLE OR RESPONSIBLE FOR ANY LOSS, COST, DAMAGES, OR EXPENSES WHATSOEVER INCURRED OR SUSTAINED BY THE CUSTOMER RESULTING FROM ANY INTERPRETATION MADE BY ANY OF OUR EMPLOYEES. Santos and Baker Hughes Confidential Page 4 Executive Summary The 9 5/8” liner was logged for Top of Cement (TOC) with the 6 ¾” SoundTrak LWD Acoustic tool while pulling out of the hole after drilling the 8 ½” hole section. The cement evaluation log was performed with the bottom hole assembly inside casing above the 9 5/8” shoe. The up-log depth ranged from 12,350 ft MD to 8,686 ft MD. This TOC log was performed at ~1,000 to ~1,200 feet per hour. The parameters used to log the cement were 550 GPMs and 100 RPMs. The LWD Acoustic parameter file was optimized for TOC acquisition only to reduce logging time. Interpretation Summary Observations for the zones of interest are defined below: - Partial bond possible from 8,700 ft MD to 8,766 ft MD. - Partial bond possible from 8,869 ft MD to 8,906 ft MD. - Partial bond possible from 8,932 ft MD to 8,942 ft MD. - Partial bond possible from 9,188 ft MD to 9,202 ft MD. - Partial bond possible from 9,330 ft MD to 9,344 ft MD. - Partial bond possible from 9,432 ft MD to 9,442 ft MD. - Partial bond possible from 9,554 ft MD to 9,570 ft MD. - Partial bond possible from 9,580 ft MD to 9,598 ft MD. - Good to partial bonds observed below 9632 ft MD. Please see the following screen shot(s) covering the zones of interest. Full TOC logs and digital data are available for further discussion. Santos and Baker Hughes Confidential Page 5 Good to partial bonds observed below 9632 ft MD Partial bonds observed sporadically from 8,700 ft to 9,598 ft MD. Santos and Baker Hughes Confidential Page 6 Appendix I: Methodology of Cement Evaluation Traditional Wireline Acoustic tool’s CBL measurement principle relies on detecting and measuring first “casing ringing” amplitude reflected from the casing wall. The idea is that free pipe (with cement absence) would “ring” freely creating high Casing Ringing Amplitude, whereas well cemented casing would result in dampened first arrival and thus indicate well cemented pipe. Thus, the same methodology is applied with LWD. Figure 4: General TOC log example with LWD Current traditional offerings of LWD Acoustic tool for cement quality evaluation is to detect Top of Cement in wells where running Wireline could be challenging for various reasons and Top of Cement or TOC detection can be done in the same drilling run. However, it is not a replacement for quantitative cement evaluation tools. Note however, that the T x R spacing (10.7 ft) for the LWD SoundTrak tool is over 3.5 times longer than the spacing of traditional Wireline CBL tool (3 ft), so the casing amplitude has a much higher attenuation, especially across well bonded intervals. Careful quality control must be carried out to validate the data. Santos and Baker Hughes Confidential Page 7 Additionally, Cement Evaluation with the LWD SoundTrak tool is recommended in scenarios where the cement slurry density is greater than 14 ppg. Slurries below 14 ppg would typically be classified as light-weight cements and sometimes can cause uncertainty in cement evaluation. However, more integrated interpretation would be required to reduce that uncertainty and confirm proper cement presence. Furthermore, adding this service can increase operational efficiency since it can be done in the same drilling trip and logging speed for TOC detection and CBL evaluation can be as high as ~1000 - 1300 ft/hr still providing good data quality. With combination semblance (SV), Delta-T Compressional, and the correlation image; the TOC can be detected in real-time (for final analysis it is recommended to compare real-time data with the memory data for access to the full waveforms). Good alignment between real-time and memory TOC can be seen in the following example. Figure 7: LWD capability of Real-Time Top of Cement acquisition displayed in WellLink RT viewer (left) versus Memory TOC log (right) on NDB-011. Page 1 of 2 Cement - NDB-011 Intermediate Casing Cement Intermediate Casing Cement, Casing, 7/2/2025 11:00 Type Casing Cementing Start Date 7/2/2025 Cementing End Date 7/3/2025 Wellbore Original Hole String Intermediate Liner, 12,419.0ftKB Cementing Company Halliburton Energy Services Evaluation Method Cement Bond Log Cement Evaluation Results 1st Stage Log: partial bonds observed sporadically from 8,700' to 9,598' MD. Good to partial bonds observed below 9632 ft MD Comment 1st Stage 9-5/8” Cement Job - Pump 5 bbls water & pressure test cement lines to 1,000 psi low 4,500 psi High. - Pump 80 bbl 12.5 ppg Tuned Spacer with Surfactant B and Musol A - (65 gallons each) downhole at 4 bpm with 525 psi. - Release bottom pump down plug, chase with 15.3 ppg Versacem Tail Cement Type I/II at 4 bpm, initial circulating pressure 450 psi. - Continue to chase with 15.3 ppg Versacem Tail Cement Type I/II, pump total of 313 bbls at average of 4 bpm, 440 psi, excess volume 56%. - Flush lines with 20 bbl. water to cuttings box. - Release top pump down plug. - Perform displacement with rig pumps, displace with 755 bbls 11.0 ppg OBM at 4bpm, ICP 301 psi, FCP 784 psi. - Bottom pump down dart latch up confirmed at 43 bbls displaced. - Continue to displace with 11.0 ppg OBM, reduce rate to 3 bpm for final 50 bbls of displacement. Final circulating pressure 727psi. pressured up 500 psi over FCP 1,300 psi held 5 min, bled off checked floats. Floats held. - Total displacement volume 755 bbls (measured by strokes at 96% pump efficiency). CIP @ 16:04 hrs. - No Losses during cement job or displacement. 2nd Stage 9-5/8” Cement Job Conduct 2nd stage cementing of 9-5/8”, 47#, Intermediate casing by open hole annulus through Archer cementing tool as follows: - Fill lines with water and test 1,000 psi low, 4,500 psi high. - Mix and pump 80 bbls of 12.5 ppg Mud Flush at 4 bpm, ICP 365 psi, FCP 250. - Mix and pump 80 bbls of 13.5 Tuned Spacer at 4 bpm, ICP 230 psi. FCP 220 psi, 0 bbls lost during spacer pumping. - Mix and pump 285 bbls of 15.3 ppg Versacem Type I-II Tail cement at 4 bpm, ICP 390 psi, FCP 440 psi, No losses observed. - Excess Volume 144% (1293 sacks, yield 1.237 cu ft/sk). - Displace with 11.0 ppg OBM using rig pumps to Archer Stage Collar. - Displace cement with 96.5 bbls at 5 bpm, 218 psi ICP, 605-8 psi FCP. Slowed to 3bpm for final 16 bbls of displacement. No Losses. CIP @ 07:48 hrs. 1, 8,976.0-12,427.0ftKB Top Depth (ftKB) 8,976.0 Bottom Depth (ftKB) 12,427.0 Full Return? Yes Vol Cement Ret (bbl) 0.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 727.0 Plug Bump Pressure (psi) 1,300.0 Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) 12,337.0 Tag Method Drilling BHA Depth Plug Drilled Out To (ftKB) 12,350.0 Drill Out Diameter (in) 8 1/2 Drill Out Date 7/7/2025 Spacer Fluid Type Spacer Fluid Description Tuned Spacer w/ 4# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) 8,976.0 Percent Excess Pumped (%) Yield (ft³/sack) 2.24 Mix H20 Ratio (gal/sack) 13.09 Free Water (%) 0.00 Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Tail (Type I/II) Amount (sacks) 1,430 Class Type I/II Volume Pumped (bbl) 313.0 Estimated Top (ftKB) 8,976.0 Percent Excess Pumped (%) 56.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.58 Free Water (%) 0.00 Density (lb/gal) 15.30 Plastic Viscosity (cP) 129.0 Thickening Time (hr) 7.00 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 12.50 2, 2,578.0-4,745.0ftKB Top Depth (ftKB) 2,578.0 Bottom Depth (ftKB) 4,745.0 Full Return? Yes Vol Cement Ret (bbl) 60.0 Top Plug? No Bottom Plug? No Initial Pump Rate (bbl/min) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 4 Final Pump Pressure (psi) 608.0 Plug Bump Pressure (psi) Pipe Reciprocated? No Reciprocation Stroke Length (ft) Reciprocation Rate (spm) Pipe Rotated? No Pipe RPM (rpm) Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in) Drill Out Date Mud Flush Spacer Fluid Type Mud Flush Spacer Fluid Description Mud Flush Spacer w/ 8# Red Dye, 65 gal Surf B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) 2,578.0 Percent Excess Pumped (%) Yield (ft³/sack) 2.22 Mix H20 Ratio (gal/sack) 12.89 Free Water (%) Density (lb/gal) 12.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Page 2 of 2 Cement - NDB-011 Intermediate Casing Cement Tuned Spacer Fluid Type Tuned Spacer Fluid Description Tuned Spacer w/ 4# Red Dye, 65 gal Surf-B & Musol A Amount (sacks) Class Volume Pumped (bbl) 80.0 Estimated Top (ftKB) 2,578.0 Percent Excess Pumped (%) Yield (ft³/sack) 1.91 Mix H20 Ratio (gal/sack) 10.72 Free Water (%) Density (lb/gal) 13.50 Plastic Viscosity (cP) Thickening Time (hr) 1st Compressive Strength (psi) CmprStr Time 1 (hr) Tail Fluid Type Tail Fluid Description Versacem Tail (Type I/II) Amount (sacks) 1,293 Class I/II Volume Pumped (bbl) 285.0 Estimated Top (ftKB) 2,578.0 Percent Excess Pumped (%) 144.0 Yield (ft³/sack) 1.24 Mix H20 Ratio (gal/sack) 5.57 Free Water (%) Density (lb/gal) 15.30 Plastic Viscosity (cP) 121.0 Thickening Time (hr) 6.50 1st Compressive Strength (psi) 500.0 CmprStr Time 1 (hr) 18.50 1For Internal Use onlyTOP HC NT8NDB-011 Intermediate Cement Consideration 2For Internal Use onlyOnly 3 continuous ft TVDTop of possible HC accumulation in NT8 (TVD)5 ft 3For Internal Use onlyMeasured DepthTop of possible HC accumulation in NT8 MDTop of potential HC. 9791 ft MD Well: NDB-011 NanushukNT8 MFSNT7 MFSNT6 MFSNT5 MFSNT4 MFSNT3 MFSZone TOPS.TOPS_PROC_3Well Schematic 12302LNR_HNGR200Clay Volume GR_2 GAPI0200 VSH_3 V/V01 VLAM_1 01 9500975010000102501050010750110001125011500117501200012250MD DEPTHFEET1 : 12003850390039504000405041004150420042504300TVDSS TVDSSFEET3900395040004050410041504200425043004350TVDSS TVDFEETResistivity RT_2 OHMM0.2 200 RSAND_TS_1 OHMM0.2 200 RACSHM_2 OHM.M0.2 200 Fm Por WR.RHOB G/C31.65 2.65 WR.NPHI V/V0.6 0 SURVEY.INCL DEG0100 BH Rugosity WR.DRHO G/C3-0.25 0.25 WR.CALI IN515 LWD_RM_REAM12427.CALCM IN515 EXP_EVAL.BADHOLE 10 0 WR.BITSIZE IN515 Fm Por PHIT_2 V/V0.5 0 PHIT_D_1 V/V0.5 0 Fm Sw SWT V/V10 SWE V/V10 Sand Por PHITLAM_1 V/V0.5 0 badhole V/V10 0 Sand Sw SWTLAM_1 V/V10 SWELAM_1 V/V10 NTG < 50 ntglt50 V/V10 Pay*NTG*KCalc Perm MD0.1 1000 Perm MD0.1 1000 NET PAY_PAY_1 LOGICAL15 0 NTG_1 V/V01 NET_PAY_SAND_ACCUM_1 FT0 5000 NET_PORH_PAY_SAND_ACCUM_1 FRACTION0 5000 NTG_ACCUM_1 FRACTION0 5000 Nanushuk9734NT8 MFS9987NT7 MFS10242NT6 MFS10561NT5 MFS10985NT4 MFS12183NT3 MFSZone TOPS_ACTUAL.TOPS_ACTUAL_1Zone TOPS.TOPS_PROC_3 Top Nan 3.2 @12,542' MD Tuluvak Sand @ 3,226' MD Top Nanushuk @ 9,436' MD NDB-011 Well Schematic (Potential P&A) 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2,578' MD 13-3/8" 68 ppf L-80 Surface Casing2,758' MD 9-5/8", 47ppf L-80 Production Liner12,419' MD 4-½”, 12.6ppf P-110S Production Liner 18,617' MD 4-½” Liner Hanger/ Top Packer12,228' MD 69.50' RKB – Bottom Flange August 18th, 2025 9-5/8" Tieback2,578' MD 9-5/8" Cflex Stage Tool (101' MD below TS790) 4,750' MD 9-5/8" Primary TOC (159' MD/35' TVD above top HC)9,632' MD 8-½” Openhole TD TD 18,634' MD Cement Plug #1: Down squeeze 4-½” liner and 9-5/8" casing volume to cement retainer depth Cement Plug #3 & 4: Cement Plugs in Accordance with AOGCC regulations to isolate Tuluvak hydrocarbon bearing formation and surface cement plug. 1 Dewhurst, Andrew D (OGC) From:Williams, Rob (Rob) <Rob.Williams@santos.com> Sent:Monday, 18 August, 2025 14:00 To:Dewhurst, Andrew D (OGC) Cc:McLellan, Bryan J (OGC); Wallace, Chris D (OGC); AOGCC Permitting (CED sponsored); Leahy, Scott (Scott); Tirpack, Robert (Robert); Senden, Robert (Ty); Smith, Travis (Travis); Atherton, Michaela (Michaela) Subject:Pikka NDB-011 PTD(225-048) Variance Request Attachments:NDB-011 PTD 225-048 Variance Request.zip Hi Andy, I understand from Scott Leahy that you requested a variance request for the NDB-011 PTD (225-048) well in relation to the Ʊrst stage cementing of the intermediate 9-5/8” liner. Please Ʊnd attached the subject variance request . Please let me know if you have any questions or if you require any further information. Thanks and regards, Rob Williams Senior Drilling Engineer m: +1 907 343 9737 | e: rob.williams@santos.com Santos.com | Follow us on LinkedIn, Facebook and X Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 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. 1 Dewhurst, Andrew D (OGC) From:Senden, Robert (Ty) <Ty.Senden@santos.com> Sent:Thursday, 14 August, 2025 16:32 To:Dewhurst, Andrew D (OGC) Cc:Leahy, Scott (Scott); McLellan, Bryan J (OGC); Wallace, Chris D (OGC); Miller, Nicklaus (Nick) Subject:RE: Pikka NDB-011 Frac Sundry (325-442) Andy, Got your email. We’ll get the variance over ASAP. Ty From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, August 14, 2025 4:25 PM To: Senden, Robert (Ty) <Ty.Senden@santos.com> Cc: Leahy, Scott (Scott) <Scott.Leahy@santos.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: ![EXT]: FW: Pikka NDB-011 Frac Sundry (325-442) Ty, I sent an email to Scott Leahy and received an out-of-office reply message. Please see below: Andy From: Dewhurst, Andrew D (OGC) Sent: Thursday, 14 August, 2025 16:22 To: Leahy, Scott (Scott) <scott.leahy@santos.com> Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Pikka NDB-011 Frac Sundry (325-442) Scott, I am completing my review of the Pikka NDB-011 frac sundry. x As you noted in the application, the cementing of the Ʊrst stage of the intermediate casing did not reach the required depth (100’ TVD above top of Nanushuk Pool as per condition of approval #10 on the PTD). This frac sundry will need a variance request similar to that done for the NDBi-036 frac sundry. 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. 2 x Also, thank you for the graphic showing the vertical separation of the o Ưset wells. This greatly helps with the area of review. I’d just like to conƱrm that going forward, well intersections that are completely outside the pool (in this case, NDBi-044, NDB-048, and NDBi-050/PB1) can be left out of the list of AOR wells evaluated for mechanical integrity. Please continue to show them on the vertical separation graphic though. Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-011 (PTD No. 225-048; Sundry No. 325-442) Paragraph Sub-Paragraph Section Complete? AOGCC Page 1 August 19, 2025 (a) Application for Sundry Approval (a)(1) Affidavit Provided with application. A.Dewhurst 13AUG25 (a)(2) Plat Provided with application. A.Dewhurst 13AUG25 (a)(2)(A) Well location Provided with application. A.Dewhurst 13AUG25 (a)(2)(B) Each water well within ½ mile None: There are no wells used for drinking water purposes known to lie within ½ mile of the surface location of Pikka NDB-011. There are no subsurface water rights or temporary subsurface water rights within 14 miles of the surface location of Pikka NDB-011. A.Dewhurst 13AUG25 (a)(2)(C) Identify all well types within ½ mile Provided with application. A.Dewhurst 13AUG25 (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 AOGCC’s Well History File 223-076, p. 101-107 of Sundry Application 323-591). Pickett Plot well-log analyses were performed on three wells within the unit that have wireline log coverage from surface through the fracturing interval: Colville River 1, Till 1, and Pikka DW-02. Estimated salinity values for clean, porous 100% water-saturated sands beneath the base of the permafrost layer in these three wells are: Colville River 1 (PTD 192-153) ~20,000 mg/l between 1,400 and 2,000’ MD (-1,354’ to 1,954' TVDSS; base of permafrost 1,350’ MD (-1,313’ TVDSS)); Till 1 (PTD 193-004) 16,700 to ~23,000 mg/l between 1,400’ and 1,500’ MD (-1,463’ to -1,363’ TVDSS; base of permafrost 1,350’ MD (-1,305’ TVDSS)); and DW-02 (PTD 223-039) ~21,500 mg/l between 1,550’ and 1,650’ MD (-A.Dewhurst 13AUG25 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-011 (PTD No. 225-048; Sundry No. 325-442) Paragraph Sub-Paragraph Section Complete? AOGCC Page 2 August 19, 2025 1,408’ to -1,486’ TVDSS; base of permafrost ~1,170’ MD (~-1,080’ TVDSS)). (a)(4) Baseline water sampling plan None required. A.Dewhurst 13AUG25 (a)(5) Casing and cementing information Provided with application. Proposed schematic attached, as built not generated to date. TOC included. CDW 08/13/2025 (a)(6) Casing and cementing operation assessment Surface cement 13-3/8” casing shoe at 2758 ft. 475 bbl pumped with full returns and 160 bbl returned to surface Two stage cement job in 9-5/8”liner. 1st stage: 56% excess. 313 bbl pumped, no losses reported. Estimated (volume) top of 8976 ft. Santos 9-5/8” SoundTrak TOC 9632 ft with partial bonding sporadically from 8700 ft to 9598 ft.. Packer set at 12269 ft. 13025 ft shallowest frac sleeve. SoundTrak conservatively shows good cement at area of interest so no cement concerns. 2nd stage bottom 4750 ft Cflex stage tool. estimated top 2578 ft (liner top). 145% excess volume, 285 bbl cement pumped. Job went as planned. CDW 08/13/2025 (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.) No. TOC for the intermediate casing is 9,632' MD, which is below the top of the Nanushuk Pool and 144’ below the depth required by the PTD Condition of Approval #10. Santos has requested a variance. Recommend approving variance as the hydrocarbon pay is adequately isolated with the current cement. A.Dewhurst 13AUG25 (a)(6)( B) Each hydrocarbon zone is isolated Yes. A.Dewhurst 18AUG25/ 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-011 (PTD No. 225-048; Sundry No. 325-442) Paragraph Sub-Paragraph Section Complete? AOGCC Page 3 August 19, 2025 The Tuluvak hydrocarbon zone is adequately isolated by the 2nd stage of the intermediate liner cement job. The multiple Nanushuk hydrocarbon zones within the Nanushuk Oil Pool are isolated by the 1st stage of the intermediate liner cement job. Because TOC is 44 below the top of the pool, Santos has requested a variance. For details, see above. (a)(7) Pressure test: information and pressure-test plans for casing and tubing installed in well Provided with application. 4300 psi MITIA planned, 5500 psi MITT plan. CDW 08/13/2025 (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head Provided with application. 10K psi frac tree max. frac. Pressure 8800 psi. Pump knock out 7800 and GORV 8500 psi., lines test 9200 psi. CDW 08/13/2025 (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 700’ true vertical thickness (TVT) of claystone, shale and volcanic tuff assigned to the Seabee Formation having an estimated fracture gradient of 13.7 ppg EMW (0.71 psi/ft). Fracturing Zone: Perforated zone lies within a subdivision of the Nanushuk Formation 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 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: About 900’ TVT of Lower Torok (Hue) shales and interbedded siltstones with an estimated fracture gradient of 13.3 ppg EMW (0.69 psi/ft). A.Dewhurst 13AUG25 (a)(10) Location, orientation, report on mechanical condition of each well that may transect the confining zones and It is highly unlikely that any of the wells or wellbores within a ½-mile radius will interfere with hydraulic fracturing fluids A.Dewhurst 18AUG25/ 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-011 (PTD No. 225-048; Sundry No. 325-442) Paragraph Sub-Paragraph Section Complete? AOGCC Page 4 August 19, 2025 sufficient information to determine wells will not interfere with containment of hydraulic fracturing fluid within ½ mile of the proposed wellbore trajectory from this operation because of cement isolation and / or separation distance. There are 11 wells Santos has provided cementing and isolation details for within ½ mile of Pikka NDB-011 that penetrate the confining intervals. AOGCC evaluated all wells that may transect the confining zones within the Pikka NDB-011 Area of Review. Q3 etc abandoned. NDB wells active, logs provided, liner production zone uncemented but confined with packers in cemented casing shoe etc. . CDW 08/14/2025 (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 Yes. The operator has identified one potential fault through seismic data within a ½-mile radius of Pikka NDB-011. Though the well was drilled through the fault location, there was no evidence from drilling or logs that suggest offset. It is unlikely that this fault will interfere with containment of the injected fracturing fluids; however, if there are indications that a fracture has intersected a fault or natural-fracture interval during frac operations, the operator will go to flush and terminate the stage immediately. A.Dewhurst 13AUG25 (a)(12) Proposed program for fracturing operation Provided with application. CDW 08/13/2025 (a)(12)(A) Estimated volume Provided with application. 20,000 bbl total dirty vol. 2.52 M lb total proppant. CDW 08/13/2025 (a)(12)(B) Additives: names, purposes, concentrations Provided with application. CDW 08/13/2025 (a)(12)(C) Chemical name and CAS number of each Provided with application. Schlumberger, Tracerco disclosures provided. CDW 08/13/2025 (a)(12)(D) Inert substances, weight or volume of each Provided with application. CDW 08/13/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-011 (PTD No. 225-048; Sundry No. 325-442) Paragraph Sub-Paragraph Section Complete? AOGCC Page 5 August 19, 2025 (a)(12)(E) Maximum treating pressure with supporting info to determine appropriateness for program Simulation shows max surface pressure 5091 psi. Max. 8800 psi allowable treating pressure. Max pressure is 7800 psi to 8500 psi to Pump shutdown. With 3800 psi back pressure IA (IA popoff set 4100 psi), max tubing differential allowed is 5000 psi. CDW 08/13/2025 (a)(12)(F) Fractures – height, length, MD and TVD to top, description of fracturing model Provided with application. The maximum anticipated half-length of the induced fractures is 457’ according to the Operator’s computer simulation. Computer simulation indicates the maximum anticipated height of the induced fractures will be 296’, so it is unlikely that induced fractures will penetrate into the overlying confining zone. Detailed depths are provided in the application. A.Dewhurst 13AUG25 (a)(13) Proposed program for post-fracturing well cleanup and fluid recovery Well cleanout and flowback procedure provided with application. No disposal identified CDW 08/13/2025 (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 08/13/2025 (c) Fracturing string (c)(1) Packer >100’ below TOC of production or intermediate casing Santos 9-5/8” SoundTrak TOC 9632 ft. Packer set at 12269 ft. 13025 ft shallowest sleeve. SoundTrak conservatively shows good cement at area of interest so no cement concerns. CDW 08/13/2025 (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 08/13/2025 (d) Pressure relief valve Line pressure <= test pressure, remotely controlled shut-in device MAWP 8800 psi. Estimated frac pressure 8091 psi. 9200 psi line pressure test, pump knock out 7800 psi with max. global kickout 8500 psi. IA PRV set as 4100 psi. CDW 08/13/2025 (e) Confinement Frac fluids confined to approved formations Provided with application. CDW 08/13/2025 20 AAC 25.283 Hydraulic Fracturing Application – Checklist Pikka NDB-011 (PTD No. 225-048; Sundry No. 325-442) Paragraph Sub-Paragraph Section Complete? AOGCC Page 6 August 19, 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 08/13/2025 (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 08/13/2025 (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post-frac water sampling plan Not required (see Section (a)(3), above). A.Dewhurst 13AUG25 (k) Confidential information Clearly marked and specific facts supporting nondisclosure Non-confidential well. A.Dewhurst 13AUG25 (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. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PIKKA NDB-011 JBR 08/04/2025 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:2 Tested BOP's with 4-1/2" & 5" TJ's. Tested all LEL and H2s, Cellar H2s needed filter replaced it was totally plugged off and no gas could get to sensor. Tested pvt's and flow paddle. No other failures or issues. Test Results TEST DATA Rig Rep:Russell WoodsOperator:Oil Search (Alaska), LLC Operator Rep:Brian Buzby Rig Owner/Rig No.:Parker 272 PTD#:2250480 DATE:7/5/2025 Type Operation:DRILL Annular: 250/3600Type Test:BIWKLY Valves: 250/3600 Rams: 250/3600 Test Pressures:Inspection No:bopSTS250707150552 Inspector Sully Sullivan Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 4.5 MASP: 1521 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 1 P Inside BOP 1 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 4-1/2x 7" vari P #2 Rams 1 blinds P #3 Rams 1 9-5/8"NT #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 1 3-1/8"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3050 Pressure After Closure P2050 200 PSI Attained P23 Full Pressure Attained P68 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 FP FPH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P26 #1 Rams P5 #2 Rams P5 #3 Rams P5 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 #3 Rams not tested; casing rams not needed prior to next test -- jbr Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Rob Williams Senior Drilling Engineer Oil Search Alaska, LLC 601 W 5th Avenue Anchorage, AK, 99501 Re: Pikka Field, Nanushuk Oil Pool, NDBi-011 Oil Search Alaska, LLC Permit to Drill Number: 225-048 Surface Location: 2,479’ FSL, 2,555’ FWL, Sec 4, T11N, R6E, UM Bottomhole Location: 1,347’ FSL, 2,060’ FEL, Sec 11, T11N, R6E, UM Dear Mr. Williams: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. Proposed dry ditch sample interval from Attachment 9 accepted with modification of Ivishak (not to exceed 30'). This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this th day of June 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.06 08:57:23 -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: 18,637' TVD: 4,191' 4a. Location of Well (Governmental Section): 7. Property Designation: ADL 392984, Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 9th June 2025 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 6,870' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 69.78' 15. Distance to Nearest Well Open Surface: x- 422,520.84 y- 5,972,860.23 Zone- 4 22.78' to Same Pool: 390' 16. Deviated wells: Kickoff depth: 347 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 92 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 2,785' Surface Surface 2,785' 2,377' 12-1/4" 9-5/8" 47# L-80 HYD563 9,832' 2,635' 2,303' 12,467' 4,361' Tie Back 9-5/8" 47# L-80 HYD563 2,635' Surface Surface 2,635' 2,303' 8-1/2" 4-1/2" 12.6# P-110S HYD563 6,313' 12,317' 4,357' 18,630' 4,191' Tubing 4-1/2" 12.6# P-110S HYD563 12,317' Surface Surface 12,317' 4,357' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Rob Williams Rob Williams Contact Email:rob.williams@santos.com Senior Drilling Engineer Contact Phone:1-907-343-9737 Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval: If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Pikka NDB-011 Pikka/Nanushuk Oil Pool N/A 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 1,521 1,404’ FSL, 1,054’ FWL, Sec 8, T11N, R6E, UM 1,347’ FSL, 2,060’ FEL, Sec 11, T11N, R6E, UM LONS 19-003 601 W Fifth Avenue, Anchorage, AK 99501-6301 Oil Search Alaska, LLC 2,479’ FSL, 2,555’ FWL, Sec 4, T11N, R6E, UM 392985, 393023, 393022, 393021 3109 18. Casing Program:Top - Setting Depth - BottomSpecifications 1,955 GL / BF Elevation above MSL (ft): Cement Volume MDSize Plugs (measured): (including stage data) Grouted to surface See attachment 6 See attachment 6 Effect. Depth MD (ft): Effect. Depth TVD (ft): Uncemented 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 1 Class: os N s No s N o schhhh s s chhh chhhhhh 277U o well is G S S 20 AA SS S s Nos No S G y s No essss Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 1st May 2025 By Grace Christianson at 9:31 am, May 07, 2025 225-048 DSR-5/8/25A.Dewhurst 05JUN25 50-103-20916-00-00 BJM 6/5/25 See attached conditions of approval. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.06 08:57:38 -08'00' 06/06/25 06/06/25 RBDMS JSB 061025 NDB-011 (PTD 225-048) WĞƌŵŝƚƚŽƌŝůůŽŶĚŝƟŽŶƐŽĨApproval 1.ŝǀĞƌƚĞƌǁĂŝǀĞƌƌĞƋƵĞƐƚ ŝƐĂƉƉƌŽǀĞĚŽŶƚŚĞĐŽŶĚŝƟŽŶƚŚĂƚƚŚĞƐƵƌĨĂĐĞŚŽůĞŵĂLJďĞĚƌŝůůĞĚŶŽ ĚĞĞƉĞƌƚŚĂŶ250’ TVD ďĞůŽǁƚŚĞDh͘ 2./ŶŝƟĂůKWƚĞƐƚƚŽϱϬϬϬƉƐŝ͘^ƵďƐĞƋƵĞŶƚKWƚĞƐƚƚŽϯ6ϬϬƉƐŝ. All aŶŶƵůĂƌƚĞƐƚƐ ƚŽϯϬϬϬƉƐŝ͘ ϯ͘ sĂƌŝĂŶĐĞƚŽϮϬϮϱ͘Ϭϯϱ;ĞͿ;ϭϬͿ;ͿŝƐĐŽŶĚŝƟŽŶĂůůLJĂƉƉƌŽǀĞĚƚŽĂůůŽǁϮϭ-ĚĂLJKWƚĞƐƚŝŶƚĞƌǀĂů͘ ^ĞĞĐŽŶĚŝƟŽŶƐŽĨĂƉƉƌŽǀĂůŝŶŽĐŬĞƚKd,-25-ϬϭϬůĞƩĞƌŝŶƩĂĐŚŵĞŶƚϭϮŽĨƚŚŝƐWdĂƉƉůŝĐĂƟŽŶ͘ 4.>Kdͬ&/dƌĞƐƵůƚƐƚŽďĞƐƵďŵŝƩĞĚƚŽK'ǁŝƚŚŝŶϰϴŚŽƵƌƐŽĨŽďƚĂŝŶŝŶŐƚŚĞĚĂƚĂ͘ 5./ĨDWǁŝůůďĞƵƐĞĚ͕Kŝů^ĞĂƌĐŚŵƵƐƚŵĂŝŶƚĂŝŶŵƵĚĚĞŶƐŝƚLJŝŶĞdžĐĞƐƐŽĨƚŚĞŚŝŐŚĞƐƚĂŶƟĐŝƉĂƚĞĚ ƌĞƐĞƌǀŽŝƌ Dt. 6.EŽƟĨLJK'ŝĨĐĞŵĞŶƚũŽďƐĚŽŶŽƚŐŽĂĐĐŽƌĚŝŶŐƚŽƉůĂŶŽƌŝĨũŽďƉĂƌĂŵĞƚĞƌƐĂƌĞŶŽƚĂƐ ĞdžƉĞĐƚĞĚ;ůŽƐƐĞƐŽĐĐƵƌ͕ƵŶĞdžƉĞĐƚĞĚůŝŌƉƌĞƐƐƵƌĞƐŽĐĐƵƌ͕ĐĞŵĞŶƚŝƐŶŽƚĐŝƌĐƵůĂƚĞĚŽīƚŚĞƚŽƉŽĨ ƚŚĞŝŶƚĞƌŵĞĚŝĂƚĞůŝŶĞƌ͕ĞƚĐ͘Ϳ. Cement ƚŽďĞůŽŐŐĞĚŝĨũŽďĚŽĞƐŶŽƚŐŽĂĐĐŽƌĚŝŶŐƚŽƉůĂŶ͘ 7.sĂƌŝĂŶĐĞĨƌŽŵƉŽŽůƌƵůĞƐŐƌĂŶƚĞĚƚŽŝƐŽůĂƚĞƐŝŐŶŝĮĐĂŶƚŚLJĚƌŽĐĂƌďŽŶnjŽŶĞŽĨ hƉƉĞƌ dƵůƵǀĂŬĂďŽǀĞ d^ϳϵϬŚŽƌŝnjŽŶĂƐƉƌŽƉŽƐĞĚ ŝŶƐĞĐƟŽŶϭϱ. 8.sĂƌŝĂŶĐĞƚŽϮϬϮϱ͘ϬϯϬ;ĚͿ;ϱͿĨŽƌϮ-ƐƚĂŐĞŝŶƚĞƌŵĞĚŝĂƚĞĐĂƐŝŶŐĐĞŵĞŶƚŽƉĞƌĂƟŽŶĂŶĚŐĂƉŝŶ ĐĞŵĞŶƚĐŽǀĞƌĂŐĞŝƐĂƉƉƌŽǀĞĚ͕ǁŝƚŚƐƚĂŐĞĐŽůůĂƌƉůĂĐĞŵĞŶƚĂƐĨŽůůŽǁƐ ;ƌĞĨĞƌĞŶĐĞƐĞĐƟŽŶϭϱŝŶ WdĂƉƉůŝĐĂƟŽŶͿ: a.^ƚĂŐĞĐŽůůĂƌŵƵƐƚďĞƉůĂĐĞĚŶŽƐŚĂůůŽǁĞƌƚŚĂŶϱϬΖDďĞůŽǁƚŚĞďĂƐĞŽĨƚŚĞhƉƉĞƌ dƵůƵǀĂŬĂƐĚĞĮŶĞĚďLJƚŚĞd^ϳϵϬŚŽƌŝnjŽŶ͘ ď͘ ^ƵďŵŝƚϭϮ-ϭͬϰΗK,ůŽŐƐƚŽK'ĂƐƐŽŽŶĂƐƉƌĂĐƟĐĂůĂŌĞƌdŽĨŚŽůĞƐĞĐƟŽŶ͘ dŚĞ d^ϳϵϬŵĂƌŬĞƌŝƐǁĞůů-ĞƐƚĂďůŝƐŚĞĚŝŶƚŚĞĂƌĞĂŽĨEƉĂĚĂŶĚƚŚĞƌĞĨŽƌĞKŝů^ĞĂƌĐŚĚŽĞƐ ŶŽƚŶĞĞĚƚŽƐĞĞŬK'ĂƉƉƌŽǀĂůŽĨƚŚĞŝƌƉŝĐŬŽĨƚŚĞd^ϳϵϬďĞĨŽƌĞƌƵŶŶŝŶŐϵ-ϱͬϴ͟ ĐĂƐŝŶŐ͘ ϵ͘ dŚĞ>t-^ŽŶŝĐůŽŐǁŝůůŽŶůLJďĞĂĐĐĞƉƚĞĚĨŽƌĐĞŵĞŶƚĞǀĂůƵĂƟŽŶǁŚĞŶƚŚĞĨŽůůŽǁŝŶŐĐŽŶĚŝƟŽŶƐ are met: a.KŝůƐĞĂƌĐŚƚŽƉƌŽǀŝĚĞĂǁƌŝƩĞŶůŽŐĞǀĂůƵĂƟŽŶͬŝŶƚĞƌƉƌĞƚĂƟŽŶƚŽƚŚĞK'ĂůŽŶŐǁŝƚŚƚŚĞ ůŽŐĂƐƐŽŽŶĂƐƚŚĞLJďĞĐŽŵĞĂǀĂŝůĂďůĞ͘dŚĞĞǀĂůƵĂƟŽŶŝƐƚŽŝŶĚŝĐĂƚĞƚŚĞŝŶƚĞƌǀĂůƐŽĨ ĐŽŵƉĞƚĞŶƚĐĞŵĞŶƚƚŚĂƚKŝůƐĞĂƌĐŚŝƐƵƐŝŶŐƚŽŵĞĞƚƚŚĞŽďũĞĐƟǀĞƌĞƋƵŝƌĞŵĞŶƚƐĨŽƌ aŶŶƵůĂƌŝƐŽůĂƟŽŶĂŶĚƌĞƐĞƌǀŽŝƌŝƐŽůĂƟŽŶ͕ĂŶĚƚŽŝŶĚŝĐĂƚĞƚŚĞůŽĐĂƟŽŶŽĨĐŽŶĮŶŝŶŐnjŽŶĞƐ͕ ŚLJĚƌŽĐĂƌďŽŶ-ďĞĂƌŝŶŐnjŽŶĞƐ͕ŽǀĞƌƉƌĞƐƐƵƌĞĚnjŽŶĞƐĂŶĚĨƌĞƐŚǁĂƚĞƌ͕ŝĨƉƌĞƐĞŶƚ͘WƌŽǀŝĚŝŶŐ ƚŚĞůŽŐǁŝƚŚŽƵƚĂŶĞǀĂůƵĂƟŽŶͬŝŶƚĞƌƉƌĞƚĂƟŽŶŝƐŶŽƚĂĐĐĞƉƚĂďůĞ͘ ď͘ >tƐŽŶŝĐůŽŐƐŵƵƐƚƐŚŽǁĨƌĞĞƉŝƉĞĂŶĚdŽƉŽĨĞŵĞŶƚ͘ dŚĞůŽŐŵƵƐƚďĞƌƵŶĂĐƌŽƐƐƚŚĞ ƚĂƌŐĞƚnjŽŶĞƐĂŶĚĂƚĂĚĞƉƚŚƚŽĞŶƐƵƌĞƚŚĞĨƌĞĞƉŝƉĞĂďŽǀĞƚŚĞdKŝƐĐĂƉƚƵƌĞĚĂƐǁĞůůĂƐ ƚŚĞdK͘/ĨƚŚĞůŽŐŐĞĚŝŶƚĞƌǀĂůĚŽĞƐŶŽƚĐĂƉƚƵƌĞƚŚĞdKĂŶĚĨƌĞĞƉŝƉĞĂďŽǀĞŝƚ͕ it will ŶĞĞĚƚŽďĞƌĞ-ƌƵŶ͕ƵŶůĞƐƐƚŚĞĐĞŵĞŶƚǁĂƐƉůĂŶŶĞĚƚŽĐŽǀĞƌƚŚĞĞŶƟƌĞůĞŶŐƚŚŽĨůŝŶĞƌŽƌ ĐĂƐŝŶŐ͘ Đ͘ KŝůƐĞĂƌĐŚǁŝůůƉƌŽǀŝĚĞĂĐĞŵĞŶƚũŽďƐƵŵŵĂƌLJƌĞƉŽƌƚĂŶĚĞǀĂůƵĂƟŽŶĂůŽŶŐǁŝƚŚƚŚĞ ĐĞŵĞŶƚůŽŐĂŶĚĞǀĂůƵĂƟŽŶƚŽƚŚĞK'ǁŚĞŶƚŚĞLJďĞĐŽŵĞĂǀĂŝůĂďůĞ͘ d.ĞƉĞŶĚŝŶŐŽŶƚŚĞĐĞŵĞŶƚũŽďƌĞƐƵůƚƐŝŶĚŝĐĂƚĞĚďLJƚŚĞĐĞŵĞŶƚũŽďƌĞƉŽƌƚ͕ƚŚĞůŽŐƐĂŶĚ ƚŚĞ&/d͕ƌĞŵĞĚŝĂůŵĞĂƐƵƌĞƐŽƌĂĚĚŝƟŽŶĂůůŽŐŐŝŶŐŵĂLJďĞƌĞƋƵŝƌĞĚ͘ 10.sĂƌŝĂŶĐĞŽĨϵ -ϱͬϴ͟/ŶƚĞƌŵĞĚŝĂƚĞĐĞŵĞŶƚŽĨŽŶůLJϭ0ϬΖdsĂďŽǀĞƚŽƉŽĨEĂŶƵƐŚƵŬƉŽŽů ŝƐ approved. dŚĞ ϵ-ϱͬϴ͟ůŝŶĞƌĐĞŵĞŶƚƋƵĂůŝƚLJĂŶĚŚĞŝŐŚƚŵƵƐƚďĞǀĞƌŝĮĞĚǁŝƚŚĂůŽŐ͘ Page 1 of 1 01 May 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-011 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-011 is planned to be a horizontal producer targeting the Nanushuk 3. The approximate spud date is anticipated to be June 9th, 2025. Parker Rig 272 will be used to drill this well. The 16” Surface Hole will TD above the Tuluvak sand and then 13-3/8” casing will be set and cemented. The 12-1/4” intermediate hole will be drilled to above the top of the Nanushuk 3 formation at an inclination of ~78 degrees. A 9-5/8” liner will be set and cemented from TD to secure the shoe and cover the Tuluvak sand. A 9-5/8” tieback will be run to the top of the 9-5/8” liner. The 8-1/2” production hole will be geo-steered in the Nanushuk 3 sand and the lateral will be drilled to TD. The well will be completed as a stimulated 4-1/2” liner with frac sleeves and isolation packers. The production liner will be tied back to surface with a 4-1/2” tubing upper completion string. Please find enclosed for your review Form 10-401 Permit to Drill with a supporting Application for Permit to Drill containing information as required by 20 AAC 25.005. If there are any questions and/or additional information desired, please contact me at (907) 343 9737 or rob.williams@santos.com. Respectfully, Rob Williams Senior Drilling Engineer Oil Search (Alaska), LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Application for Permit to Drill NDB-011 Well Table of Contents 1. Well Name......................................................................................................................................3 2. Location Summary..........................................................................................................................3 3. Blowout Prevention Equipment Information.................................................................................4 4. Drilling Hazards Information...........................................................................................................5 5. Procedure for Conducting Formation Integrity Tests.....................................................................6 6. Casing and Cementing Program.....................................................................................................6 7. Diverter System Information..........................................................................................................6 8. Drilling Fluid Program.....................................................................................................................7 9. Abnormally Pressured Formation Information..............................................................................8 10. Seismic Analysis............................................................................................................................8 11. Seabed Condition Analysis............................................................................................................8 12. Evidence of Bonding.....................................................................................................................8 13. Proposed Drilling Program ...........................................................................................................9 14. Discussion of Mud and Cuttings Disposal and Annular Disposal................................................11 15. Proposed Variance Requests......................................................................................................11 Attachments..................................................................................................................................................15 Attachment 1: Location Maps..........................................................................................................16 Attachment 2: Directional Plan........................................................................................................17 Attachment 3: BOPE Equipment ......................................................................................................38 Attachment 4: Drilling Hazards.........................................................................................................43 Attachment 5A: Leak Off Test Procedure (Conventional)................................................................45 Attachment 5B: Leak Off Test Procedure (With MPD).....................................................................46 Attachment 6: Cement Summary.....................................................................................................47 Attachment 7: Prognosed Formation Tops......................................................................................50 Attachment 8: Well Schematic.........................................................................................................51 Attachment 9: Formation Evaluation Program................................................................................52 Attachment 10: Wellhead & Tree Diagram......................................................................................53 Attachment 11: Diverter Variance Request NDB Surface Hole Map View.......................................54 Attachment 12: Oil Search Alaska 21-day BOPE Test Schedule Waiver Approval Letter.................55 Attachment 13: Managed Pressure Drilling.....................................................................................58 Attachment 14: As Built Survey NDB Well 11 Conductor Final........................................................60 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-011. 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 2,479’ FSL, 2,555’ FWL, Sec 4, T11N, R6E, UM NAD 27 Coordinate System N 5,972,860 E 422,521’ Rig KB Elevation 47’ above GL Ground Level 22.78’ above MSL Location at Top of Productive Interval Reference to Government Section Lines 1,404’ FSL, 1,054’ FWL, Sec 8, T11N, R6E, UM NAD 27 Coordinate System N 5,966,580’ E 415,689’ Measured Depth, Rig KB (MD) 12,545’ Total Vertical Depth, Rig KB (TVD) 4,362’ Total vertical Depth, Subsea (TVDSS) 4,292’ Location at Bottom of Productive Interval Reference to Government Section Lines 1,347’ FSL, 2,060’ FEL, Sec 11, T11N, R6E, UM NAD 27 Coordinate System N 5,971,837’ E 412,618’ Measured Depth, Rig KB (MD) 18,637’ Total Vertical Depth, Rig KB (TVD) 4,191’ Total vertical Depth, Subsea (TVDSS) 4,121’ (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 x NOV Shaffer Spherical annular BOP, 13-5/8” x 5000 psi x NOV T3 6012 double gate, 13-5/8” x 5000 psi x Mud cross, 13-5/8” x 5000 psi with 2 ea. 3-1/8" x 5000 psi side outlets x Choke Line, 3-1/8” x 5000 psi with 3-1/8” manual and HCR valve x Kill Line, 2-1/16” x 5000 psi with 3-1/8” manual and HCR valve x NOV T3 6012 single gate, 13-5/8” x 5000 psi Choke Manifold x 3-1/8” x 5000 psi working pressure with Axon Type S remote controlled chokes and NRG mud/gas separator BOP Closing Unit x NOV SARA Koomey Control System, 316 gallon, 299 gallon reservoir. Twenty-Four 15 gallon bottles. Equipped with 1 electric and 3 air pumps with emergency power. Please refer to Attachment 3: BOPE Equipment for further details. 4. Drilling Hazards Information 20 AAC 25.005 (c) (4) Information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure; 12-1/4” Intermediate Hole Pressure Data Maximum anticipated BHP 1,955 psi at TD in Nanushuk 3 MFS at 4,340’ TVD (8.7ppg EMW in the Nanushuk 3 formation) Maximum surface pressure 1,521 psi from TD in the Nanushuk 3 MFS (0.10 psi/ft gas gradient to surface, 4,340’ TVD) Planned BOP test pressure Rams test to 5,000 psi / 250 psi (Initial) Rams test to 3,600 psi / 250 psi (Subsequent) Annular test to 3,000 psi / 250 psi (Test pressure driven by annular pressure during frac job) Integrity Test – 12-1/4” hole FIT after drilling 20’-50’ of new hole to 14.0 ppg. (12.9 ppg LOT required for Kick Tolerance with 11.5ppg MW) 13-3/8” Casing Test 2,600 psi surface pressure (Test pressure driven by 50% of Casing Burst) 8-1/2” Production Hole Pressure Data Maximum anticipated BHP 1,903 psi in the Nanushuk 3 at 4,360’ TVD (8.8ppg EMW Nanushuk 3 formation) Maximum surface pressure 1,470 psi from the Nanushuk 3 (0.10 psi/ft gas gradient to surface, 4,360’ TVD) Planned BOP test pressure Rams test to 3,600 psi / 250 psi Annular test to 3,000 psi / 250 psi (Test pressure driven by annular pressure during frac job) Integrity Test – 8-1/2” hole FIT after drilling 20’-50’ of new hole to 14.0 ppg. (10.5ppg required for infinite kick tolerance with 9.6ppg MW) 9-5/8” Liner Test 4,000 psi surface pressure (MIT-IA after upper completion run, test pressure driven by annular pressure during frac job) (B) data on potential gas zones; and The Tuluvak formation is expected in this area and has a high potential for gas as based on offset Exploration and Appraisal well data. The Tuluvak is expected to be over-pressured at 10.1ppg pore pressure. The well plan is designed to safely manage pressures consistent with offset wells in the same manner that hydrocarbons are handled in the reservoir zone. BOPE will be installed before entering any hydrocarbon zones and appropriate mud weights will be utilized to provide sufficient overbalance. (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 2,785’ Surface 2,785’ / 2,377’ 12-1/4” 9-5/8” 47# L-80 HYD 563 9,832’ 2,635’ 12,467’ / 4,361’ Tie Back 9-5/8” 47# L-80 HYD 563 2,635’ Surface 2,635’ / 2,303’ 8-1/2” 4-1/2” 12.6# P-110S HYD 563 6,313’ 12,317’ 18,630’ / 4,191’ Tubing 4-1/2” 12.6# P-110S HYD 563 12,317’ Surface 12,317’ / 4,357’ 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: x Hydril MSP annular BOP, 21 1/4” x 2000 psi, flanged x Diverter Spool 21 1/4” x 2000 psi with 16-3/4” flanged sidearm connection. Interlocked knife/gate valves. x 16” Diverter Line. Please refer to Attachment 3: BOPE Equipment for further details. A diverter variance is requested for NDB-011. Please refer to Section 15 for further details.A diverter variance is requested for NDB-011. Please refer to Section 15 for further details Recommend granting diverter variance. See discussion in attached emails. -A.Dewhurst 05JUN25 8. Drilling Fluid Program 20 AAC 25.005 (c) (8) A drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling Fluid Program Summary 16” Surface Hole 12-1/4” Int #1 Hole 8-1/2” Prod Hole Mud Type Spud Mud (WBM)MOBM MOBM Mud Properties: Mud Weight Funnel Vis PV YP API Fluid Loss HPHT Fluid Loss pH MBT 9.0 - 10 ppg 100 - 300 sec ALAP 30 - 80 < 10 ml/30min n/a 8.6-10.5 <35 11.0 - 12.0 ppg 50 - 80 sec ALAP 15 - 30 n/a < 5 ml/30min n/a n/a 9.0 - 10.0 ppg 50 - 80 sec ALAP 10 - 20 n/a < 5 ml/30min n/a n/a A diagram of drilling fluid system on Parker 272 is on file with AOGCC. 9. Abnormally Pressured Formation Information 20 AAC 25.005 (c) (9) For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); N/A – Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis 20 AAC 25.005 (c) (10) For an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); N/A – Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis 20 AAC 25.005 (c) (11) For a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); The NDB-011 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-011 is listed below. Please refer to Attachments 8-10 for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Proposed NDB-011 Drilling Program 1. Drill 20” conductor to ~128’ MD/TVD. Cement to surface. Install Cellar and landing ring on conductor. 2. Move in / rig up Parker 272. 3. Nipple up spacer spools over the 20” conductor. 4. Pick up 5-7/8” drill pipe, fill pits with spud mud and prepare for surface hole drilling. Make up 16” motor BHA with MWD and LWD tools. 5. Spud well and drill surface hole section to TD. Perform wiper trips as required. Circulate and condition hole to run casing. POOH and lay down BHA. 6. Run 13-3/8” 68# surface casing as per casing tally and land on pre-installed landing ring. Circulate and condition mud prior to commencing cement job. 7. Cement 13-3/8” casing as per cement program. Verify cement returns to surface. 8. NU casing head and spacer spool. NU BOPE with Rotating Control Device (RCD). BOP configured from top to bottom: annular preventor, 4-1/2” x 7” VBR, blind/shear, mud cross, 9-5/8” Fixed Rams. Test rams to 5000 psi high (initial test only – 3600 psi for subsequent tests) and annular to 3000 psi high as per AOGCC regulations. Provide AOGCC 48 hrs notice for witnessing BOP test. 9. Close blind shear rams and pressure test casing to 2600 psi for 30 min. 10. Make up 12-1/4” RSS BHA with MWD and LWD tools. RIH, clean out to top of float equipment and displace well to MOBM. 11. Drill out shoe track and 20 - 50’ of new formation. Perform FIT / LOT. 12. Directionally drill 12-1/4” intermediate hole section to TD. Perform wiper trips as required. Circulate and condition hole to run liner. POOH. 13. RU and run 9-5/8” intermediate liner as per casing tally then RIH on 5-7/8” DP / HWDP to TD. Circulate and condition mud prior to commencing cement job. 14. Set liner hanger and release running tool. Cement 9-5/8” liner with 1st stage cement job as per cement program. Monitor returns during displacement until plug bump. 15. Un-sting from liner hanger and POOH and LD liner running tools. 16. RIH with mechanical shifting tool and open 2 nd stage cement job tools. Pump secondary cement job, set liner top packer, and circulate cement to surface. POOH. 17. RIH with polish mill assembly for cleanout of the 9-5/8” liner top PBR. 18. Run 9-5/8” tieback string. Freeze protect the 13-3/8” x 9-5/8” annulus with diesel and land tieback. 19. Pressure test the 13-3/8” x 9-5/8” annulus to 2600 psi for 30 min. 20. Pressure test the 9-5/8” liner / tieback to 3500 psi for 30 min. 21. Make up 8-1/2” RSS BHA with MWD and LWD tools. RIH with 5” drillpipe. 22. Drill out shoe track and displace/condition MOBM to the required mud weight. 23. Drill 20 - 50’ of new formation. Perform FIT / LOT. 24. Directionally drill 8-1/2” production hole section to TD. Back ream hole and perform wiper trips as required. Circulate and condition hole to run liner. 25. POOH. Log first stage cement with Sonic LWD. NOTE: See more details / justification in Attachment 6: Cement Summary. 26. Run cleanout/string mill assembly to dress the 9-5/8” CFLEX tool. 27. RU and run 4-1/2” production liner with liner hanger/top packer and downhole jewelry to TD. 28. 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. 29. Close WIV collar and set open hole hydraulic set packers and liner hanger/top packer. 30. Set and pressure test the 9-5/8” x 7” x 4-1/2” IA to liner top packer to 3,500 psi for 10 min. Release the running tool. 31. Pull liner running tool above liner top. Circulate corrosion inhibited brine. 32. POOH and LD liner running tool. 33. RU and run 4-1/2” upper completion and downhole jewelry with TEC wires. Space out seals. 34. Land tubing hanger. 35. Pressure test tubing to 3,500 psi for 30 mins. Pressure up on the annulus to 4,000 psi for 30 mins. Bleed pressure on tubing and shear upper gas lift valve. 36. Reverse circulate freeze protect and U-Tube. 37. Install TWC, pressure test to 2,500 psi for 10 mins. ND BOPE, NU frac tree. 38. Secure well and prepare for rig move. 14. Discussion of Mud and Cuttings Disposal and Annular Disposal 20 AAC 25.005 (c) (14) A general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. The Oil Search Alaska NGI (Nanushuk Grind & Inject) facility is now operational, and cuttings will be hauled via truck as generated, processed at NGI, and disposed of into the DW-02 Class 1 disposal well. The NGI facility is located on NDB. In the event that NGI is not operational, water-based and oil-based drilling muds and cuttings will typically be hauled directly offsite via truck as it is generated. Contractual arrangements have been made with other operators on the North Slope to utilize their waste injection/disposal facilities (Class 1 and Class 2) at Prudhoe Bay, Kuparuk and Milne Point. If waste cannot be hauled directly offsite, it may be stored temporarily in drilling waste cuttings bins or a bermed cuttings storage cell in accordance with a drilling waste temporary storage plan approved by Alaska Department of Conservation (ADEC) Solid Waste Program until it can be transported for proper disposal. There is no intention to request authorization under 20 AAC 25.080 for any annular disposal operation in the well. 15. Proposed Variance Requests 20 AAC 25.035. Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements. (h)(2) from the diverter system requirements in (c) of this section if the variance provides at least equally effective means of diverting flow away from the drill rig or if drilling experience in the near vicinity indicates that a diverter is not necessary A diverter variance is requested for the NDB-011 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-011 surface hole is surrounded by more than 15 other existing surface holes at the NDB pad location. Additionally, there are 2 previously drilled wells (NDB-025 and NDBi-014) within 600’ of the proposed NDB-011 surface hole TD location (see attachment 11). More than 32 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 16 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-011 well. NDB-011 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-011 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 9-5/8” Cement Job: A variance is requested to the above regulation 20 AAC 25.030 (d)(5) to not place cement across the entire annular space from the casing shoe to above the shallowest significant hydrocarbon zone. A two-stage cement job will be performed to isolate the significant hydrocarbon zone in the Nanushuk formation (primary job), and the second stage cement job will isolate the significant hydrocarbon zone in the Tuluvak formation. The primary cement job will target a top of cement 500’ MD or 250’ TVD, whichever is greater, above the top of the Nanushuk. Due to the ERD nature and high angle of the Pikka NDB development wells, a single stage cement job on the intermediate liner is not achievable without exceeding the fracture gradient and compromising cement placement and zonal isolation. The two-stage cement job will achieve all casing and cementing objectives outlined in AOGCC regulation 20 AAC 25.030.(a), stating that a well casing and cementing program must be designed to: a) provide suitable and safe operating conditions for the total measured depth proposed; b) confine fluids to the wellbore; c) prevent migration of fluids from one stratum to another; d) ensure control of well pressures encountered; e) protect against thaw subsidence and freezeback effects within permafrost; f) prevent contamination of freshwater; g) protect significant hydrocarbon zones; and h) provide well control until the next casing is set, considering all factors relevant to well control including formation fracture gradients, formation pressures, casing setting depths, and proposed total depth. The formation interval between the top of stage one and the bottom of stage two includes the Seabee and lower Tuluvak formation. These formations are interbedded silts and shales with very low permeability and contain no significant hydrocarbons. Based on offset well logs, cuttings, mudlogging analysis, and the latest petrophysical interpretation, the base of the significant hydrocarbon zone in the Tuluvak formation is contained only within the upper portion of TS 880 clinoform of the Upper Tuluvak in the NDB area. Within the TS 880 clinoform, the base of significant hydrocarbon is at or above 2,640’ 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: Recommend granting requested variance to permit two-stage cementing operation. Recommend granting variance from pool rules to isolate significant hydrocarbons as proposed above (base of significant HC zone defined from TS790 maker). -A.Dewhurst 03JUN25 No longer true. See email from Rob Williams email 5/30/25 requesting 100' TVD above top Nanushuk. -bjm 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. Attachments Attachment 1: Location Maps ADL 392977 ADL 392991 ADL 392959 ADL 392965 ADL 392985 ADL 392984 ADL 392958 ADL 393024 ADL 393022 ADL 393021 ADL 393023 ADL 393019 ADL 393020 ADL 393016 ADL 391320 ADL 391445 U011N006E04 U012N006E32 U011N006E05 U012N006E33 U012N005E36U011N005E01U011N005E12U011N006E09 U011N006E08 U011N006E16 U011N006E17 U011N005E13U012N006E31 U011N006E06 U011N006E18 U011N006E07 COLVILLE RIVER 1 QUGRUK 3 QUGRUK 301 QUGRUK 3A QUGRUK 8 Colville River 1PB1 DW-02 NDB-025 NDB-032 NDB-048 NDB-051 NDBi-014 NDBi-043A NDBi-044 NDBi-046 NDBi-050 NDBi-046L1 OIL SEARCH (ALASKA) LLC A SUBSIDIARY OF SANTOS LTD NDB-011 SURFACE LOCATION NDB-011 TRAJECTORY OTHER DRILLED NDB WELLS NDB-011 BOTTOM HOLE 0.25-MILE BUFFER 0.5-MILE BUFFER NDB DRILLED WELLS BOTTOM HOLES EXPLORATION WELLS BOTTOM HOLES OTHER WELL TRAJECTORIES BY OTHERS PRODUCTION INTERVAL SANTOS LEASES SECTIONS DATE: 4/22/2025. By: JB 00.10.2 Miles Project: AP-DRL-GEN_assorted Layout: AP-DRL-GEN-M_NDB11_buffers Map Frame: AP-DRL-GEN-M_NDB-011_buffers GCS: NAD 1983 StatePlane Alaska 4 FIPS 5004 Feet 00.20.4 Kilometers PIKKA DEVELOPMENT NDB-011 WELL Attachment 2: Directional Plan SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 47.0 0.00 0.00 47.0 0.0 0.0 0.00 0.00 0.0 2 347.0 0.00 0.00 347.0 0.0 0.0 0.00 0.00 0.0 3 647.0 6.00 190.00 646.5 -15.5 -2.7 2.00 190.00 4.5 4 996.8 15.00 190.00 990.0 -78.2 -13.8 2.57 0.00 22.5 5 1146.8 15.00 190.00 1134.9 -116.4 -20.5 0.00 0.00 33.6 6 3278.1 77.54 213.98 2543.5 -1385.4 -724.6 3.00 26.22 876.7 7 9291.7 77.54 213.98 3840.9 -6254.7 -4006.4 0.00 0.00 4688.1 8 12833.1 91.66 329.33 4358.8 -6116.0 -6933.0 3.25 94.06 7580.2 NDB-011 Heel Rev 4.0 9 18636.9 91.66 329.33 4190.8 -1126.1 -9892.4 0.00 0.00 9956.3 NDB-011 Toe Rev 1.0 47 500 500 1000 1000 1500 1500 2000 2000 2500 2500 3000 3000 5000 5000 6000 6000 7000 7000 8000 8000 9000 9000 10000 10000 12000 12000 14000 14000 16000 16000 18000 18000 20000 20000 25000 Plan: NDB-011 Rev F.1 Plan Summary 0 3 Dogleg Severity0 3000 6000 9000 12000 15000 18000 Measured Depth 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Production 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] 475075100125150175200225250275300325327350375400425450475500525550Plan: NDBi-06 Rev B.0 75100125150175200225250275300325327350375400425450475500525550575600625650675Plan: NDBi-07 Rev A.0 475075100125150175200225250275300325327350375400425450475500525550575600625650675700725750775800825850875900925NDB-08 Slot Saver 75100125150175200225250275300325327350375400425450475500525550575600625650675700 725 750 775Plan: NDB-09 Rev A.0 475075100125150175200225250275300325327350375400425450475500525550575600625650675700725750775 800 825 850 875Plan: NDB-010 Rev B.0 4750751001251501752002252502753003253503754004254504755005255505725756006256506757007257507758008258508759009259509751000Plan: NDBi-012 Slot Saver 4750751001251501752002252502753003253503754004254504755005255505756006256506646757007257507758008258508759009259509751000Plan: NDBi-013 Slot Saver 475075100125150175183200225250275300325350375400425450475500525550575600625 65067570070972573875077580082585087590092595097510001025105010751100112511501175120012251250127513001325135013751400142514501475150015251550157516001625165016751700172517501775180018251850187519001925NDBi-014 75100125150175200225250275300325350375400425450475475500525550575600625650675700725 750Plan: NDB-015 Rev A.0 47505275100125150175200225250275300325 350375400425450475500512525550575600625650675700725NDBi-016 2250 True Vertical Depth0 1500 3000 4500 6000 7500 9000 Vertical Section at 263.51° 20" Conductor Casing 13-3/8" Surface Casing 9-5/8" Production Liner4-1/2" Production Liner 0 28 55 Centre to Centre Separation0 275 550 825 1100 1375 1650 1925 Measured Depth Equivalent Magnetic Distance DDI 7.262 SURVEY PROGRAM Date: 2021-02-11T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 47.0 900.0 Plan: NDB-011 Rev F.1 (NDB-011)SDI_URSA1_I4 900.0 2790.0 Plan: NDB-011 Rev F.1 (NDB-011)3_MWD+IFR2+MS+Sag 2790.0 12471.0 Plan: NDB-011 Rev F.1 (NDB-011)3_MWD+IFR2+MS+Sag 12471.0 18636.9 Plan: NDB-011 Rev F.1 (NDB-011)3_MWD+IFR2+MS+Sag Surface Location North / 5972608.23 East / 1562553.64 Elevation / 22.8 CASING DETAILS TVD MD Name 128.0 128.0 20" Conductor Casing 2376.9 2785.013-3/8" Surface Casing 4360.8 12467.09-5/8" Production Liner 4191.0 18630.04-1/2" Production Liner Mag Model & Date: BGGM2024 01-Aug-25 Magnetic North is 13.65° East of True North (Magnetic De Mag Dip & Field Strength: 80.53°57117.75404 FORMATION TOP DETAILS TVDPath Formation 1048.8 Upper SB 1138.8Base Ice Bearing Permafrost 1389.8 BP Transition1731.8 Middle SB 2153.8 MCU 2450.8 Tuluvak Shale 2516.8 Tuluvak Sand 2843.8 TS_790 3166.8 Seabee 3892.8 Nanushuk 3939.8 NT8 MFS 3984.8 NT7 MFS 4038.8 NT6 MFS 4098.8 NT5 MFS 4207.8 NT4 MFS 4347.8 NT3 MFS 4361.8NT3.2 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 surroundingwells are assigned to the proper position, and I approve the scan and collision avoidance plan as set out in the audit pack.I approve it as the basiis for the final well plan and wellsite drawings. I also acknowledge that unless notified otherwise all targets have a 100 feet lateral tolerance. Prepared by Checked by BHI DE Accepted by BHI PSD Approved by Santos DE Parker 272 @ 69.8usft Standard Planning Report - Geographic 17 April, 2025 Plan: Plan: NDB-011 Rev F.1 Santos NAD27 Conversion Pikka NDB B-11 NDB-011 Santos Ltd Planning Report - Geographic Well B-11Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-11Well: NDB-011Wellbore: Plan: NDB-011 Rev F.1Design: 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 " 5,972,909.13 423,383.61 36 70° 20' 10.132 N 150° 37' 17.794 W Well Well Position Longitude: Latitude: Easting: Northing: +E/-W +N/-S Position Uncertainty Ground Level: B-11 Wellhead Elevation:0.5 0.0 0.0 5,972,860.23 422,520.84 70° 20' 9.564 N 150° 37' 42.977 W 22.8 usft usft usft usft usft usft usft °-0.59Grid Convergence: Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NDB-011 Model NameMagnetics BGGM2024 1/08/2025 13.65 80.53 57,117.75376782 Phase:Version: Audit Notes: Design Plan: NDB-011 Rev F.1 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:47.0 263.510.00.047.0 Plan Survey Tool Program RemarksTool NameSurvey (Wellbore) Date 17/04/2025 Depth To (usft) Depth From (usft) SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISC Plan: NDB-011 Rev F.1 (NDB-01147.0 900.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-011 Rev F.1 (NDB-012900.0 2,790.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-011 Rev F.1 (NDB-0132,790.0 12,471.0 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-s Plan: NDB-011 Rev F.1 (NDB-01412,471.0 18,636.9 17/04/2025 12:36:05 COMPASS 5000.17 Build Page 2 Santos Ltd Planning Report - Geographic Well B-11Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-11Well: NDB-011Wellbore: Plan: NDB-011 Rev F.1Design: Inclination (°) Azimuth (°) +E/-W (usft) TFO (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections Target 0.000.000.000.000.00.047.00.000.0047.0 0.000.000.000.000.00.0347.00.000.00347.0 190.000.002.002.00-2.7-15.5646.5190.006.00647.0 0.000.002.572.57-13.8-78.2990.0190.0015.00996.8 0.000.000.000.00-20.5-116.41,134.9190.0015.001,146.8 26.221.132.933.00-724.7-1,385.42,543.5213.9877.543,278.1 0.000.000.000.00-4,007.0-6,254.73,840.9213.9877.549,292.0 94.063.260.403.25-6,933.5-6,116.04,358.8329.3391.6612,833.3 NDB-011 Heel Rev 90.080.000.000.00-9,892.5-1,125.84,190.8329.3491.6618,637.2 NDB-011 Toe Rev 1 17/04/2025 12:36:05 COMPASS 5000.17 Build Page 3 Santos Ltd Planning Report - Geographic Well B-11Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-11Well: NDB-011Wellbore: Plan: NDB-011 Rev F.1Design: 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 0.00.00 422,520.845,972,860.23 70° 20' 9.564 N 150° 37' 42.977 W 100.0 0.00 100.0 0.0 0.00.00 422,520.845,972,860.23 70° 20' 9.564 N 150° 37' 42.977 W 128.0 0.00 128.0 0.0 0.00.00 422,520.845,972,860.23 70° 20' 9.564 N 150° 37' 42.977 W 20" Conductor Casing 200.0 0.00 200.0 0.0 0.00.00 422,520.845,972,860.23 70° 20' 9.564 N 150° 37' 42.977 W 300.0 0.00 300.0 0.0 0.00.00 422,520.845,972,860.23 70° 20' 9.564 N 150° 37' 42.977 W 347.0 0.00 347.0 0.0 0.00.00 422,520.845,972,860.23 70° 20' 9.564 N 150° 37' 42.977 W 400.0 1.06 400.0 -0.5 -0.1190.00 422,520.755,972,859.75 70° 20' 9.559 N 150° 37' 42.980 W 500.0 3.06 499.9 -4.0 -0.7190.00 422,520.095,972,856.22 70° 20' 9.525 N 150° 37' 42.998 W 600.0 5.06 599.7 -11.0 -1.9190.00 422,518.795,972,849.26 70° 20' 9.456 N 150° 37' 43.034 W 647.0 6.00 646.5 -15.5 -2.7190.00 422,517.965,972,844.81 70° 20' 9.412 N 150° 37' 43.057 W 700.0 7.36 699.1 -21.5 -3.8190.00 422,516.825,972,838.75 70° 20' 9.352 N 150° 37' 43.088 W 800.0 9.94 797.9 -36.3 -6.4190.00 422,514.065,972,823.97 70° 20' 9.207 N 150° 37' 43.164 W 900.0 12.51 896.0 -55.5 -9.8190.00 422,510.485,972,804.84 70° 20' 9.018 N 150° 37' 43.263 W 996.8 15.00 990.0 -78.2 -13.8190.00 422,506.255,972,782.23 70° 20' 8.795 N 150° 37' 43.380 W 1,000.0 15.00 993.1 -79.0 -13.9190.00 422,506.105,972,781.40 70° 20' 8.787 N 150° 37' 43.384 W 1,057.6 15.00 1,048.8 -93.7 -16.5190.00 422,503.365,972,766.74 70° 20' 8.643 N 150° 37' 43.460 W Upper Schrader Bluff 1,100.0 15.00 1,089.7 -104.5 -18.4190.00 422,501.345,972,755.96 70° 20' 8.537 N 150° 37' 43.515 W 1,146.8 15.00 1,134.9 -116.4 -20.5190.00 422,499.125,972,744.07 70° 20' 8.419 N 150° 37' 43.577 W 1,150.8 15.11 1,138.8 -117.4 -20.7190.21 422,498.925,972,743.04 70° 20' 8.409 N 150° 37' 43.582 W Base Ice Bearing Permafrost 1,200.0 16.45 1,186.1 -130.5 -23.4192.49 422,496.145,972,729.95 70° 20' 8.280 N 150° 37' 43.659 W 1,300.0 19.23 1,281.3 -160.2 -31.0196.17 422,488.195,972,700.39 70° 20' 7.989 N 150° 37' 43.883 W 1,400.0 22.07 1,374.9 -193.8 -41.7198.94 422,477.165,972,666.92 70° 20' 7.658 N 150° 37' 44.195 W 1,416.1 22.53 1,389.8 -199.5 -43.7199.33 422,475.095,972,661.17 70° 20' 7.602 N 150° 37' 44.253 W Base Permafrost Transition 1,500.0 24.94 1,466.6 -231.2 -55.4201.11 422,463.085,972,629.62 70° 20' 7.290 N 150° 37' 44.595 W 1,600.0 27.84 1,556.2 -272.4 -72.0202.85 422,445.995,972,588.61 70° 20' 6.885 N 150° 37' 45.081 W 1,700.0 30.76 1,643.4 -317.2 -91.6204.29 422,425.945,972,543.98 70° 20' 6.444 N 150° 37' 45.653 W 1,800.0 33.69 1,728.0 -365.6 -114.1205.50 422,402.985,972,495.87 70° 20' 5.969 N 150° 37' 46.309 W 1,804.6 33.82 1,731.8 -367.9 -115.2205.55 422,401.855,972,493.57 70° 20' 5.946 N 150° 37' 46.341 W Middle Schrader Bluff 1,900.0 36.63 1,809.7 -417.3 -139.4206.53 422,377.195,972,444.41 70° 20' 5.460 N 150° 37' 47.047 W 2,000.0 39.57 1,888.4 -472.3 -167.4207.43 422,348.625,972,389.74 70° 20' 4.919 N 150° 37' 47.865 W 2,100.0 42.53 1,963.8 -530.4 -198.0208.23 422,317.355,972,332.00 70° 20' 4.348 N 150° 37' 48.760 W 2,200.0 45.49 2,035.7 -591.3 -231.3208.94 422,283.485,972,271.36 70° 20' 3.748 N 150° 37' 49.731 W 2,300.0 48.45 2,103.9 -655.1 -267.0209.58 422,247.095,972,207.98 70° 20' 3.121 N 150° 37' 50.775 W 2,376.9 50.73 2,153.8 -705.9 -296.1210.04 422,217.455,972,157.49 70° 20' 2.622 N 150° 37' 51.625 W MCU 2,400.0 51.42 2,168.3 -721.4 -305.2210.17 422,208.285,972,142.04 70° 20' 2.469 N 150° 37' 51.888 W 2,500.0 54.39 2,228.6 -790.2 -345.6210.71 422,167.165,972,073.72 70° 20' 1.792 N 150° 37' 53.068 W 2,600.0 57.36 2,284.7 -861.2 -388.1211.21 422,123.855,972,003.20 70° 20' 1.094 N 150° 37' 54.312 W 2,700.0 60.33 2,336.5 -934.2 -432.8211.68 422,078.465,971,930.67 70° 20' 0.377 N 150° 37' 55.615 W 2,785.0 62.86 2,376.9 -997.7 -472.3212.06 422,038.345,971,867.60 70° 19' 59.752 N 150° 37' 56.768 W 13-3/8" Surface Casing 2,800.0 63.30 2,383.7 -1,009.0 -479.4212.12 422,031.125,971,856.34 70° 19' 59.641 N 150° 37' 56.975 W 2,900.0 66.28 2,426.3 -1,085.4 -527.8212.54 421,981.955,971,780.42 70° 19' 58.889 N 150° 37' 58.388 W 2,963.4 68.17 2,450.8 -1,134.6 -559.3212.80 421,949.905,971,731.56 70° 19' 58.405 N 150° 37' 59.309 W Tuluvak Shale 3,000.0 69.26 2,464.1 -1,163.3 -577.8212.94 421,931.095,971,703.10 70° 19' 58.123 N 150° 37' 59.849 W 3,100.0 72.23 2,497.1 -1,242.3 -629.4213.33 421,878.685,971,624.60 70° 19' 57.346 N 150° 38' 1.356 W 3,168.5 74.27 2,516.8 -1,297.0 -665.6213.58 421,841.975,971,570.26 70° 19' 56.808 N 150° 38' 2.411 W Tuluvak Sand 3,200.0 75.21 2,525.1 -1,322.3 -682.4213.70 421,824.875,971,545.13 70° 19' 56.559 N 150° 38' 2.903 W 3,278.1 77.54 2,543.5 -1,385.4 -724.7213.98 421,781.945,971,482.52 70° 19' 55.938 N 150° 38' 4.137 W 3,300.0 77.54 2,548.2 -1,403.1 -736.6213.98 421,769.825,971,464.93 70° 19' 55.764 N 150° 38' 4.486 W 3,400.0 77.54 2,569.8 -1,484.1 -791.2213.98 421,714.415,971,384.54 70° 19' 54.968 N 150° 38' 6.079 W 3,500.0 77.54 2,591.4 -1,565.1 -845.8213.98 421,659.015,971,304.15 70° 19' 54.172 N 150° 38' 7.673 W 17/04/2025 12:36:05 COMPASS 5000.17 Build Page 4 Santos Ltd Planning Report - Geographic Well B-11Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-11Well: NDB-011Wellbore: Plan: NDB-011 Rev F.1Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 3,600.0 77.54 2,612.9 -1,646.0 -900.4213.98 421,603.605,971,223.76 70° 19' 53.375 N 150° 38' 9.266 W 3,700.0 77.54 2,634.5 -1,727.0 -954.9213.98 421,548.205,971,143.36 70° 19' 52.579 N 150° 38' 10.859 W 3,800.0 77.54 2,656.1 -1,808.0 -1,009.5213.98 421,492.795,971,062.97 70° 19' 51.782 N 150° 38' 12.452 W 3,900.0 77.54 2,677.7 -1,888.9 -1,064.1213.98 421,437.385,970,982.58 70° 19' 50.986 N 150° 38' 14.046 W 4,000.0 77.54 2,699.2 -1,969.9 -1,118.7213.98 421,381.985,970,902.19 70° 19' 50.190 N 150° 38' 15.639 W 4,100.0 77.54 2,720.8 -2,050.9 -1,173.3213.98 421,326.575,970,821.79 70° 19' 49.393 N 150° 38' 17.232 W 4,200.0 77.54 2,742.4 -2,131.8 -1,227.8213.98 421,271.165,970,741.40 70° 19' 48.597 N 150° 38' 18.825 W 4,300.0 77.54 2,764.0 -2,212.8 -1,282.4213.98 421,215.765,970,661.01 70° 19' 47.800 N 150° 38' 20.418 W 4,400.0 77.54 2,785.5 -2,293.8 -1,337.0213.98 421,160.355,970,580.62 70° 19' 47.004 N 150° 38' 22.011 W 4,500.0 77.54 2,807.1 -2,374.7 -1,391.6213.98 421,104.945,970,500.23 70° 19' 46.208 N 150° 38' 23.604 W 4,600.0 77.54 2,828.7 -2,455.7 -1,446.1213.98 421,049.545,970,419.83 70° 19' 45.411 N 150° 38' 25.197 W 4,670.1 77.54 2,843.8 -2,512.5 -1,484.4213.98 421,010.695,970,363.47 70° 19' 44.853 N 150° 38' 26.314 W TS_790 4,700.0 77.54 2,850.2 -2,536.7 -1,500.7213.98 420,994.135,970,339.44 70° 19' 44.615 N 150° 38' 26.790 W 4,800.0 77.54 2,871.8 -2,617.6 -1,555.3213.98 420,938.725,970,259.05 70° 19' 43.818 N 150° 38' 28.383 W 4,900.0 77.54 2,893.4 -2,698.6 -1,609.9213.98 420,883.325,970,178.66 70° 19' 43.022 N 150° 38' 29.976 W 5,000.0 77.54 2,915.0 -2,779.6 -1,664.5213.98 420,827.915,970,098.26 70° 19' 42.225 N 150° 38' 31.568 W 5,100.0 77.54 2,936.5 -2,860.5 -1,719.0213.98 420,772.515,970,017.87 70° 19' 41.429 N 150° 38' 33.161 W 5,200.0 77.54 2,958.1 -2,941.5 -1,773.6213.98 420,717.105,969,937.48 70° 19' 40.633 N 150° 38' 34.754 W 5,300.0 77.54 2,979.7 -3,022.5 -1,828.2213.98 420,661.695,969,857.09 70° 19' 39.836 N 150° 38' 36.347 W 5,400.0 77.54 3,001.3 -3,103.4 -1,882.8213.98 420,606.295,969,776.70 70° 19' 39.040 N 150° 38' 37.939 W 5,500.0 77.54 3,022.8 -3,184.4 -1,937.3213.98 420,550.885,969,696.30 70° 19' 38.243 N 150° 38' 39.532 W 5,600.0 77.54 3,044.4 -3,265.4 -1,991.9213.98 420,495.475,969,615.91 70° 19' 37.447 N 150° 38' 41.125 W 5,700.0 77.54 3,066.0 -3,346.3 -2,046.5213.98 420,440.075,969,535.52 70° 19' 36.650 N 150° 38' 42.717 W 5,800.0 77.54 3,087.6 -3,427.3 -2,101.1213.98 420,384.665,969,455.13 70° 19' 35.854 N 150° 38' 44.310 W 5,900.0 77.54 3,109.1 -3,508.3 -2,155.7213.98 420,329.255,969,374.73 70° 19' 35.057 N 150° 38' 45.902 W 6,000.0 77.54 3,130.7 -3,589.2 -2,210.2213.98 420,273.855,969,294.34 70° 19' 34.261 N 150° 38' 47.495 W 6,100.0 77.54 3,152.3 -3,670.2 -2,264.8213.98 420,218.445,969,213.95 70° 19' 33.465 N 150° 38' 49.087 W 6,167.3 77.54 3,166.8 -3,724.7 -2,301.5213.98 420,181.175,969,159.87 70° 19' 32.929 N 150° 38' 50.158 W Seabee 6,200.0 77.54 3,173.9 -3,751.2 -2,319.4213.98 420,163.035,969,133.56 70° 19' 32.668 N 150° 38' 50.679 W 6,300.0 77.54 3,195.4 -3,832.2 -2,374.0213.98 420,107.635,969,053.17 70° 19' 31.872 N 150° 38' 52.272 W 6,400.0 77.54 3,217.0 -3,913.1 -2,428.5213.98 420,052.225,968,972.77 70° 19' 31.075 N 150° 38' 53.864 W 6,500.0 77.54 3,238.6 -3,994.1 -2,483.1213.98 419,996.825,968,892.38 70° 19' 30.279 N 150° 38' 55.456 W 6,600.0 77.54 3,260.2 -4,075.1 -2,537.7213.98 419,941.415,968,811.99 70° 19' 29.482 N 150° 38' 57.049 W 6,700.0 77.54 3,281.7 -4,156.0 -2,592.3213.98 419,886.005,968,731.60 70° 19' 28.686 N 150° 38' 58.641 W 6,800.0 77.54 3,303.3 -4,237.0 -2,646.9213.98 419,830.605,968,651.20 70° 19' 27.889 N 150° 39' 0.233 W 6,900.0 77.54 3,324.9 -4,318.0 -2,701.4213.98 419,775.195,968,570.81 70° 19' 27.093 N 150° 39' 1.825 W 7,000.0 77.54 3,346.5 -4,398.9 -2,756.0213.98 419,719.785,968,490.42 70° 19' 26.296 N 150° 39' 3.417 W 7,100.0 77.54 3,368.0 -4,479.9 -2,810.6213.98 419,664.385,968,410.03 70° 19' 25.500 N 150° 39' 5.009 W 7,200.0 77.54 3,389.6 -4,560.9 -2,865.2213.98 419,608.975,968,329.64 70° 19' 24.703 N 150° 39' 6.601 W 7,300.0 77.54 3,411.2 -4,641.8 -2,919.8213.98 419,553.565,968,249.24 70° 19' 23.907 N 150° 39' 8.194 W 7,400.0 77.54 3,432.8 -4,722.8 -2,974.3213.98 419,498.165,968,168.85 70° 19' 23.110 N 150° 39' 9.785 W 7,500.0 77.54 3,454.3 -4,803.8 -3,028.9213.98 419,442.755,968,088.46 70° 19' 22.314 N 150° 39' 11.377 W 7,600.0 77.54 3,475.9 -4,884.7 -3,083.5213.98 419,387.355,968,008.07 70° 19' 21.517 N 150° 39' 12.969 W 7,700.0 77.54 3,497.5 -4,965.7 -3,138.1213.98 419,331.945,967,927.67 70° 19' 20.720 N 150° 39' 14.561 W 7,800.0 77.54 3,519.0 -5,046.7 -3,192.6213.98 419,276.535,967,847.28 70° 19' 19.924 N 150° 39' 16.153 W 7,900.0 77.54 3,540.6 -5,127.6 -3,247.2213.98 419,221.135,967,766.89 70° 19' 19.127 N 150° 39' 17.745 W 8,000.0 77.54 3,562.2 -5,208.6 -3,301.8213.98 419,165.725,967,686.50 70° 19' 18.331 N 150° 39' 19.337 W 8,100.0 77.54 3,583.8 -5,289.6 -3,356.4213.98 419,110.315,967,606.11 70° 19' 17.534 N 150° 39' 20.928 W 8,200.0 77.54 3,605.3 -5,370.5 -3,411.0213.98 419,054.915,967,525.71 70° 19' 16.738 N 150° 39' 22.520 W 8,300.0 77.54 3,626.9 -5,451.5 -3,465.5213.98 418,999.505,967,445.32 70° 19' 15.941 N 150° 39' 24.112 W 8,400.0 77.54 3,648.5 -5,532.5 -3,520.1213.98 418,944.095,967,364.93 70° 19' 15.145 N 150° 39' 25.703 W 8,500.0 77.54 3,670.1 -5,613.4 -3,574.7213.98 418,888.695,967,284.54 70° 19' 14.348 N 150° 39' 27.295 W 8,600.0 77.54 3,691.6 -5,694.4 -3,629.3213.98 418,833.285,967,204.14 70° 19' 13.551 N 150° 39' 28.887 W 8,700.0 77.54 3,713.2 -5,775.4 -3,683.8213.98 418,777.875,967,123.75 70° 19' 12.755 N 150° 39' 30.478 W 8,800.0 77.54 3,734.8 -5,856.4 -3,738.4213.98 418,722.475,967,043.36 70° 19' 11.958 N 150° 39' 32.070 W 8,900.0 77.54 3,756.4 -5,937.3 -3,793.0213.98 418,667.065,966,962.97 70° 19' 11.162 N 150° 39' 33.661 W 9,000.0 77.54 3,777.9 -6,018.3 -3,847.6213.98 418,611.665,966,882.58 70° 19' 10.365 N 150° 39' 35.253 W 17/04/2025 12:36:05 COMPASS 5000.17 Build Page 5 Santos Ltd Planning Report - Geographic Well B-11Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-11Well: NDB-011Wellbore: Plan: NDB-011 Rev F.1Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 9,100.0 77.54 3,799.5 -6,099.3 -3,902.2213.98 418,556.255,966,802.18 70° 19' 9.569 N 150° 39' 36.844 W 9,200.0 77.54 3,821.1 -6,180.2 -3,956.7213.98 418,500.845,966,721.79 70° 19' 8.772 N 150° 39' 38.435 W 9,292.0 77.54 3,840.9 -6,254.7 -4,007.0213.98 418,449.855,966,647.80 70° 19' 8.039 N 150° 39' 39.900 W 9,300.0 77.52 3,842.7 -6,261.2 -4,011.3214.25 418,445.425,966,641.41 70° 19' 7.975 N 150° 39' 40.027 W 9,400.0 77.32 3,864.4 -6,340.2 -4,068.6217.57 418,387.385,966,562.97 70° 19' 7.198 N 150° 39' 41.696 W 9,500.0 77.15 3,886.6 -6,415.7 -4,130.2220.90 418,324.935,966,488.09 70° 19' 6.455 N 150° 39' 43.494 W 9,528.1 77.11 3,892.8 -6,436.3 -4,148.3221.83 418,306.655,966,467.75 70° 19' 6.253 N 150° 39' 44.021 W Nanushuk 9,600.0 77.03 3,908.9 -6,487.5 -4,196.2224.23 418,258.285,966,417.00 70° 19' 5.748 N 150° 39' 45.417 W 9,700.0 76.95 3,931.4 -6,555.3 -4,266.1227.57 418,187.645,966,349.94 70° 19' 5.081 N 150° 39' 47.457 W 9,737.1 76.93 3,939.8 -6,579.4 -4,293.0228.80 418,160.475,966,326.14 70° 19' 4.844 N 150° 39' 48.242 W NT8 MFS 9,800.0 76.91 3,954.0 -6,618.9 -4,339.9230.90 418,113.235,966,287.11 70° 19' 4.455 N 150° 39' 49.608 W 9,900.0 76.92 3,976.7 -6,678.1 -4,417.2234.24 418,035.295,966,228.73 70° 19' 3.873 N 150° 39' 51.864 W 9,935.8 76.93 3,984.8 -6,698.2 -4,445.7235.43 418,006.555,966,208.92 70° 19' 3.675 N 150° 39' 52.696 W NT7 MFS 10,000.0 76.96 3,999.3 -6,732.7 -4,497.9237.57 417,954.085,966,174.97 70° 19' 3.335 N 150° 39' 54.216 W 10,100.0 77.05 4,021.8 -6,782.5 -4,581.6240.91 417,869.865,966,126.02 70° 19' 2.845 N 150° 39' 56.658 W 10,176.2 77.15 4,038.8 -6,817.2 -4,647.3243.45 417,803.795,966,092.02 70° 19' 2.503 N 150° 39' 58.575 W NT6 MFS 10,200.0 77.19 4,044.1 -6,827.4 -4,668.1244.24 417,782.895,966,082.03 70° 19' 2.403 N 150° 39' 59.181 W 10,300.0 77.36 4,066.1 -6,867.2 -4,757.1247.57 417,693.475,966,043.13 70° 19' 2.011 N 150° 40' 1.778 W 10,400.0 77.58 4,087.8 -6,901.9 -4,848.4250.89 417,601.865,966,009.47 70° 19' 1.670 N 150° 40' 4.440 W 10,451.3 77.70 4,098.8 -6,917.6 -4,896.0252.59 417,554.105,965,994.25 70° 19' 1.515 N 150° 40' 5.829 W NT5 MFS 10,500.0 77.83 4,109.1 -6,931.2 -4,941.6254.20 417,508.385,965,981.13 70° 19' 1.381 N 150° 40' 7.159 W 10,600.0 78.13 4,129.9 -6,955.1 -5,036.4257.51 417,413.325,965,958.23 70° 19' 1.145 N 150° 40' 9.925 W 10,700.0 78.46 4,150.2 -6,973.5 -5,132.6260.81 417,316.985,965,940.82 70° 19' 0.964 N 150° 40' 12.731 W 10,800.0 78.83 4,169.9 -6,986.3 -5,229.8264.11 417,219.685,965,928.96 70° 19' 0.836 N 150° 40' 15.566 W 10,900.0 79.24 4,188.9 -6,993.6 -5,327.6267.39 417,121.735,965,922.70 70° 19' 0.764 N 150° 40' 18.422 W 11,000.0 79.68 4,207.2 -6,995.3 -5,425.9270.67 417,023.445,965,922.06 70° 19' 0.747 N 150° 40' 21.290 W 11,003.2 79.70 4,207.8 -6,995.2 -5,429.0270.77 417,020.325,965,922.13 70° 19' 0.748 N 150° 40' 21.380 W NT4 MFS 11,100.0 80.16 4,224.7 -6,991.3 -5,524.3273.93 416,925.135,965,927.02 70° 19' 0.785 N 150° 40' 24.160 W 11,200.0 80.66 4,241.4 -6,981.7 -5,622.4277.19 416,827.125,965,937.59 70° 19' 0.879 N 150° 40' 27.023 W 11,300.0 81.20 4,257.2 -6,966.6 -5,720.0280.44 416,729.725,965,953.73 70° 19' 1.027 N 150° 40' 29.870 W 11,400.0 81.76 4,272.0 -6,946.0 -5,816.7283.67 416,633.255,965,975.37 70° 19' 1.229 N 150° 40' 32.692 W 11,500.0 82.35 4,285.8 -6,919.9 -5,912.2286.90 416,538.015,966,002.46 70° 19' 1.485 N 150° 40' 35.479 W 11,600.0 82.96 4,298.6 -6,888.4 -6,006.2290.12 416,444.315,966,034.91 70° 19' 1.794 N 150° 40' 38.224 W 11,700.0 83.60 4,310.3 -6,851.6 -6,098.5293.33 416,352.465,966,072.61 70° 19' 2.155 N 150° 40' 40.916 W 11,800.0 84.25 4,320.9 -6,809.7 -6,188.7296.53 416,262.745,966,115.44 70° 19' 2.566 N 150° 40' 43.548 W 11,900.0 84.92 4,330.3 -6,762.8 -6,276.4299.72 416,175.455,966,163.27 70° 19' 3.027 N 150° 40' 46.111 W 12,000.0 85.61 4,338.6 -6,711.0 -6,361.6302.91 416,090.875,966,215.93 70° 19' 3.536 N 150° 40' 48.596 W 12,100.0 86.31 4,345.6 -6,654.5 -6,443.8306.09 416,009.275,966,273.27 70° 19' 4.090 N 150° 40' 50.995 W 12,135.0 86.56 4,347.8 -6,633.6 -6,471.8307.20 415,981.445,966,294.42 70° 19' 4.295 N 150° 40' 51.814 W NT3 MFS 12,200.0 87.03 4,351.4 -6,593.5 -6,522.8309.27 415,930.925,966,335.09 70° 19' 4.690 N 150° 40' 53.302 W 12,300.0 87.75 4,356.0 -6,528.2 -6,598.3312.44 415,856.055,966,401.19 70° 19' 5.332 N 150° 40' 55.508 W 12,400.0 88.48 4,359.3 -6,458.7 -6,670.2315.61 415,784.925,966,471.37 70° 19' 6.014 N 150° 40' 57.607 W 12,467.0 88.97 4,360.8 -6,410.0 -6,716.1317.73 415,739.475,966,520.56 70° 19' 6.493 N 150° 40' 58.949 W 9-5/8" Production Liner 12,500.0 89.21 4,361.3 -6,385.4 -6,738.1318.78 415,717.765,966,545.40 70° 19' 6.735 N 150° 40' 59.591 W 12,544.7 89.54 4,361.8 -6,351.4 -6,767.1320.19 415,689.085,966,579.67 70° 19' 7.069 N 150° 41' 0.439 W NT3.2 Top Reservoir 12,600.0 89.95 4,362.0 -6,308.4 -6,801.9321.94 415,654.785,966,623.04 70° 19' 7.492 N 150° 41' 1.454 W 12,700.0 90.68 4,361.5 -6,228.0 -6,861.3325.11 415,596.175,966,704.04 70° 19' 8.282 N 150° 41' 3.191 W 12,800.0 91.41 4,359.7 -6,144.4 -6,916.2328.27 415,542.145,966,788.14 70° 19' 9.103 N 150° 41' 4.795 W 12,833.3 91.66 4,358.8 -6,116.0 -6,933.5329.33 415,525.195,966,816.81 70° 19' 9.383 N 150° 41' 5.299 W 12,900.0 91.66 4,356.8 -6,058.6 -6,967.5329.33 415,491.785,966,874.48 70° 19' 9.946 N 150° 41' 6.293 W 17/04/2025 12:36:05 COMPASS 5000.17 Build Page 6 Santos Ltd Planning Report - Geographic Well B-11Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-11Well: NDB-011Wellbore: Plan: NDB-011 Rev F.1Design: Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft)Latitude Longitude Planned Survey Vertical Depth (usft) 13,000.0 91.66 4,354.0 -5,972.6 -7,018.5329.33 415,441.695,966,960.97 70° 19' 10.791 N 150° 41' 7.783 W 13,100.0 91.66 4,351.1 -5,886.7 -7,069.5329.33 415,391.605,967,047.46 70° 19' 11.637 N 150° 41' 9.273 W 13,200.0 91.66 4,348.2 -5,800.7 -7,120.5329.33 415,341.505,967,133.95 70° 19' 12.482 N 150° 41' 10.764 W 13,300.0 91.66 4,345.3 -5,714.7 -7,171.4329.33 415,291.415,967,220.44 70° 19' 13.327 N 150° 41' 12.254 W 13,400.0 91.66 4,342.4 -5,628.7 -7,222.4329.33 415,241.325,967,306.92 70° 19' 14.172 N 150° 41' 13.744 W 13,500.0 91.66 4,339.5 -5,542.8 -7,273.4329.33 415,191.225,967,393.41 70° 19' 15.017 N 150° 41' 15.235 W 13,600.0 91.66 4,336.6 -5,456.8 -7,324.4329.33 415,141.135,967,479.90 70° 19' 15.862 N 150° 41' 16.725 W 13,700.0 91.66 4,333.7 -5,370.8 -7,375.4329.33 415,091.045,967,566.39 70° 19' 16.707 N 150° 41' 18.216 W 13,800.0 91.66 4,330.8 -5,284.8 -7,426.4329.33 415,040.945,967,652.88 70° 19' 17.552 N 150° 41' 19.706 W 13,900.0 91.66 4,327.9 -5,198.9 -7,477.4329.33 414,990.855,967,739.37 70° 19' 18.397 N 150° 41' 21.197 W 14,000.0 91.66 4,325.0 -5,112.9 -7,528.4329.33 414,940.765,967,825.86 70° 19' 19.242 N 150° 41' 22.687 W 14,100.0 91.66 4,322.1 -5,026.9 -7,579.4329.33 414,890.675,967,912.35 70° 19' 20.087 N 150° 41' 24.178 W 14,200.0 91.66 4,319.2 -4,940.9 -7,630.3329.33 414,840.585,967,998.84 70° 19' 20.932 N 150° 41' 25.668 W 14,300.0 91.66 4,316.3 -4,855.0 -7,681.3329.33 414,790.495,968,085.34 70° 19' 21.777 N 150° 41' 27.159 W 14,400.0 91.66 4,313.4 -4,769.0 -7,732.3329.33 414,740.395,968,171.83 70° 19' 22.622 N 150° 41' 28.649 W 14,500.0 91.66 4,310.5 -4,683.0 -7,783.3329.33 414,690.305,968,258.32 70° 19' 23.468 N 150° 41' 30.140 W 14,600.0 91.66 4,307.6 -4,597.0 -7,834.3329.33 414,640.215,968,344.81 70° 19' 24.313 N 150° 41' 31.631 W 14,700.0 91.66 4,304.8 -4,511.1 -7,885.3329.33 414,590.125,968,431.30 70° 19' 25.158 N 150° 41' 33.122 W 14,800.0 91.66 4,301.9 -4,425.1 -7,936.3329.33 414,540.035,968,517.79 70° 19' 26.003 N 150° 41' 34.612 W 14,900.0 91.66 4,299.0 -4,339.1 -7,987.2329.33 414,489.945,968,604.28 70° 19' 26.848 N 150° 41' 36.103 W 15,000.0 91.66 4,296.1 -4,253.1 -8,038.2329.33 414,439.855,968,690.77 70° 19' 27.693 N 150° 41' 37.594 W 15,100.0 91.66 4,293.2 -4,167.1 -8,089.2329.33 414,389.765,968,777.27 70° 19' 28.538 N 150° 41' 39.085 W 15,200.0 91.66 4,290.3 -4,081.2 -8,140.2329.33 414,339.685,968,863.76 70° 19' 29.383 N 150° 41' 40.576 W 15,300.0 91.66 4,287.4 -3,995.2 -8,191.2329.33 414,289.595,968,950.25 70° 19' 30.228 N 150° 41' 42.066 W 15,400.0 91.66 4,284.5 -3,909.2 -8,242.2329.33 414,239.505,969,036.74 70° 19' 31.073 N 150° 41' 43.557 W 15,500.0 91.66 4,281.6 -3,823.2 -8,293.1329.33 414,189.415,969,123.23 70° 19' 31.918 N 150° 41' 45.048 W 15,600.0 91.66 4,278.7 -3,737.3 -8,344.1329.33 414,139.325,969,209.73 70° 19' 32.763 N 150° 41' 46.539 W 15,700.0 91.66 4,275.8 -3,651.3 -8,395.1329.33 414,089.235,969,296.22 70° 19' 33.608 N 150° 41' 48.030 W 15,800.0 91.66 4,272.9 -3,565.3 -8,446.1329.33 414,039.155,969,382.71 70° 19' 34.453 N 150° 41' 49.521 W 15,900.0 91.66 4,270.0 -3,479.3 -8,497.1329.33 413,989.065,969,469.21 70° 19' 35.298 N 150° 41' 51.012 W 16,000.0 91.66 4,267.1 -3,393.3 -8,548.1329.33 413,938.975,969,555.70 70° 19' 36.143 N 150° 41' 52.503 W 16,100.0 91.66 4,264.2 -3,307.4 -8,599.0329.33 413,888.895,969,642.19 70° 19' 36.988 N 150° 41' 53.994 W 16,200.0 91.66 4,261.3 -3,221.4 -8,650.0329.33 413,838.805,969,728.68 70° 19' 37.833 N 150° 41' 55.486 W 16,300.0 91.66 4,258.4 -3,135.4 -8,701.0329.33 413,788.715,969,815.18 70° 19' 38.678 N 150° 41' 56.977 W 16,400.0 91.66 4,255.6 -3,049.4 -8,752.0329.33 413,738.635,969,901.67 70° 19' 39.523 N 150° 41' 58.468 W 16,500.0 91.66 4,252.7 -2,963.4 -8,803.0329.33 413,688.545,969,988.17 70° 19' 40.368 N 150° 41' 59.959 W 16,600.0 91.66 4,249.8 -2,877.5 -8,854.0329.33 413,638.455,970,074.66 70° 19' 41.213 N 150° 42' 1.450 W 16,700.0 91.66 4,246.9 -2,791.5 -8,904.9329.33 413,588.375,970,161.15 70° 19' 42.058 N 150° 42' 2.942 W 16,800.0 91.66 4,244.0 -2,705.5 -8,955.9329.33 413,538.285,970,247.65 70° 19' 42.903 N 150° 42' 4.433 W 16,900.0 91.66 4,241.1 -2,619.5 -9,006.9329.33 413,488.205,970,334.14 70° 19' 43.748 N 150° 42' 5.924 W 17,000.0 91.66 4,238.2 -2,533.5 -9,057.9329.34 413,438.115,970,420.64 70° 19' 44.593 N 150° 42' 7.416 W 17,100.0 91.66 4,235.3 -2,447.6 -9,108.9329.34 413,388.035,970,507.13 70° 19' 45.438 N 150° 42' 8.907 W 17,200.0 91.66 4,232.4 -2,361.6 -9,159.8329.34 413,337.955,970,593.63 70° 19' 46.283 N 150° 42' 10.398 W 17,300.0 91.66 4,229.5 -2,275.6 -9,210.8329.34 413,287.865,970,680.12 70° 19' 47.128 N 150° 42' 11.890 W 17,400.0 91.66 4,226.6 -2,189.6 -9,261.8329.34 413,237.785,970,766.62 70° 19' 47.973 N 150° 42' 13.381 W 17,500.0 91.66 4,223.7 -2,103.6 -9,312.8329.34 413,187.705,970,853.11 70° 19' 48.818 N 150° 42' 14.873 W 17,600.0 91.66 4,220.8 -2,017.7 -9,363.8329.34 413,137.615,970,939.61 70° 19' 49.663 N 150° 42' 16.364 W 17,700.0 91.66 4,217.9 -1,931.7 -9,414.7329.34 413,087.535,971,026.10 70° 19' 50.508 N 150° 42' 17.856 W 17,800.0 91.66 4,215.0 -1,845.7 -9,465.7329.34 413,037.455,971,112.60 70° 19' 51.353 N 150° 42' 19.347 W 17,900.0 91.66 4,212.1 -1,759.7 -9,516.7329.34 412,987.365,971,199.09 70° 19' 52.198 N 150° 42' 20.839 W 18,000.0 91.66 4,209.2 -1,673.7 -9,567.7329.34 412,937.285,971,285.59 70° 19' 53.043 N 150° 42' 22.331 W 18,100.0 91.66 4,206.3 -1,587.7 -9,618.6329.34 412,887.205,971,372.08 70° 19' 53.888 N 150° 42' 23.822 W 18,200.0 91.66 4,203.5 -1,501.8 -9,669.6329.34 412,837.125,971,458.58 70° 19' 54.733 N 150° 42' 25.314 W 18,300.0 91.66 4,200.6 -1,415.8 -9,720.6329.34 412,787.045,971,545.08 70° 19' 55.578 N 150° 42' 26.806 W 18,400.0 91.66 4,197.7 -1,329.8 -9,771.6329.34 412,736.955,971,631.57 70° 19' 56.423 N 150° 42' 28.297 W 18,500.0 91.66 4,194.8 -1,243.8 -9,822.6329.34 412,686.875,971,718.07 70° 19' 57.268 N 150° 42' 29.789 W 18,600.0 91.66 4,191.9 -1,157.8 -9,873.5329.34 412,636.795,971,804.57 70° 19' 58.113 N 150° 42' 31.281 W 18,630.0 91.66 4,191.0 -1,132.0 -9,888.8329.34 412,621.775,971,830.52 70° 19' 58.367 N 150° 42' 31.728 W 4-1/2" Production Liner 18,637.2 91.66 4,190.8 -1,125.8 -9,892.5329.34 412,618.155,971,836.77 70° 19' 58.428 N 150° 42' 31.836 W 17/04/2025 12:36:05 COMPASS 5000.17 Build Page 7 Santos Ltd Planning Report - Geographic Well B-11Local Co-ordinate Reference:Database:EDM Parker 272 @ 69.8usftTVD Reference:Santos NAD27 ConversionCompany: Parker 272 @ 69.8usftMD Reference:PikkaProject: TrueNorth Reference:NDBSite: Minimum CurvatureSurvey Calculation Method:B-11Well: NDB-011Wellbore: Plan: NDB-011 Rev F.1Design: 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-011 Toe Rev 1.0 4,190.8 5,971,836.77 412,618.15-1,125.8 -9,892.50.00 0.00 70° 19' 58.428 N 150° 42' 31.836 W - plan hits target center - Point NDB-011 Heel Rev 4.0 4,358.8 5,966,816.81 415,525.19-6,116.0 -6,933.50.00 0.00 70° 19' 9.383 N 150° 41' 5.299 W - plan hits target center - Polygon 39.7Point 1 5,966,850.74 416,083.024,358.8 557.5 True 5,460.1Point 2 5,972,303.56 412,924.684,358.8 -2,657.3 True 4,950.1Point 3 5,971,802.51 412,059.744,358.8 -3,517.1 True -470.3Point 4 5,966,349.70 415,218.074,358.8 -302.3 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 Casing2,376.92,785.0 13-3/8 16 9-5/8" Production Liner4,360.812,467.0 9-5/8 12-1/4 4-1/2" Production Liner4,191.018,630.0 4-1/2 8-1/2 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations 1,057.6 Upper Schrader Bluff 0.001,048.8 1,150.8 Base Ice Bearing Permafrost 0.001,138.8 1,416.1 Base Permafrost Transition 0.001,389.8 1,804.6 Middle Schrader Bluff 0.001,731.8 2,376.9 MCU 0.002,153.8 2,963.4 Tuluvak Shale 0.002,450.8 3,168.5 Tuluvak Sand 0.002,516.8 4,670.1 TS_790 0.002,843.8 6,167.3 Seabee 0.003,166.8 9,528.1 Nanushuk 0.003,892.8 9,737.1 NT8 MFS 0.003,939.8 9,935.8 NT7 MFS 0.003,984.8 10,176.2 NT6 MFS 0.004,038.8 10,451.3 NT5 MFS 0.004,098.8 11,003.2 NT4 MFS 0.004,207.8 12,135.0 NT3 MFS 0.004,347.8 12,544.7 NT3.2 Top Reservoir 0.004,361.8 17/04/2025 12:36:05 COMPASS 5000.17 Build Page 8 -15000150030004500True Vertical Depth-1500 0 1500 3000 4500 6000 7500 9000 10500Vertical Section at 263.51°20" Conductor Casing13-3/8" Surface Casing9-5/8" Production Liner4-1/2" Production Liner10002000300040005000600070008000900010000110001200013000 1 4000 15000 16000 17000 18000 18637 0°30°60°78°90°92° P l an : ND B -0 11 Re v F.1 Upper Schrader BluffBase Ice Bearing PermafrostBase Permafrost TransitionMiddle Schrader BluffMCUTuluvak ShaleTuluvak SandTS_790SeabeeNanushukNT8 MFSNT7 MFSNT6 MFSNT5 MFSNT4 MFSNT3 MFSNT3.2 Top ReservoirPlan: NDB-011 Rev F.112:03, April 17 2025 -6000-4500-3000-150001500South(-)/North(+)-10500 -9000 -7500 -6000 -4500 -3000 -1500 0West(-)/East(+)NDB-011 Heel Rev 4.095% conf.NDB-011 Toe Rev 1.020" Conductor Casing13-3/8" Surface Casing9-5/8" Production Liner4-1/2" Production LinerPlan: NDB-011 Rev F.1Plan: NDB-011 Rev F.112:01, April 17 2025 Northing (6000 usft/in)Easting (6000 usft/in)Northing (6000 usft/in)Easting (6000 usft/in)NDB-011 Toe Rev 1.0Qugruk 3Quguruk 3AQugruk 301Plan: NDB-01 Rev A.0Plan: NDB-02 Rev A.0NDB-03 Slot SaverPlan: NDB-04 Rev A.0Plan: NDB-05 Rev A.0Plan: NDBi-06 Rev B.0Plan: NDBi-07 Rev A.0NDB-08 Slot SaverPlan: NDB-09 Rev A.0Plan: NDB-010 Rev B.0Plan: NDBi-012 Slot SaverPlan: NDBi-013 Slot SaverNDBi-014Plan: NDB-015 Rev A.0NDBi-016NDB-017 Slot SaverNDBi-018Plan: NDBi-019 Rev A.0Plan: NDBi-020 Rev A.0Plan:NDB-021 Rev A.0Plan NDB-022 Rev A.0NDB-023 Slot SaverNDB-024NDB-024PB1NDB-025Plan NDBi-028 Rev A.0Plan: NDB-031 Rev E.1Plan: NDB-033 Rev A.0NDBi-036Plan: NDBi-036 Rev E.0Plan: NDBi-038 Rev A.0Plan: NDB-040 Rev C.1Plan: NDB-045 Rev A.0NDBi-046NDBi-046 L1NDB-048NDBi-049NDBi-050NDBi-050 PB1NDB-051Qugruk-3Qugruk-3AQugruk-301Plan: NDB-011 Rev F.1NDANDBNPF12:24, April 17 2025 17 April, 2025 Anticollision Summary Report Santos Pikka NDB B-11 NDB-011 Plan: NDB-011 Rev F.1 Santos Ltd Anticollision Summary Report Well B-11 - Slot B-11Local Co-ordinate Reference:SantosCompany: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-11Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-011 Database:EDM Offset DatumReference Design:Plan: NDB-011 Rev F.1 Offset TVD Reference: Interpolation Method: Depth Range: Reference Error Model: Scan Method: Error Surface: Filter type: ISCWSA Closest Approach 3D Combined Pedal Curve GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of refere MD Interval 25.0usft Unlimited Maximum centre distance of 2,059.0usft Plan: NDB-011 Rev F.1 Results Limited by: SigmaWarning Levels Evaluated at:2.79 ISCWSA TESTCasing Method: From (usft) Survey Tool Program DescriptionTool NameSurvey (Wellbore) To (usft) Date 17/04/2025 SDI_URSA1_I4 SDI URSA-1 gyroMWD (ISCWSA Rev 4)47.0 900.0 Plan: NDB-011 Rev F.1 (NDB-011) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag900.0 2,790.0 Plan: NDB-011 Rev F.1 (NDB-011) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag2,790.0 12,471.0 Plan: NDB-011 Rev F.1 (NDB-011) 3_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi-station analysis + sag12,471.0 18,636.9 Plan: NDB-011 Rev F.1 (NDB-011) Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB CCB-01 - NDB-01 - Plan: NDB-01 Rev A.0 325.0 325.2 199.9 190.8 40.674 ESB-01 - NDB-01 - Plan: NDB-01 Rev A.0 350.0 350.2 199.9 190.8 40.284 SFB-01 - NDB-01 - Plan: NDB-01 Rev A.0 550.0 534.0 210.0 200.3 38.625 CCB-02 - NDB-02 - Plan: NDB-02 Rev A.0 325.0 325.2 179.8 170.8 36.422 ESB-02 - NDB-02 - Plan: NDB-02 Rev A.0 350.0 350.0 179.8 170.7 36.078 SFB-02 - NDB-02 - Plan: NDB-02 Rev A.0 525.0 511.7 188.7 179.1 35.001 CCB-03 - NDB-03 - NDB-03 Slot Saver 325.0 325.2 159.8 151.0 33.181 ESB-03 - NDB-03 - NDB-03 Slot Saver 350.0 350.2 159.8 150.9 32.999 SFB-03 - NDB-03 - NDB-03 Slot Saver 725.0 724.1 172.1 162.5 31.366 CCB-04 - NDB-04 - Plan: NDB-04 Rev A.0 325.0 325.2 139.8 130.7 28.195 ESB-04 - NDB-04 - Plan: NDB-04 Rev A.0 350.0 350.1 139.8 130.6 27.927 SFB-04 - NDB-04 - Plan: NDB-04 Rev A.0 550.0 544.1 147.0 137.3 26.736 CCB-05 - NDB-05 - Plan: NDB-05 Rev A.0 325.0 325.2 119.8 110.8 24.102 ESB-05 - NDB-05 - Plan: NDB-05 Rev A.0 350.0 350.2 119.8 110.7 23.873 SFB-05 - NDB-05 - Plan: NDB-05 Rev A.0 550.0 546.3 125.9 116.2 22.816 CCB-06 - NDBi-06 - Plan: NDBi-06 Rev B.0 325.0 325.2 99.8 91.0 20.429 ESB-06 - NDBi-06 - Plan: NDBi-06 Rev B.0 350.0 350.2 99.8 90.9 20.318 SFB-06 - NDBi-06 - Plan: NDBi-06 Rev B.0 450.0 449.3 101.1 92.0 20.053 CCB-07 - NDBi-07 - Plan: NDBi-07 Rev A.0 325.0 325.2 79.7 70.7 15.875 ESB-07 - NDBi-07 - Plan: NDBi-07 Rev A.0 350.0 350.2 79.7 70.6 15.724 SFB-07 - NDBi-07 - Plan: NDBi-07 Rev A.0 475.0 474.1 81.8 72.3 15.257 CCB-08 - NDB-08 - NDB-08 Slot Saver 325.0 325.2 59.7 50.9 12.094 ESB-08 - NDB-08 - NDB-08 Slot Saver 350.0 350.2 59.7 50.9 12.027 SFB-08 - NDB-08 - NDB-08 Slot Saver 450.0 450.2 60.5 51.5 11.884 CCB-09 - NDB-09 - Plan: NDB-09 Rev A.0 325.0 325.2 39.7 30.6 7.654 ESB-09 - NDB-09 - Plan: NDB-09 Rev A.0 350.0 350.2 39.7 30.5 7.581 SFB-09 - NDB-09 - Plan: NDB-09 Rev A.0 425.0 425.0 40.3 31.0 7.465 CCB-10 - NDB-010 - Plan: NDB-010 Rev B.0 325.0 325.0 20.1 11.2 3.733 ESB-10 - NDB-010 - Plan: NDB-010 Rev B.0 350.0 350.0 20.1 11.2 3.713 SFB-10 - NDB-010 - Plan: NDB-010 Rev B.0 375.0 375.0 20.1 11.2 3.703 CCB-12 - NDBi-012 - Plan: NDBi-012 Slot Saver 571.8 571.6 18.0 8.7 3.061 ES, SFB-12 - NDBi-012 - Plan: NDBi-012 Slot Saver 575.0 574.8 18.0 8.7 3.058 CCB-13 - NDB-013 - Plan: NDBi-013 Slot Saver 664.3 663.6 36.0 26.5 6.365 ESB-13 - NDB-013 - Plan: NDBi-013 Slot Saver 675.0 674.3 36.1 26.5 6.341 SFB-13 - NDB-013 - Plan: NDBi-013 Slot Saver 700.0 699.1 36.3 26.7 6.319 CCB-14 - NDBi-014 - NDBi-014 737.5 732.8 56.5 46.8 9.956 ESB-14 - NDBi-014 - NDBi-014 775.0 769.7 56.5 46.7 9.845 SFB-14 - NDBi-014 - NDBi-014 2,550.0 2,518.0 167.6 133.8 6.681 CCB-15 - NDB-015 - Plan: NDB-015 Rev A.0 474.7 473.7 80.2 70.7 14.959 17/04/2025 12:45:34 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-11 - Slot B-11Local Co-ordinate Reference:SantosCompany: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-11Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-011 Database:EDM Offset DatumReference Design:Plan: NDB-011 Rev F.1 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB ESB-15 - NDB-015 - Plan: NDB-015 Rev A.0 500.0 498.5 80.3 70.7 14.779 SFB-15 - NDB-015 - Plan: NDB-015 Rev A.0 600.0 595.6 82.6 72.6 14.405 CCB-16 - NDBi-016 - NDBi-016 52.0 51.7 100.1 91.0 21.045 ESB-16 - NDBi-016 - NDBi-016 75.0 74.7 100.1 91.0 21.039 SFB-16 - NDBi-016 - NDBi-016 675.0 668.9 103.1 93.5 18.880 CC, ESB-17 - NDB-017 - NDB-017 Slot Saver 882.4 879.0 108.5 98.4 18.528 SFB-17 - NDB-017 - NDB-017 Slot Saver 950.0 944.9 109.5 99.3 18.278 CCB-18 - NDBi-018 - NDBi-018 690.8 685.2 136.2 126.7 25.375 ESB-18 - NDBi-018 - NDBi-018 700.0 694.2 136.2 126.7 25.280 SFB-18 - NDBi-018 - NDBi-018 825.0 813.6 138.8 128.9 24.347 CCB-19 - NDBi-019 - Plan: NDBi-019 Rev A.0 644.2 637.2 156.4 146.3 27.093 ESB-19 - NDBi-019 - Plan: NDBi-019 Rev A.0 650.0 642.5 156.4 146.3 27.004 SFB-19 - NDBi-019 - Plan: NDBi-019 Rev A.0 5,325.0 4,901.9 833.7 742.4 11.709 CC, ESB-20 - NDBi-020 - Plan: NDBi-020 Rev A.0 606.1 602.0 177.7 167.7 31.383 SFB-20 - NDBi-020 - Plan: NDBi-020 Rev A.0 775.0 756.4 185.0 174.3 29.586 CCB-21 - NDB-021 - Plan:NDB-021 Rev A.0 652.3 643.2 196.3 186.3 34.225 ESB-21 - NDB-021 - Plan:NDB-021 Rev A.0 675.0 663.9 196.4 186.2 33.787 SFB-21 - NDB-021 - Plan:NDB-021 Rev A.0 10,950.0 10,147.7 1,998.0 1,776.7 11.405 CCB-22 - NDB-022 - Plan NDB-022 Rev A.0 615.6 610.0 217.4 207.4 37.931 ESB-22 - NDB-022 - Plan NDB-022 Rev A.0 625.0 618.6 217.5 207.4 37.733 SFB-22 - NDB-022 - Plan NDB-022 Rev A.0 825.0 800.0 228.4 217.4 35.242 CC, ESB-23 - NDB-023 - NDB-023 Slot Saver 1,012.7 1,000.0 217.9 207.5 36.005 SFB-23 - NDB-023 - NDB-023 Slot Saver 1,025.0 1,000.0 218.3 207.9 35.938 CC, ESB-24 - NDB-024 - NDB-024 632.0 626.0 255.1 245.7 47.371 SFB-24 - NDB-024 - NDB-024 800.0 770.8 263.1 253.2 45.549 CC, ESB-24 - NDB-024PB1 - NDB-024PB1 632.0 626.0 255.1 245.5 47.342 SFB-24 - NDB-024PB1 - NDB-024PB1 800.0 770.8 263.1 253.0 45.522 CCB-25 - NDB-025 - NDB-025 1,602.6 1,528.3 260.2 246.1 28.713 ESB-25 - NDB-025 - NDB-025 1,675.0 1,592.1 260.6 245.7 26.819 SFB-25 - NDB-025 - NDB-025 2,800.0 2,592.0 377.7 341.1 13.856 CCB-28 - NDBi-028 - Plan NDBi-028 Rev A.0 660.2 644.1 336.4 326.3 58.424 ESB-28 - NDBi-028 - Plan NDBi-028 Rev A.0 675.0 656.8 336.4 326.2 57.954 SFB-28 - NDBi-028 - Plan NDBi-028 Rev A.0 14,125.0 10,433.1 1,830.2 1,610.6 10.521 CC, ESB-31 - NDB-031 - Plan: NDB-031 Rev E.1 346.8 346.8 399.9 391.0 82.909 SFB-31 - NDB-031 - Plan: NDB-031 Rev E.1 14,875.0 10,544.2 1,492.6 1,242.7 7.525 CCB-33 - NDB-033 - Plan: NDB-033 Rev A.0 754.4 725.8 433.6 423.7 78.822 ESB-33 - NDB-033 - Plan: NDB-033 Rev A.0 775.0 742.7 433.6 423.7 78.134 SFB-33 - NDB-033 - Plan: NDB-033 Rev A.0 15,475.0 10,395.6 1,722.3 1,487.7 9.257 CC, ESB-36 - NDBi-036 - NDBi-036 47.0 47.0 500.0 490.9 107.403 SFB-36 - NDBi-036 - NDBi-036 15,325.0 10,508.4 1,198.9 942.6 5.888 CC, ESB-36 - NDBi-036 - Plan: NDBi-036 Rev E.0 346.8 346.8 500.0 491.1 103.797 SFB-36 - NDBi-036 - Plan: NDBi-036 Rev E.0 15,325.0 10,521.8 1,202.0 944.6 5.881 CCB-38 - NDBi-038 - Plan: NDBi-038 Rev A.0 666.1 639.7 536.5 527.0 101.366 ESB-38 - NDBi-038 - Plan: NDBi-038 Rev A.0 675.0 646.7 536.5 527.0 101.098 SFB-38 - NDBi-038 - Plan: NDBi-038 Rev A.0 16,125.0 10,359.3 1,679.2 1,458.1 9.584 CC, ESB-40 - NDB-040 - Plan: NDB-040 Rev C.1 347.9 347.0 580.1 571.2 120.487 SFB-40 - NDB-040 - Plan: NDB-040 Rev C.1 16,075.0 10,435.8 1,282.7 1,032.1 6.446 CCB-45 - NDB-045 - Plan: NDB-045 Rev A.0 728.2 687.0 675.2 664.8 113.056 ESB-45 - NDB-045 - Plan: NDB-045 Rev A.0 750.0 700.0 675.2 664.7 111.951 SFB-45 - NDB-045 - Plan: NDB-045 Rev A.0 16,725.0 10,410.4 1,436.7 1,187.8 7.268 SFB-46 - NDBi-046 - NDBi-046 18,625.0 11,127.3 535.9 278.1 2.613 CC, ESB-46 - NDBi-046 - NDBi-046 18,636.9 11,129.8 527.7 273.9 2.614 SFB-46 - NDBi-046 L1 - NDBi-046 L1 18,625.0 11,127.3 535.9 278.1 2.613 CC, ESB-46 - NDBi-046 L1 - NDBi-046 L1 18,636.9 11,129.8 527.7 273.9 2.614 CCB-48 - NDB-048 - NDB-048 18,012.0 10,868.7 577.8 460.3 6.241 ESB-48 - NDB-048 - NDB-048 18,250.0 10,945.6 620.1 418.4 3.875 SFB-48 - NDB-048 - NDB-048 18,550.0 11,045.0 769.6 468.7 3.213 CCB-49 - NDBi-049 - NDBi-049 15,985.2 10,310.5 700.6 594.2 8.394 17/04/2025 12:45:34 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-11 - Slot B-11Local Co-ordinate Reference:SantosCompany: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-11Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-011 Database:EDM Offset DatumReference Design:Plan: NDB-011 Rev F.1 Offset TVD Reference: Offset Well - Wellbore - Design Reference Measured Depth (usft) Offset Measured Depth (usft) Between Centres (usft) Between Ellipses (usft) Separation Factor Warning Summary Site Name Distance NDB ESB-49 - NDBi-049 - NDBi-049 16,175.0 10,336.6 725.4 576.8 6.186 SFB-49 - NDBi-049 - NDBi-049 16,625.0 10,400.0 944.6 674.5 4.400 CCB-50 - NDBi-050 - NDBi-050 17,005.2 10,516.5 622.0 516.0 7.465 ESB-50 - NDBi-050 - NDBi-050 17,200.0 10,563.6 650.0 493.6 5.253 SFB-50 - NDBi-050 - NDBi-050 17,575.0 10,650.7 832.4 568.2 3.963 CCB-50 - NDBi-050 PB1 - NDBi-050 PB1 52.0 51.8 780.0 770.9 167.859 ESB-50 - NDBi-050 PB1 - NDBi-050 PB1 17,100.0 10,494.9 826.3 677.3 7.027 SFB-50 - NDBi-050 PB1 - NDBi-050 PB1 17,650.0 10,630.2 1,083.7 801.8 4.838 Take Immediate Action, CB-51 - NDB-051 - NDB-051 18,636.9 11,271.5 131.8 -27.3 1.036 Qugruk 3 Caution - Monitor CloselyQugruk 3 - Qugruk 3 - Qugruk 3 18,358.0 4,276.9 244.7 39.6 1.496 Caution - Monitor CloselyQugruk 3 - Qugruk 3 - Qugruk 3 18,375.0 4,270.6 245.3 39.4 1.494 CC, ES, SFQugruk 3 - Quguruk 3A - Quguruk 3A 18,636.9 3,735.6 856.5 665.8 5.665 CC, ES, SFQugruk 301 - Qugruk 301 - Qugruk 301 18,636.9 3,569.0 1,109.9 920.4 7.400 Wildcat Caution - Monitor CloselyQugruk-3 - Qugruk-3 - Qugruk-3 18,368.1 4,279.1 215.9 8.3 1.303 Caution - Monitor CloselyQugruk-3 - Qugruk-3 - Qugruk-3 18,375.0 4,276.6 216.0 8.0 1.301 CC, ES, SFQugruk-3 - Qugruk-3A - Qugruk-3A 18,636.9 3,735.6 855.8 664.4 5.642 CC, ES, SFQugruk-301 - Qugruk-301 - Qugruk-301 18,636.9 3,569.0 1,109.9 920.8 7.414 17/04/2025 12:45:34 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-11 - Slot B-11Local Co-ordinate Reference:SantosCompany: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-11Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-011 Database:EDM Offset DatumReference Design:Plan: NDB-011 Rev F.1 Offset TVD Reference: 0 500 1000 1500 2000 Centre to Centre Separation0 3500 7000 10500 14000 17500 21000 Measured Depth Ladder Plot Qugruk 3, Qugruk 3, Qugruk 3 V0 Qugruk 3, Quguruk 3A, Quguruk 3A V0 Qugruk 301, Qugruk 301, Qugruk 301 V0 B-01, NDB-01, Plan: NDB-01 Rev A.0 V0 B-02, NDB-02, Plan: NDB-02 Rev A.0 V0 B-03, NDB-03, NDB-03 Slot Saver V0 B-04, NDB-04, Plan: NDB-04 Rev A.0 V0 B-05, NDB-05, Plan: NDB-05 Rev A.0 V0 B-06, NDBi-06, Plan: NDBi-06 Rev B.0 V0 B-07, NDBi-07, Plan: NDBi-07 Rev A.0 V0 B-08, NDB-08, NDB-08 Slot Saver V0 B-09, NDB-09, Plan: NDB-09 Rev A.0 V0 B-10, NDB-010, Plan: NDB-010 Rev B.0 V0 B-12, NDBi-012, Plan: NDBi-012 Slot Saver V0 B-13, NDB-013, Plan: NDBi-013 Slot Saver V0 B-14, NDBi-014, NDBi-014 V0 B-15, NDB-015, Plan: NDB-015 Rev A.0 V0 B-16, NDBi-016, NDBi-016 V0 B-17, NDB-017, NDB-017 Slot Saver V0 B-18, NDBi-018, NDBi-018 V0 B-19, NDBi-019, Plan: NDBi-019 Rev A.0 V0 B-20, NDBi-020, Plan: NDBi-020 Rev A.0 V0 B-21, NDB-021, Plan:NDB-021 Rev A.0 V0 B-22, NDB-022, Plan NDB-022 Rev A.0 V0 B-23, NDB-023, NDB-023 Slot Saver V0 B-24, NDB-024, NDB-024 V0 B-24, NDB-024PB1, NDB-024PB1 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-33, NDB-033, Plan: NDB-033 Rev A.0 V0 B-36, NDBi-036, NDBi-036 V0 B-36, NDBi-036, Plan: NDBi-036 Rev E.0 V0 B-38, NDBi-038, Plan: NDBi-038 Rev A.0 V0 B-40, NDB-040, Plan: NDB-040 Rev C.1 V0 B-45, NDB-045, Plan: NDB-045 Rev A.0 V0 B-46, NDBi-046, NDBi-046 V0 B-46, NDBi-046 L1, NDBi-046 L1 V0 B-48, NDB-048, NDB-048 V0 B-49, NDBi-049, NDBi-049 V0 B-50, NDBi-050, NDBi-050 V0 B-50, NDBi-050 PB1, NDBi-050 PB1 V0 B-51, NDB-051, NDB-051 V0 Qugruk-3, Qugruk-3, Qugruk-3 V0 Qugruk-3, Qugruk-3A, Qugruk-3A V0 Qugruk-301, Qugruk-301, Qugruk-301 V0 L E G E N D Coordinates are relative to: B-11 - Slot B-11 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.59°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to Parker 272 @ 69.8usft 17/04/2025 12:45:34 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 5 Santos Ltd Anticollision Summary Report Well B-11 - Slot B-11Local Co-ordinate Reference:SantosCompany: Parker 272 @ 69.8usftTVD Reference:PikkaProject: Parker 272 @ 69.8usftMD Reference:NDBReference Site: TrueNorth Reference:0.9 usftSite Error: Minimum CurvatureSurvey Calculation Method:B-11Reference Well: Output errors are at 2.79 sigmaWell Error:0.5 usft Reference Wellbore NDB-011 Database:EDM Offset DatumReference Design:Plan: NDB-011 Rev F.1 Offset TVD Reference: 0.00 3.00 6.00 9.00 Separation Factor0 3500 7000 10500 14000 17500 Measured Depth Stop Drilling Caution - Monitor Closely Normal Operations Separation Factor Plot Qugruk 3, Qugruk 3, Qugruk 3 V0 Qugruk 3, Quguruk 3A, Quguruk 3A V0 Qugruk 301, Qugruk 301, Qugruk 301 V0 B-01, NDB-01, Plan: NDB-01 Rev A.0 V0 B-02, NDB-02, Plan: NDB-02 Rev A.0 V0 B-03, NDB-03, NDB-03 Slot Saver V0 B-04, NDB-04, Plan: NDB-04 Rev A.0 V0 B-05, NDB-05, Plan: NDB-05 Rev A.0 V0 B-06, NDBi-06, Plan: NDBi-06 Rev B.0 V0 B-07, NDBi-07, Plan: NDBi-07 Rev A.0 V0 B-08, NDB-08, NDB-08 Slot Saver V0 B-09, NDB-09, Plan: NDB-09 Rev A.0 V0 B-10, NDB-010, Plan: NDB-010 Rev B.0 V0 B-12, NDBi-012, Plan: NDBi-012 Slot Saver V0 B-13, NDB-013, Plan: NDBi-013 Slot Saver V0 B-14, NDBi-014, NDBi-014 V0 B-15, NDB-015, Plan: NDB-015 Rev A.0 V0 B-16, NDBi-016, NDBi-016 V0 B-17, NDB-017, NDB-017 Slot Saver V0 B-18, NDBi-018, NDBi-018 V0 B-19, NDBi-019, Plan: NDBi-019 Rev A.0 V0 B-20, NDBi-020, Plan: NDBi-020 Rev A.0 V0 B-21, NDB-021, Plan:NDB-021 Rev A.0 V0 B-22, NDB-022, Plan NDB-022 Rev A.0 V0 B-23, NDB-023, NDB-023 Slot Saver V0 B-24, NDB-024, NDB-024 V0 B-24, NDB-024PB1, NDB-024PB1 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-33, NDB-033, Plan: NDB-033 Rev A.0 V0 B-36, NDBi-036, NDBi-036 V0 B-36, NDBi-036, Plan: NDBi-036 Rev E.0 V0 B-38, NDBi-038, Plan: NDBi-038 Rev A.0 V0 B-40, NDB-040, Plan: NDB-040 Rev C.1 V0 B-45, NDB-045, Plan: NDB-045 Rev A.0 V0 B-46, NDBi-046, NDBi-046 V0 B-46, NDBi-046 L1, NDBi-046 L1 V0 B-48, NDB-048, NDB-048 V0 B-49, NDBi-049, NDBi-049 V0 B-50, NDBi-050, NDBi-050 V0 B-50, NDBi-050 PB1, NDBi-050 PB1 V0 B-51, NDB-051, NDB-051 V0 Qugruk-3, Qugruk-3, Qugruk-3 V0 Qugruk-3, Qugruk-3A, Qugruk-3A V0 Qugruk-301, Qugruk-301, Qugruk-301 V0 L E G E N D Coordinates are relative to: B-11 - Slot B-11 Coordinate System is US State Plane 1983, Alaska Zone 4 Grid Convergence at Surface is: -0.59°Central Meridian is 150° 0' 0.000 W Offset Depths are relative to Offset Datum Reference Depths are relative to Parker 272 @ 69.8usft 17/04/2025 12:45:34 COMPASS 5000.17 Build CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation Page 6 Plan: NDB-011 Rev F.1AC FlipbookSURVEY PROGRAMDepth From Depth To Tool47.0 900.0 SDI_URSA1_I4900.0 2790.0 3_MWD+IFR2+MS+Sag2790.0 12471.0 3_MWD+IFR2+MS+Sag12471.0 18636.9 3_MWD+IFR2+MS+SagCASING DETAILSTVD MD Name128.0 128.0 20" Conductor Casing2376.9 2785.013-3/8" Surface Casing4360.8 12467.09-5/8" Production Liner4191.0 18630.04-1/2" Production Liner1515303045456060757590900901802703021060240120300150330Travelling Cylinder Azimuth (TFO+AZI) [°] vs Travelling Cylinder Separation [30 usft/in]475075100125150175200225250275300325350375401426451476502527552578603628653679704730755780806831856882907932958983100810331058108311081133115811831209123412591285131013361361138614121437146214871513153815631589161416391664168917141740176517901815184018651890NDBi-014475075100125150175200225250275300325350376401426452477502528553578603627652677701NDBi-016475075100125150175200225250275300325350374399424448473497521Plan: NDBi-06 Rev B.07075100125150175200225250275300325350374399424448473497522546570594618642665Plan: NDBi-07 Rev A.0475075100125150175200225250275300325350375399424449474498523548572597622646670695719743767791815839863886910NDB-08 Slot Saver7075100125150175200225250275300325350375399424449474498523547571596620643667690713736758781Plan: NDB-09 Rev A.0475075100125150175200225250275300325350375400425450475499524549574598623647671695719742766789812835857879Plan: NDB-010 Rev B.0475075100125150175200225250275300325350375400425450475500525550575600625650675699724748773797821846870894918941965988Plan: NDBi-012 Slot Saver475075100125150175200225250275300325350375400425451476501526551576601626651676700725750774799823847871896919943967991Plan: NDBi-013 Slot Saver7075100125150175200225250275300325350375400426451476501526551576600625649673697721744Plan: NDB-015 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 18636.9MD Azi TFace47.0 0.00 0.00347.0 0.00 0.00647.0 190.00 190.00996.8 190.00 0.001146.8 190.00 0.003278.1 213.98 26.229291.7 213.98 0.0012833.1 329.33 94.0618636.9 329.33 0.00 0 30 60 Centre to Centre Separation0 450 900 1350 1800 2250 Partial Measured DepthNDBi-014Plan: NDB-011 Rev F.1 Ladder View 0 150 300 Centre to Centre Separation0 3000 6000 9000 12000 15000 18000 Measured Depth Qugruk 3NDBi-014NDBi-016NDBi-018NDB-024NDB-024PB1NDB-025NDB-051Qugruk-3SURVEY PROGRAM Depth From Depth To Survey/Plan Tool 47.0 900.0 Plan: NDB-011 Rev F.1 (NDB-011) SDI_URSA1_I4 900.0 2790.0 Plan: NDB-011 Rev F.1 (NDB-011) 3_MWD+IFR2+MS+Sag 2790.0 12471.0 Plan: NDB-011 Rev F.1 (NDB-011) 3_MWD+IFR2+MS+Sag 12471.0 18636.9 Plan: NDB-011 Rev F.1 (NDB-011) 3_MWD+IFR2+MS+Sag 12:28, April 17 2025 CASING DETAILS TVD MD Name 128.0 128.020" Conductor Casing 2376.9 2785.013-3/8" Surface Casing 4360.8 12467.09-5/8" Production Liner 4191.0 18630.04-1/2" 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 ChokeLinefromBOPPressureGauge1502PressureSensorPressureTransducerBill ofMaterialItemDescriptionToPanicLineItemDescriptionA3Ͳ1/8”– 5,000psi W.P.RemoteHydraulicOperatedChokeB3Ͳ1/8”–5,000psiW.P.AdjustableManualChoke1–14 3Ͳ1/8”– 5,000psi W.P.ManualGateValve1521/16”5 000 i WP152Ͳ1/16”–5,000psiW.P.ManualGateValveToMudGasLegendBlindSpareToTigerTankSeparatorValveNormally OpenValveNormally Closed Attachment 4: Drilling Hazards 16” Surface Hole Section Hazard Mitigations Conductor Broach Monitor conductor for any indications of broaching. Monitor pit volumes for any losses. Gas Hydrates Keep mud cool, optimize pump rates, minimize any excess circulation. Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends. Anti-Collision Closely monitor real-time surveys and run GWD in BHA 12-1/4” Intermediate Hole Sections Hazard Mitigations Lost Returns Optimal drillpipe sizing. Monitor ECD with MWD tools. Pump LCM as required (consult prepared lost returns decisions tree). Slow pump rates, reduce ROP / trip speed when necessary. ECD modelling for cement jobs. Challenging liner runs The Intermediate liner runs requires relatively low OH friction factor to run to TD (hole cleaning and lubricants). Ability to rotate while RIH to overcome drag. Washouts/Hole Enlargement Drill with oil-based mud, maintain mud in specifications, use sufficient mud weight / back-pressure to hold back formations. Tight Hole/Stuck Pipe Hole cleaning and tripping practices, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight / back- pressure to hold back formations. High Angle Hole Cleaning Conduct T&D and hydraulics modeling, control ROP limits based on cuttings returns and comparison to the models. Pack Off During Cementing Proper wellbore cleanup procedure prior to running in hole. Stage circulation rates up while running in hole with liner. Circulate bottoms up at multiple depths to condition mud the way in the hole. Circulate at TD to planned cementing rates and ensure hole is clean. Wireline Inaccessibility The sail angle on this section is too high for wireline to be run conventionally. If wireline logs are required for operations a tractor will be required. Operational complexity with Mechanical two stage cement equipment (9-5/8” Liner) The 2 nd stage of the cement job will be conducted through a mechanically shifted sleeve. This will require the LTP to not be set until the 2nd stage is pumped giving a higher complexity leading to complications with setting the LTP. 8-1/2” Production Hole Section Hazard Mitigations Lost Returns Pump LCM as required (consult prepared lost returns decisions tree), slow pump rates, reduce ROP or trip speed when necessary. Monitor ECD with MWD tools. Hole Swabbing Reduce tripping speed, lower mud rheology, pump out of the hole if required. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight to hold back formations. Wellbore Instability Maintain adequate mud weight for wellbore stability. Monitor cuttings returns, LWD logs, and drilling parameters for signs of washout. * Note that no H2S has been encountered on nearby offset wells, and H2S is not anticipated in this well. 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) (MPD operations are not planned on NDB-011 however equipment will remain in place and may be used if unexpected or adverse hole conditions are observed and/or if operationally more efficient.) 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: 354 bbls, 1988 cuft, 784 sks ArcticCem, Yield: 2.53 cuft/sk Tail 15.3ppg Tail: 66bbls, 370cuft,299sks HalCem Type I/II–1.24cuft/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-011 13-3/8" SURFACE CEMENT JOB Description TOP BOTTOM LENGTH CAPACITY VOLUME SHOE TRACK LENGTH 2720 2785 65 0.14973 9.7 TAIL LENGTH 2285 2785 500 0.07491 37.5 TAIL EXCESS 50% 18.7 LEAD TOP TO BASE PERMAFROST 1416 2285 869 0.07491 65.1 EXCESS FACTOR FOR ABOVE 50% 32.5 PERMAFROST ANNULUS (Lead) 128 1416 1288 0.07491 96.5 EXCESS FACTOR FOR ABOVE 150% 144.7 CASED HOLE ANNULUS 46 128 82 0.18620 15.3 TOTAL LEAD VOLUME 354.1 TOTAL TAIL VOLUME 65.9 Verified cement calcs. -bjm Intermediate Liner Cement Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Tail Open hole volume + excess + 77 ft shoe track Tail TOC Stage 1: 250’ TVD above the 9-5/8” shoe Stage 2: Top of the 9-5/8” Liner (~150’ liner lap) Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Tail Stage 1: 30% Open Hole Excess 15.3ppg Tail: 91 bbls, 513cuft, 415sks VersaCem Type I/II – 1.24 cuft/sk Stage 2: 100% Open Hole Excess 15.3ppg Tail: 225 bbls, 1262cuft, 1021sks VersaCem Type I/II – 1.24 cuft/sk Temp Stage 1 - BHST 105° F (2.25°/100’ TVD below PermaFrost) Stage 2 - BHST 71° F (2.25°/100’ TVD below PermaFrost) Notes Job will be mixed on the fly Verification Method - LWD Sonic will be used to log the 1 st Stage Cement Job only. -2ndStage Cement Job will not be logged, assuming job parameters are as expected (no losses, good lift pressures, circulate cement off top of liner). Justification: - Stage tool allows for precise placement of base cement column at base Tuluvak hydrocarbon. - Bond log not required for 2 nd Stage per Regulation 20 AAC 25.030(d)(5) -2ndStage bond evaluation does not affect 1st Stage bond evaluation and frac decision. - Logging of 1 st Stage cement will demonstrate isolation between Nanushuk and Tuluvak, ensuring no potential crossflow. -2ndStage cement job will isolate Tuluvak with cement and a V0-rated LTP above it as a redundant means of isolation. - Well design allows for the OA annulus to be freeze protected by circulating in place (with Tieback) vs. bullheaded into place. With a sufficient initial LOT/FIT at the surface casing shoe, any potential Tuluvak pressures will be contained by the surface casing shoe and not cross flow into shallower formations. - Future hydraulic fracture operations will only be done in the Nanushuk formation. Log verification of the 1st stage cement job will verify proper isolation has been achieved for frac operations. - Tuluvak isolation has been achieved on all historical Pikka development wells. - Seeking to simplify an already complicated operation, saving time/money. Verified cement calcs. See attached for updated Int stage 1 calcs. -bjm 100' TVD above top Nanushuk. -bjm Superseded by updated Intermediate Liner Cement calculations. -A.Dewhurst 03JUN25 NDB-011 9.625" Intermediate Liner – 1st Stage Description TOP BOTTOM LENGTH CAPACITY VOLUME SHOE TRACK LENGTH 13209 13286 77 0.07321 5.6 TAIL LENGTH 12105 13286 1181 0.05578 65.9 TAIL EXCESS 30% 19.8 TOTAL TAIL VOLUME 91.3 NDB-011 9.625" Intermediate Liner - 2nd Stage Description TOP BOTTOM LENGTH CAPACITY VOLUME TAIL LENGTH 2785 4720 1935 0.05578 107.9 TAIL EXCESS 100% 107.9 LINER LAP 13-3/8" 68# x 9-5/8" 47# LNR 2635 2785 150 0.05974 9.0 TOTAL TAIL VOLUME 224.8 See attached email from Rob Williams 5/30/25 for updated 1st stagwe cement volume calcs -bjm 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: 9-5/8” Primary Stage 1 Cement Job: The primary cement job will target a top of cement 100 feet TVD above the top of the Nanushuk formation. Due to the ERD nature of this section (inclination 77-89°), 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. The requested variance will not only adequately isolate the Nanushuk formation it will also provide additional coverage above the topmost hydrocarbon zone. 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. 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 (ie. lost circulation, low fracture gradient or excessive washout) observed prior to execution of the cement job. An estimate of cement volumes using a range of cement excess is included in the table below. TOC 9070' MD 3793' TVD 458' MD 100' TVD 667' MD 146' TVD Nanushuk 9528' MD 3893' TVD NT8 9737' MD 3939' TVD 568' TVD 9-5/8" Shoe 12467' MD 4361' TVD 3397' MD 77-89 o INC Intermediate Liner Cement Casing Size 9-5/8” 47# L-80 Hydril 563 Intermediate Liner Basis Tail Open hole volume + excess + 77 ft shoe track Tail TOC Stage 1: 100’ TVD above the Nanushuk formation Stage 2: Top of the 9-5/8” Liner (~150’ liner lap) Total Cement Volume Spacer ~80 bbls of 12.5 ppg Clean Spacer Tail Stage 1: 30-60% Open Hole Excess (dependent on well/operational conditions) 15.3ppg Tail: 30% Excess: 252 bbl, 1414cuft, 1141sks VersaCem Type I/II – 1.24 cuft/sk 60% Excess: 309 bbl, 1734cuft, 13984sks VersaCem Type I/II – 1.24 cuft/sk Stage 2: 100% Open Hole Excess 15.3ppg Tail: 225 bbl, 1262cuft, 1018sks VersaCem Type I/II – 1.24 cuft/sk Temp Stage 1 - BHST 105° F (2.25°/100’ TVD below PermaFrost) Stage 2 - BHST 71° F (2.25°/100’ TVD below PermaFrost) Notes Job will be mixed on the fly Verification Method - LWD Sonic will be used to log the 1 st Stage Cement Job only. -2ndStage Cement Job will not be logged, assuming job parameters are as expected (no losses, good lift pressures, circulate cement off top of liner). Justification: - Stage tool allows for precise placement of base cement column at base Tuluvak hydrocarbon. - Bond log not required for 2 nd Stage per Regulation 20 AAC 25.030(d)(5) -2ndStage bond evaluation does not affect 1st Stage bond evaluation and frac decision. - Logging of 1 st Stage cement will demonstrate isolation between Nanushuk and Tuluvak, ensuring no potential crossflow. -2ndStage cement job will isolate Tuluvak with cement and a V0-rated LTP above it as a redundant means of isolation. - Well design allows for the OA annulus to be freeze protected by circulating in place (with Tieback) vs. bullheaded into place. With a sufficient initial LOT/FIT at the surface casing shoe, any potential Tuluvak pressures will be contained by the surface casing shoe and not cross flow into shallower formations. - Future hydraulic fracture operations will only be done in the Nanushuk formation. Log verification of the 1st stage cement job will verify proper isolation has been achieved for frac operations. - Tuluvak isolation has been achieved on all historical Pikka development wells. - Seeking to simplify an already complicated operation, saving time/money. NDB-011 9-5/8" Production Liner - Stage 1Well DetailsStick Up on Rig Floor -4 ft MD 12.250 " HWDP Length 1240.2 ft MDTop of Liner 2635 ft MD 9.625 " DP Length 1398.8 ft MDCflex Depth 4720 ft MD 8.681 " HWDP Capacity0.0155 bbl/ftLanding Collar Depth N/A ft MD 12.415 " DP Capacity 0.0241 bbl/ftFloat Collar Depth 12390 ft MDCasing Shoe Depth 12467 ft MDTD Hole Depth 12471 ft MDPrevious Casing Shoe 2785 ft MDTail Cement CalculationsDescriptionTop Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excessft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl9-5/8" Shoe Track 12390 12467 77 8.681 0.0732 5.6 0% 0 5.612-1/4" Open Hole x 9-5/8" Casing 9070 12467 3397 12.250 9.625 0.0558 189.5 30% 56.8 246.3252.0Displacement CalculationsDescriptionTop Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excessft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl5-7/8" 23.4# S135 Delta576 DP -4 1395 1399 0.0241 33.7 33.75-7/8" x 4" 130ksi Delta576 HWDP 1395 2635 1240 0.0155 19.2 19.2Liner Running Tools 2635 2680 45 2.5 0.0061 0.3 0.39-5/8” 47# L-80 Hydril 563 Casing to Float/Landing Collar 2680 12390 9710 8.681 0.0732 710.8 710.8764.1Hole SizeCasing ODCasing IDPrevious Casing ID NDB-011 9-5/8" Production Liner - Stage 2Well DetailsStick Up on Rig Floor -4 ft MD 12.250 " HWDP Length 1240.2 ft MDTop of Liner 2635 ft MD 9.625 " DP Length 1398.8 ft MDCflex Depth 4720 ft MD 8.681 " HWDP Capacity 0.0155 bbl/ftLanding Collar Depth N/A ft MD 12.415 " DP Capacity 0.0241 bbl/ftFloat Collar Depth 12390 ft MDCasing Shoe Depth 12467 ft MDTD Hole Depth 12471 ft MDPrevious Casing Shoe 2785 ft MDTail Cement CalculationsDescriptionTop Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excessft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl12-1/4" Open Hole x 9-5/8" Casing 2785 4720 1935 12.250 9.625 0.0558 107.9 100% 107.9 215.913-3/8" Cased Hole x 9-5/8" Casing 2635 2785 150 12.415 9.625 0.0597 9.0 0% 0.0 9.0224.8Displacement CalculationsDescriptionTop Bottom Length OD ID Capacity Volume Excess Excess Volume Volume + Excessft MD ft MD ft MD inches inches bbl/ft bbl % bbl bbl5-7/8" 23.4# S135 Delta576 DP -4 1395 1399 0.0241 33.7 33.75-7/8" x 4" 130ksi Delta576 HWDP 1395 2635 1240 0.0155 19.2 19.25-7/8" 23.4# S135 Delta576 DP 2635 4720 2085 0.0241 50.2 50.2103.2Hole SizeCasing ODCasing IDPrevious Casing ID 1 McLellan, Bryan J (OGC) From:Williams, Rob (Rob) <Rob.Williams@santos.com> Sent:Friday, May 30, 2025 11:21 AM To:McLellan, Bryan J (OGC) Cc:Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC); Guhl, Meredith D (OGC); Atherton, Michaela (Michaela); AOGCC Permitting (CED sponsored) Subject:NDB-011 10-401 PTD Application - Request for Cement Variance Attachments:NDB-011 Cement Variance Request.pdf Hi Bryan, Please Ʊnd attached an additional variance request for the NDB-011 for your consideration in association with the NDB-011 10-401 Permit to Drill Application. The cement variance to 20 AAC 25.030. Casing and Cementing is requested due to the ERD nature of the well designs and subsequent risk of losses due to ECD’s exceeding the formation fracture gradient. If you have any questions or would like to discuss further, please don’t hesitate to reach out to me on 907 343 9737. Thank you and regards, Rob. Rob Williams Senior Drilling Engineer m: +1 907 343 9737 | e: rob.williams@santos.com Santos.com | Follow us on LinkedIn, Facebook and X Santos Ltd A.B.N. 80 007 550 923 Disclaimer: The information contained in this email is intended only for the use of the person(s) to whom it is addressed and may be confidential or contain privileged information. If you are not the intended recipient you are hereby notified that any perusal, use, distribution, copying or disclosure is strictly prohibited. If you have received this email in error please immediately advise us by return email and delete the email without making a copy. Please consider the environment before printing this email You don't often get email from rob.williams@santos.com. Learn why this is important 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. Attachment 7: Prognosed Formation Tops NDB-011 Prognosed Tops Formation MD (ft) TVD KB (ft) TVDss (ft) Pore Pressure (ppg) Upper Schrader Bluff 1058 1049 979 7.2 Base Permafrost Transition 1416 1390 1320 7.3 Middle Schrader Bluff 1805 1732 1662 7.6 MCU 2377 2153 2084 7.8 Tuluvak Shale 2963 2451 2381 7.9 Tuluvak Sand 3168 2517 2447 10.1 TS_790 4670 2844 2774 9.4 Seabee 6167 3167 3097 9.2 Nanushuk 9528 3893 3824 8.9 NT8 MFS 9737 3939 3870 8.9 NT7 MFS 9936 3985 3915 8.8 NT6 MFS 10176 4039 3969 8.8 NT5 MFS 10451 4099 4029 8.8 NT4 MFS 11003 4208 4138 8.7 NT3 MFS 12135 4348 4278 8.7 NT3.2 Top Reservoir 12542 4361 4292 8.7 Attachment 8: Well Schematic Tuluvak Sand @ 3,168' MD Top Nan 3.2 @12,542' MD Top Nanushuk @ 9,528' MD NDB-011 Well Schematic 20" Insulated Conductor128' MD 9-5/8" Liner Hanger and Liner Top Packer2,635' MD 13-3/8" 68 ppf L-80 Surface Casing2,785' MD 9-5/8", 47ppf L-80 Production Liner12,467' MD 4-½”, 12.6ppf P-110S Production Liner TD 18,637' MD 4-½” Liner Hanger/Top Packer12,317' MD GL RKB – Bottom Flange 16 Apr 2025 1 2 3 4 5 6 9-5/8" Tieback2,635' MD 9-5/8" Cflex Stage Tool (50' MD below TS790)4,720' MD 9-5/8" Primary TOC (250' TVD above Nanushuk)8,347' MD # Completion Item 1 X Landing Nipple 2 Gaslift Mandrel 1.5" 3X Landing Nipple 4 SSD NERA Gaslift 5EGL Valve 6D/H Psi-Temp Gauge 7 Tieback Seal Assy 8 9.625" x 4.5" LH/Packer 9 #11 Openhole Packer 10 #10 Openhole Packer 11 Stg 10 - Collet Sleeve 9 12 #9 Openhole Packer 13 Stg 9 - Collet Sleeve 8 14 #8 Openhole Packer 15 Stg 8 - Collet Sleeve 7 16 #7 Openhole Packer 17 Stg 7 - Collet Sleeve 6 18 #6 Openhole Packer 19 Stg 6 - Collet Sleeve 5 20 #5 Openhole Packer 21 Stg 5 - Collet Sleeve 4 22 #4 Openhole Packer 23 Stg 4 - Collet Sleeve 3 24 #3 Openhole Packer 25 Stg 3 - Collet Sleeve 2 26 #2 Openhole Packer 27 Stg 2 - Collet Sleeve 1 28 #1 Openhole Packer 29 Stg 1 - #2 Toe Sleeve 30 Stg 1 - #1 Toe Sleeve 31 WIV Collar 32 Float Collar 34 Eccentric shoe Attachment 9: Formation Evaluation Program 16” Surface Hole LWD Gamma Ray Resistivity 12-1/4” Intermediate Hole #1 LWD Gamma Ray Resistivity Density Neutron 8-1/2” Intermediate Hole #2 LWD Gamma Ray Resistivity Density Neutron Sonic (7” Liner Cement Evaluation Only) Mudlogging No mudlogging is planned for NDB-011 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) is not planned will on NDB-011 in either the Intermediate or Production hole sections for the base case drilling plan. The MPD system however will remain in place as it is integrated into the Parker 272 rig. The MPD system may be used on NDB-011 if unexpected or adverse hole conditions are observed and/or if operationally more efficient (for example use of the MPD bearing to strip out of hole). 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. At no point will the static wellbore fluid be underbalanced. See below for a schematic of the BOP/MPD stack with the choke flow diagram. Attachment 14: As Built Survey NDB Well 11 Conductor Final NDB-CISUV-000023 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 NANUSHUK OIL 225-048 Pikka NDB-011 WELL PERMIT CHECKLISTCompanyOil Search (Alaska), LLCWell Name:PIKKA NDB-011Initial Class/TypeDEV / PENDGeoArea890Unit11580On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250480Field & Pool:PIKKA, NANUSHUK OIL - 600100NA1Permit fee attachedYesADL392985, ADL393023, ADL393022 , ADL393021, and ADL3929842Lease number appropriateYes3Unique well name and numberYesPIKKA, NANUSHUK OIL - 600100 - governed by CO 8074Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18Conductor string providedYes19Surface casing protects all known USDWsYes20CMT vol adequate to circulate on conductor & surf csgYesVariances approved. Tuluvak will be cemented in 2nd stage. 1st stage TOC 100' TVD above Nanushuk21CMT vol adequate to tie-in long string to surf csgNoProduction liner is uncemented, with multiple frac sleeves and OH packers22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYes24Adequate tankage or reserve pitNA25If a re-drill, has a 10-403 for abandonment been approvedYes26Adequate wellbore separation proposedNoDiverter waiver approved.27If diverter required, does it meet regulationsYes28Drilling fluid program schematic & equip list adequateYes29BOPEs, do they meet regulationYesMPSP = 1521 psi, BOP rated to 5000 psi. BOP test to 3600. Variance approved for 21-day test frequency30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNo33Is presence of H2S gas probableNAProducer34Mechanical condition of wells within AOR verified (For service well only)YesH2S measures not required: None anticipated based on nearby wells.35Permit can be issued w/o hydrogen sulfide measuresYesTuluvak (with shallow gas) pressures anticipated to be 10.1 ppg EMW. Nanushuk reservoir at 8.9 ppg EMW36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate05-Jun-25ApprBJMDate02-Jun-25ApprADDDate03-Jun-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 6/6/2025
