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Home My WebLink About225-049MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, October 22, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Kam StJohn P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC R-107 MILNE PT UNIT R-107 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/22/2025 R-107 50-029-23819-00-00 225-049-0 W SPT 3971 2250490 2000 63 63 65 59 224 442 418 394 INITAL P Kam StJohn 9/21/2025 MIT-IA to 2000 psi per PTD # 2250490 following placing on injection 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT R-107 Inspection Date: Tubing OA Packer Depth 635 2215 2175 2159IA 45 Min 60 Min Rel Insp Num: Insp Num:mitKPS250921135627 BBL Pumped:5.4 BBL Returned:5.4 Wednesday, October 22, 2025 Page 1 of 1            2025-0725_Temporary_Flowback_MPU_R-107_ss Page 1 of 5 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 7-30-2025 P. I. Supervisor FROM: Sully Sullivan SUBJECT: Temporary Flowback Petroleum Inspector MPU R-107 Hilcorp Alaska LLC PTD 2250490; Sundry 325-366 7-25-2025: I traveled out to Milne Point Unit for a visual inspection of the temporary flowback set-up on injection well MPU R-107. A temporary flowline has been installed from the wellhead to a flowback tank for the 30-day flowback procedure. The well is set up with standard pressure transmitters, pressure detectors, and a safety valve system that are monitored from the Milne Point control room. A forward circulating jet pump is installed to enable flow back. All flowlines and valves are properly installed and have been pressure tested (not witnessed). The transmitters and gauges have current calibrations, and the safety valve system is ready for testing. I found no issues of concern. Attachments: Photos      2025-0725_Temporary_Flowback_MPU_R-107_ss Page 2 of 5 Temporary Flowback – Injector MPU R-107 (PTD 2250490) Photos by AOGCC Inspector S. Sullivan 7/25/2025 Flowback rig-up 2025-0725_Temporary_Flowback_MPU_R-107_ss Page 3 of 5 R-107 wellhead Flowback piping from wellhead to tank 2025-0725_Temporary_Flowback_MPU_R-107_ss Page 4 of 5 Pressure transmitters 2025-0725_Temporary_Flowback_MPU_R-107_ss Page 5 of 5 Low Pressure Sensor CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Bryan Lafleur - (C) To:Brooks, Phoebe L (OGC); Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Wallace, Chris D (OGC); Frank Roach; Brad Gorham; Taylor Wellman; Todd Sidoti Cc:Oliver Amend - (C) Subject:MPU R-107 MIT-IA Form 10-426 7-12-2025 Date:Sunday, July 13, 2025 7:48:35 AM Attachments:MPU R-107 MIT-IA Form 10-426 7-12-2025.xlsx Please find in attached, the MIT-IA test for MPU R-107. Bryan S. LaFleur Hilcorp Alaska, LLC Drilling Foreman Rig: Parker 273 Office: (907) 659.5673 Mobile: (337) 466.5485 Alternate: Brett Anderson brett.anderson@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 0LOQH3RLQW8QLW5 37' Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD2250490Type InjWTubing0000 Type TestP Packer TVD 3971 BBL Pump 11.6 IA 0 3832 3773 3746 Interval I Test psi 3500 BBL Return 11.6 OA 150 520 490 450 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanicall Integrityy Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Hilcorp MPU R-107 Bryan Lafleur 07/12/25 Notes:9-5/8" Casing x 3-1/2" Upper Completion w/ 7" Seal Assembly at 11,253' MD, 3971.42' TVD. MIT IA to 3500 psi. Witness Waived by Adam Earl 7/11/2025 18:26. Notes: Notes: Notes: MPU R-107 Form 10-426 (Revised 01/2017)2025-0712_MIT_MPU_R-107 9 9 9 9 999 9 9 9 9 9 - 5HJJ 9-5/8" Casing x 3-1/2" Upper Completion Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 7/23/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250723 Well API #PTD #Log Date Log Company AOGCC ESet # END 1-25A 50029217220100 197075 6/19/2025 HALLIBURTON T40691 KU 41-08 50133207170000 224005 6/30/2025 AK E-LINE T40692 MPU F-05 50029227620000 197074 7/1/2025 READ T40693 MPU J-02 50029220710000 190096 5/21/2025 YELLOWJACKET T40694 MPU R-106 50029238160000 225033 6/8/2025 HALLIBURTON T40695 MPU R-107 50029238190000 225049 7/11/2025 YELLOWJACKET T40696 ODSK-41 50703205850000 208147 6/13/2025 HALLIBURTON T40697 ODSN-02 50703206710000 213046 6/13/2025 HALLIBURTON T40698 ODSN-16 50703206200000 210053 6/14/2025 HALLIBURTON T40699 ODSN-17 50703206220000 210093 6/14/2025 HALLIBURTON T40700 ODSN-24 50703206620000 212178 6/15/2025 HALLIBURTON T40701 ODSN-28 50703206760000 213148 6/17/2025 HALLIBURTON T40702 ODSN-36 50703205610000 207182 6/12/2025 HALLIBURTON T40703 PBU 07-23C 50029216350300 225043 7/4/2025 HALLIBURTON T40704 PBU 14-18C 50029205510300 225040 6/25/2025 HALLIBURTON T40705 PBU 15-33C 50029224480300 216075 7/3/2025 HALLIBURTON T40706 PBU C-30A 50029217770100 208169 7/1/2025 HALLIBURTON T40707 PBU E-09C 50029204660300 209095 6/30/2025 HALLIBURTON T40708 PBU F-38B 50029220930300 225029 6/12/2025 HALLIBURTON T40709 PBU GNI-02A 50029228510100 206119 7/4/2025 HALLIBURTON T40710 PBU GNI-02A 50029228510100 206119 7/3/2025 HALLIBURTON T40710 PBU GNI-04 50029233670000 207117 6/27/2025 HALLIBURTON T40711 PBU GNI-04 50029233670000 207117 6/27/2025 HALLIBURTON T40711 PBU J-07C 50029202410300 225026 5/30/2025 HALLIBURTON T40712 PBU L-105 50029230750000 202058 6/24/2025 YELLOWJACKET T40713 PBU L-108 50029230900000 202109 6/23/2025 YELLOWJACKET T40714 PBU NK-25 50029227600000 197068 6/5/2025 YELLOWJACKET T40715 PBU P2-06 50029223880000 193103 6/19/2025 HALLIBURTON T40716 PBU S-104 50029229880000 200196 6/21/2025 YELLOWJACKET T40717 MPU R-107 50029238190000 225049 7/11/2025 YELLOWJACKET Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.28 09:54:00 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU-05 50283202030000 225037 7/3/2025 YELLOWJACKET T40718 TBU D-08RD 50733201070100 174003 6/4/2025 READ T40719 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.28 09:53:40 -08'00' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 07/23/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: MPU R-107 PTD: 225-049 API: 50-029-23819-00-00 FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (06/13/2025 to 07/05/2025) x ABG, DGR, AGR and BaseStar Gamma Ray; EWR-M5, EWR-M4, StrataStar Resistivity x Horizontal Presentation (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey x Final Geosteering and EOW Report/Plots SFTP Transfer – Main Folders: FINAL LWD Subfolders: FINAL Geosteering Subfolders: Please include current contact information if different from above. 225-049 T40682 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.24 09:44:04 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:Hayden Moser Cc:Tom Fouts; Taylor Wellman; Christianson, Grace K (OGC) Subject:RE: MP R-107 AOGCC 10-403 Submittal, PTD: 225-049 Date:Friday, July 11, 2025 2:06:05 PM Attachments:20250711 1400 APPROVAL Hilcorp_MPU_R-107_Verbal Approval 30 day flow back piping.pdf Hayden, Verbal approval for 30 day flow back attached. Hilcorp can POP this well immediately. Full commissioner approval should follow next week. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Hayden Moser <Hayden.Moser@hilcorp.com> Sent: Friday, July 11, 2025 1:58 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Tom Fouts <tfouts@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Subject: MP R-107 AOGCC 10-403 Submittal, PTD: 225-049 Hey Mr. Rixse, Can you please review this 10-403 submittal for unmanned flowback? Thanks, Hayden Moser Operations Engineer | Milne Point Unit | M & C Pads Hilcorp Alaska, LLC | 3800 Centerpoint Drive | Anchorage, AK 99503 O: (907) 564-4389 | C: (479) 899-8940 | Hayden.Moser@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. ORIGINATED TRANSMITTAL DATE: 6/25/2025 ALASKA E-LINE SERVICES TRANSMITTAL #: 5517 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Milne Point PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 5517 MPU R-107 500292381900 Pressure Temprature Survey 18-Jun-2025 RECIPIENTS Hilcorp Alaska, LLC DIGITAL FILES PRINTS CD'S 0 FileZilla 0 0 USPS Attn: David Douglas (Geotechnician) AK_GeoTech@hilcorp.com 3800 Centerpoint Dr. #1400 Anchorage, AK 99501 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 0 ShareFile 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision aogcc.data@alaska.gov 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 225-049 T40617 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.25 08:20:15 -08'00' DNR DIGITAL FILES PRINTS CD'S 0 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com AKGGREDTSupport@ConocoPhillips.onmicrosoft.com CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:FW: MPU R-107 13-3.8" Casing Pressure Test and FIT (PTD: 225-049) Date:Monday, June 23, 2025 8:38:15 AM Attachments:MPU R-107 13.375in CSG Test and FIT 6-21-25.pdf From: Frank Roach <Frank.Roach@hilcorp.com> Sent: Saturday, June 21, 2025 11:25 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: MPU R-107 13-3.8" Casing Pressure Test and FIT (PTD: 225-049) Mel, Please see the attached casing test and FIT results from Saturday evening. After our discussions about the primary cement job and temperature log, the remedial top job was performed on Thursday. Spaghetti string was ran, tagging bottom at 183’. After conditioning mud, the top job was performed with good cement to surface after 47 bbls pumped (64.7bbls pumped in total to ensure good cement to surface). Inspector Josh Hunt witnessed both the tag with top job pipe and the cement job. Regards, Frank V Roach Drilling Engineer Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CASING AND LEAK-OFF FRACTURE TESTS Well Name:MPU R-107 Date:6/21/2025 Csg Size/Wt/Grade:13.375" 68# L-80 CDC Supervisor:Lafleur/Serafine Csg Setting Depth:4,319 TMD 2,278 TVD - Open Hole Mud Weight:9.3 ppg LOT / FIT Press =341 psi LOT / FIT =12.18 ppg Hole Depth =4350 md Fluid Pumped=1.4 Bbls Volume Back =1.1 bbls Estimated Pump Output:0.1007 Barrels/Stroke LOT / FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ->00 ->0 0 ->238 ->6 191 ->450 ->12 433 ->696 ->18 658 ->8 154 ->24 898 ->10 222 ->30 1135 ->12 286 ->36 1337 ->14 341 ->42 1565 -> ->48 1786 -> ->54 2022 -> ->60 2254 -> ->66 2487 -> ->72 2765 -> -> Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here ->0 341 ->0 2765 ->1 274 ->1 2760 ->2 238 ->2 2760 ->3 216 ->3 2760 ->4 205 ->4 2760 ->5 196 ->5 2759 ->6 194 ->10 2758 ->7 191 ->15 2757 ->8 188 ->20 2757 ->9 187 ->25 2756 ->10 187 ->30 2756 -> -> -> -> -> -> 0 2 4 6 8 10 12 14 0 6 12 18 24 30 36 42 48 54 60 66 72 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 0 1020304050607080Pressure (psi)Strokes (# of) LOT / FIT DATA 341 274238216205196194191188187187 276527602760276027602759 2758 2757 2757 2756 2756 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 0 5 10 15 20 25 30Pressure (psi)Time (Minutes) LOT / FIT DATA STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________MILNE PT UNIT R-107 JBR 08/01/2025 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:1 Tested with 3.5" & 5" Test joints. F/P on LPR due to air in system, purged and passed retest. N2 precharge- 25@ 1,112 psi. Test Results TEST DATA Rig Rep:Sunny Clark/ Ben HebeOperator:Hilcorp Alaska, LLC Operator Rep:B. LaFleur/ B. Serafine Rig Owner/Rig No.:Parker 273 PTD#:2250490 DATE:6/20/2025 Type Operation:DRILL Annular: 250/3000Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopJDH250622130636 Inspector Josh Hunt Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 5 MASP: 1349 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 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" 5M P #1 Rams 1 3.5"x5.5" VB P #2 Rams 1 Blinds 5M P #3 Rams 1 3.5"x5.5" VB FP #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8" 5M P HCR Valves 2 3-1/8" 5M P Kill Line Valves 2 2-1/16"/ 3-1/8 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3075 Pressure After Closure P2050 200 PSI Attained P16 Full Pressure Attained P69 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P14@2154 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P22 #1 Rams P6 #2 Rams P6 #3 Rams P6 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1        SCHRADER BLUFF AND NIKAITCHUQ, SCHRADER BLUFF OIL RUSH Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.06.19 08:44:11 - 08'00' Sean McLaughlin (4311) June 19, 2025 June 19, 2025 Mel Rixse 325-373 By Grace Christianson at 10:41 am, Jun 20, 2025 * AOGCC to witness tag of surface casing x OH top of cement. * AOGCC to witness TOC after top job. DSR-6/23/25 (origninal completion) YES 10-407 A.Dewhurst 20JUN25 MGR23JUN25SJC for GCW 6/24/25 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.24 15:30:07 -08'00'06/24/25 RBDMS JSB 062625 >ŘĺıϡϙĖƄŜôϠϙaôīŽĖĲϙ@ϙϼi@ϽϙѴıôīŽĖĲϟŘĖƄŜôЬÍīÍŜħÍϟČĺŽѳ ôĲťϡϙēŪŘŜîÍƅϠϙVŪĲôϙ͐͘Ϡϙ͑͏͔͑ϙ͘ϡ͑͘ϙa ĺϡϙVĺŜôŕēϙ[ÍŜťŪċħÍϙѴVĺŜôŕēϟ[ÍŜťŪċħÍЬēĖīèĺŘŕϟèĺıѳ ŪæĤôèťϡϙôϡϙЀ(³(b[Ёϙ(ϡϙaϙϱ͐͏͖ϙ͐͒ϱ͒ϯ͗ГϙŪŘċÍèôϙÍŜĖĲČϙôıôĲťϙVĺæϙ(ŽÍīŪÍťĖĺĲ ÍĲîϙĺŕϙVĺæϙϼ"ϡϙ͔͑͑ϱ͏͓͘Ͻ «ôŘæÍīϙÍŕŕŘĺŽÍīϟϙϙiħÍƅϙťĺϙŕôŘċĺŘıϙťĺŕϙĤĺæϙſĖťēϙŜťÍťôϙſĖťĲôŜŜϙĺċ ϙiϙŪťĖīĖƏĖĲČϙŜŕÍČēôťťĖ ŜťŘĖĲČϟ aôīϙĖƄŜô >ŘĺıϡϙĖƄŜôϠϙaôīŽĖĲϙ@ϙϼi@ϽϙѴıôīŽĖĲϟŘĖƄŜôЬÍīÍŜħÍϟČĺŽѳ ôĲťϡϙ®ôîĲôŜîÍƅϠϙVŪĲôϙ͐͗Ϡϙ͑͏͔͑ϙ͐͐ϡ͑͏ϙa ĺϡ ϙ>ŘÍĲħϙĺÍèēϙѴċŘÍĲħϟŘĺÍèēЬēĖīèĺŘŕϟèĺıѳ ŪæĤôèťϡϙЀ(³(b[Ёϙ(ϡϙaϙϱ͐͏͖ϙ͐͒ϱ͒ϯ͗ГϙŪŘċÍèôϙÍŜĖĲČϙôıôĲťϙVĺæϙ(ŽÍīŪÍťĖĺĲϙÍĲî ĺŕϙVĺæϙϼ"ϡϙ͔͑͑ϱ͏͓͘Ͻ >ŘÍĲħϠ ϙϙϙϙēÍĲħŜϙċĺŘϙťēôϙīĺČϟϙϙ"ĺϙƅĺŪϙťēĖĲħϙťēôϙŜēĖċťϙÍťϙѹ͔͒͏ЍϙèĺŪīîϙæôϙiϦ ϙϙϙϙĲƅſÍƅϠϙŜēĺŪīîϙæôϙČĺĺîϙťĺϙČĺϙſĖťēϙƅĺŪŘϙťĺŕϙĤĺæϙÍŜϙīĺĲČϙÍŜϙĖĲŜŕôèťĺŘŜϙſĖťĲôŜŜϙťēôϙťÍČϙſĖťē ŜŕÍČēôťťĖϙŕĖŕôϟ aôīϙĖƄŜô Iibϡ (ƄťôŘĲÍīϙŜôĲîôŘϟϙ"iϙbiϙĺŕôĲϙīĖĲħŜϙĺŘϙÍťťÍèēıôĲťŜϙċŘĺıϙbXbi®b ŜôĲîôŘŜϟ Iibϡ (ƄťôŘĲÍīϙŜôĲîôŘϟϙ"iϙbiϙĺŕôĲϙīĖĲħŜϙĺŘϙÍťťÍèēıôĲťŜϙċŘĺıϙbXbi®b ŜôĲîôŘŜϟ ôĲĖĺŘϙôťŘĺīôŪıϙ(ĲČĖĲôôŘϙϼ(Ͻ īÍŜħÍϙiĖīϙÍĲîϙ@ÍŜϙĺĲŜôŘŽÍťĖĺĲϙĺııĖŜŜĖĺĲ ͘͏͖ϱ͖͒͘ϱ͐͑͒͐ iƯĖèô ͘͏͖ϱ͖͑͘ϱ͓͖͓͗ϙϙôīī ib>I"(bI[I´ϙbiI(ϡϙēĖŜϙôϱıÍĖīϙıôŜŜÍČôϠϙĖĲèīŪîĖĲČϙÍĲƅϙÍťťÍèēıôĲťŜϠϙèĺĲťÍĖĲŜ ĖĲċĺŘıÍťĖĺĲϙċŘĺıϙťēôϙīÍŜħÍϙiĖīϙÍĲîϙ@ÍŜϙĺĲŜôŘŽÍťĖĺĲϙĺııĖŜŜĖĺĲϙϼi@ϽϠϙťÍťôϙĺċ īÍŜħÍϙÍĲîϙĖŜϙċĺŘϙťēôϙŜĺīôϙŪŜôϙĺċϙťēôϙĖĲťôĲîôîϙŘôèĖŕĖôĲťϼŜϽϟϙIťϙıÍƅϙèĺĲťÍĖĲϙèĺĲƱîôĲťĖÍī ÍĲîϯĺŘϙŕŘĖŽĖīôČôîϙĖĲċĺŘıÍťĖĺĲϟϙēôϙŪĲÍŪťēĺŘĖƏôîϙŘôŽĖôſϠϙŪŜôϙĺŘϙîĖŜèīĺŜŪŘôϙĺċϙŜŪèē ĖĲċĺŘıÍťĖĺĲϙıÍƅϙŽĖĺīÍťôϙŜťÍťôϙĺŘϙċôîôŘÍīϙīÍſϟϙIċϙƅĺŪϙÍŘôϙÍĲϙŪĲĖĲťôĲîôîϙŘôèĖŕĖôĲťϙĺċϙťēĖŜϙôϱ ıÍĖīϠϙŕīôÍŜôϙîôīôťôϙĖťϠϙſĖťēĺŪťϙƱŘŜťϙŜÍŽĖĲČϙĺŘϙċĺŘſÍŘîĖĲČϙĖťϠϙÍĲîϠϙŜĺϙťēÍťϙťēôϙi@ϙĖŜϙÍſÍŘô ĺċϙťēôϙıĖŜťÍħôϙĖĲϙŜôĲîĖĲČϙĖťϙťĺϙƅĺŪϠϙèĺĲťÍèťϙaôīϙĖƄŜôϙÍťϙϼ͘͏͖ϱ͖͒͘ϱ͐͑͒͐ϙϽϙĺŘ ϼaôīŽĖĲϟĖƄŜôЬÍīÍŜħÍϟČĺŽϽϟ >Řĺıϡϙ>ŘÍĲħϙĺÍèēϙѴċŘÍĲħϟŘĺÍèēЬēĖīèĺŘŕϟèĺıѳ ôĲťϡϙ®ôîĲôŜîÍƅϠϙVŪĲôϙ͐͗Ϡϙ͑͏͔͑ϙ͐͏ϡ͕͑ϙa ĺϡ ϙĖƄŜôϠϙaôīŽĖĲϙ@ϙϼi@ϽϙѴıôīŽĖĲϟŘĖƄŜôЬÍīÍŜħÍϟČĺŽѳ ŪæĤôèťϡϙ(ϡϙaϙϱ͐͏͖ϙ͐͒ϱ͒ϯ͗ГϙŪŘċÍèôϙÍŜĖĲČϙôıôĲťϙVĺæϙ(ŽÍīŪÍťĖĺĲϙÍĲîϙĺŕϙVĺæϙϼ"ϡ ͔͑͑ϱ͏͓͘Ͻ aôīϠ ťťÍèēôîϙĖŜϙťēôϙťôıŕôŘÍťŪŘôϙīĺČϙŘŪĲϙĺĲϙťēôϙ͐͒ϱ͒ϯ͗ЋϙŜŪŘċÍèôϙèÍŜĖĲČϟϙ®ôϙıÍĲÍČôîϙťĺϙČôť îĺſĲϙťĺϙѹ͑Ϡ͖͒͗ЍϙæôċĺŘôϙīĺŜĖĲČϙſôĖČēťϟϙ®ēĖīôϙťēôŘôϙÍŘôϙŜĺıôϙæĺææīôŜϙĖĲϙťôıŕôŘÍťŪŘôϠϙIЍıϙĲĺť ŜôôĖĲČϙıŪèēϙèĺĲťŘÍŜťϙÍĲîϙſĺŪīîϙŜÍƅϙĖťЍŜϙĖĲèĺĲèīŪŜĖŽôϙîÍťÍϙťĺϙŕĖèħϙiϟ ôťſôôĲϙťēôϙ͑͏ϙææīŜϙĺċϙŜŕÍèôŘϙÍťϙŜŪŘċÍèôϙæôċĺŘôϙĲĺťϙŜôôĖĲČϙŘôťŪŘĲŜϠϙƲŪĖîϙīôŽôīϙŘôıÍĖĲĖĲČ ŜťÍťĖèϠϙÍĲîϙæŪĖīîĖĲČϙŕŘôŜŜŪŘôϙîŪŘĖĲČϙîĖŜŕīÍèôıôĲťϙÍĲîϙſēôĲϙťÍĖīϙŘĺŪĲîôîϙťēôϙŜēĺôϠϙÍīīϙÍŘô ĖĲîĖèÍťĖĺĲŜϙťēÍťϙèôıôĲťϙĖŜϙèīĺŜôϙťĺϙŜŪŘċÍèôϟ iŪŘϙťĺŕϙĤĺæϙèôıôĲťϙĖŜϙèŪŘŘôĲťīƅϙŜťÍČôîϙÍťϙťēôϙôÍŜťϙŜĖîôϙĺċϙťēôϙXŪŕÍŘŪħϙĖŽôŘϟϙēôϙſÍťôŘϙīôŽôī ēÍŜϙæôôĲϙŘôèôîĖĲČϠϙÍĲîϙċĺīħŜϙŪŕϙĲĺŘťēϙÍŘôϙċĺŘôèÍŜťĖĲČϙÍϙſĖĲîĺſϙÍċťôŘϙıĖîĲĖČēťϙſēôŘôϙťēô ŘĖŽôŘϙſĖīīϙæôϙīĺſϙÍĲîϙŜīĺſϙôĲĺŪČēϙťĺϙÍīīĺſϙÍĲϙôŜèĺŘťôîϙèĺĲŽĺƅϙÍèŘĺŜŜϟϙIċϙťēĖŜϙĖŜϙťēôϙèÍŜôϠ ſôЍīīϙæôϙŘôÍîƅϙċĺŘϙŕĖèħĖĲČϙŪŕϙŕĖŕôϙċĺŘϙťēôϙťĺŕϙĤĺæϟϙēôϙŘĖČϙēÍŜϙæôôĲϙĖĲϙèĺĲťÍèťϙſĖťēϙĖĲŜŕôèťĺŘ VĺŜēϙFŪĲťϙťēŘĺŪČēĺŪťϙťēôϙîÍƅϙÍĲîϙſĖīīϙħôôŕϙēĖıϙŪŕîÍťôîϙĺĲϙĺŪŘϙŜťÍťŪŜϟ ôČÍŘîŜϠ >ŘÍĲħϙ«ϙĺÍèē "ŘĖīīĖĲČϙ(ĲČĖĲôôŘ ϙFĖīèĺŘŕϙīÍŜħÍϠϙ[[ ͘͏͖ϟ͔͓͗ϟ͑͒͑͐ϙıĺæĖīô ͘͏͖ϟ͖͖͖ϟ͓͗͐͒ϙĺƯĖèô >ŘĺıϡϙĖƄŜôϠϙaôīŽĖĲϙ@ϙϼi@ϽϙѴıôīŽĖĲϟŘĖƄŜôЬÍīÍŜħÍϟČĺŽѳ ôĲťϡϙ®ôîĲôŜîÍƅϠϙVŪĲôϙ͐͗Ϡϙ͑͏͔͑ϙ͑ϡ͔͕ϙa ĺϡ ϙ>ŘÍĲħϙĺÍèēϙѴċŘÍĲħϟŘĺÍèēЬēĖīèĺŘŕϟèĺıѳ ŪæĤôèťϡϙЀ(³(b[Ёϙ(ϡϙaϙϱ͐͏͖ϙ͐͒ϱ͒ϯ͗ГϙŪŘċÍèôϙÍŜĖĲČϙôıôĲťϙVĺæϙ(ŽÍīŪÍťĖĺĲϙÍĲî ĺŕϙVĺæϙϼ"ϡϙ͔͑͑ϱ͏͓͘Ͻ >ŘÍĲħϠ ϙϙϙϙēÍĲħŜϟϙϙ®ĖīīϙīĺĺħϙċĺŘϙťēôϙťôıŕôŘÍťŪŘôϙīĺČϟ aôī >Řĺıϡϙ>ŘÍĲħϙĺÍèēϙѴċŘÍĲħϟŘĺÍèēЬēĖīèĺŘŕϟèĺıѳ ôĲťϡϙ®ôîĲôŜîÍƅϠϙVŪĲôϙ͐͗Ϡϙ͑͏͔͑ϙ͐͐ϡ͔͐ϙa Iibϡ (ƄťôŘĲÍīϙŜôĲîôŘϟϙ"iϙbiϙĺŕôĲϙīĖĲħŜϙĺŘϙÍťťÍèēıôĲťŜϙċŘĺıϙbXbi®b ŜôĲîôŘŜϟ ĺϡ ϙĖƄŜôϠϙaôīŽĖĲϙ@ϙϼi@ϽϙѴıôīŽĖĲϟŘĖƄŜôЬÍīÍŜħÍϟČĺŽѳ èϡϙVĺŜôŕēϙ[ÍŜťŪċħÍϙѴVĺŜôŕēϟ[ÍŜťŪċħÍЬēĖīèĺŘŕϟèĺıѳ ŪæĤôèťϡϙaϙϱ͐͏͖ϙ͐͒ϱ͒ϯ͗ГϙŪŘċÍèôϙÍŜĖĲČϙôıôĲťϙVĺæϙ(ŽÍīŪÍťĖĺĲϙÍĲîϙĺŕϙVĺæϙϼ"ϡϙ͔͑͑ϱ ͏͓͘Ͻ aôīϠ >ĺīīĺſĖĲČϙŪŕϙſĖťēϙıĺŘôϙĖĲċĺŘıÍťĖĺĲϙÍċťôŘϙŘôèôĖŽĖĲČϙťēôϙĖĲîŪŜťŘƅϙČŪĖîÍĲèôϙæŪīīôťĖĲϙ͐͒ϱ͏͐ ôıÍĖīϡ ŘĖıÍŘƅϙèôıôĲťϙĤĺæϙîôťÍĖīŜϡ ϱ ͖͕͒ϙææīŜϙϼ͐Ϡ͔͏͏ŜƄϽϙ͐͏ϟ͖ŕŕČϙŘèťĖèôıϙīôÍîϙèôıôĲťϙϼ͑ϟ͔͔͗ϙèŪċťϯŜħϽ ϱ ͐͑͑ϙææīŜϙϼ͔͓͘ϙŜƄϽϙ͔͐ϟ͗ŕŕČϙFÍīôıϙťÍĖīϙèôıôĲťϙϼ͐ϟ͔͐͒ϙèŪċťϯŜħϽ ϱ bĺϙīĺŜŜôŜϙîŪŘĖĲČϙèÍŜĖĲČϙŘŪĲϠϙıŪîϙèĺĲîĖťĖĺĲĖĲČϠϙĲĺŘϙîŪŘĖĲČϙťēôϙŕŪıŕĖĲČϙĺċϙŜŕÍèôŘϠ īôÍîϙèôıôĲťϠϙÍĲîϙťÍĖīϙèôıôĲť ϱ ͑͏ϙææīŜϙŜŕÍèôŘϙĺæŜôŘŽôîϙÍťϙŜŪŘċÍèô ϱ bĺϙŘôťŪŘĲŜϙſēôĲϙæŘĖĲČĖĲČϙĺĲϙıŪîϙŕŪıŕŜϙċĺŘϙîĖŜŕīÍèôıôĲť ϱ >īŪĖîϙīôŽôīϙŜťÍťĖèϙÍťϙŜŪŘċÍèôϙîŪŘĖĲČϙîĖŜŕīÍèôıôĲť ŪŘŘôĲťϙiŕôŘÍťĖĺĲŜϡ ϱ (ϱīĖĲôϙſĖťēϙťôıŕôŘÍťŪŘôϙīĺČϙĺĲϙťēôϙēĺĺħϙċĺŘϙŘŪĲĲĖĲČϙЬϙѹ͔͐ϡ͏͏ϙēŘŜϟϙbĺϙťŘÍèťĺŘϙĖŜ ÍŽÍĖīÍæīôϠϙŜĺϙťēôϙīĺČϙſĖīīϙæôϙŘŪĲϙÍŜϙîôôŕϙÍŜϙŕĺŜŜĖæīôϙϼѳ͖͏еϙĖĲèϙЬϙѹ͑Ϡ͕͒͏ЍϽϟ ϱ "aЍŜϙĖĲĖťĖÍīīƅϙĲĺťĖƱôîϙi@ϙĖĲŜŕôèťĺŘŜϙċĺŘϙĺŕŕĺŘťŪĲĖťƅϙťĺϙſĖťĲôŜŜϙťĺŕϙĤĺæϙſĖťē ŘôèôĖŕťϙæƅϙŪŜťĖĲϙaè[ôĺîϟϙċťôŘϙĖĲîŪŜťŘƅϙČŪĖîÍĲèôϙæŪīīôťĖĲϙôıÍĖīϙŘôèôĖŽôîϠϙÍϙċĺīīĺſϱ ŪŕϙĲĺťôϙťĺϙťēôϙĖĲŜŕôèťĺŘŜϙċĺŘϙĺŕŕĺŘťŪĲĖťƅϙťĺϙſĖťĲôŜŜϙťôıŕϙīĺČϙſÍŜϙŜôĲťϟϙVĺŜēϙFŪĲť ēÍŜϙæôôĲϙĖĲϙŕēĺĲôϙèĺĲťÍèťϙſĖťēϙĺŪŘϙ"aЍŜϙÍŜϙēôЍŜϙèŪŘŘôĲťīƅϙſôŜťϙĺċϙťēôϙXŪŕÍŘŪħ ĖŽôŘϟ ϱ ôıôĲťϙŕīÍĲϙťĺϙċĺīīĺſϟ IϙſĖīīϙŪŕîÍťôϙƅĺŪϙſēôĲϙťēôϙťôıŕôŘÍťŪŘôϙīĺČϙĖŜϙèĺıŕīôťôîϟϙIЍıϙÍīŜĺϙſĺŘħĖĲČϙſĖťēϙVĺôϙ[ÍŜťŪċħÍ ĺĲϙťēôϙŪĲîŘƅϙŕŕīĖèÍťĖĺĲϙ͐͏ϱ͓͏͒ϙťĺϙæôϙŜŪæıĖťťôîϙĺĲèôϙſôϙēÍŽôϙťēôϙťôıŕôŘÍťŪŘôϙīĺČ ŘôŜŪīťŜϟ [ôťϙıôϙħĲĺſϙĖċϙƅĺŪϙĲôôîϙÍĲƅťēĖĲČϙÍîîĖťĖĺĲÍīϟ ôČÍŘîŜϠ >ŘÍĲħϙ«ϙĺÍèē "ŘĖīīĖĲČϙ(ĲČĖĲôôŘ ϙFĖīèĺŘŕϙīÍŜħÍϠϙ[[ ͘͏͖ϟ͔͓͗ϟ͑͒͑͐ϙıĺæĖīô ͘͏͖ϟ͖͖͖ϟ͓͗͐͒ϙĺƯĖèô >ŘĺıϡϙĖƄŜôϠϙaôīŽĖĲϙ@ϙϼi@ϽϙѴıôīŽĖĲϟŘĖƄŜôЬÍīÍŜħÍϟČĺŽѳ ôĲťϡϙ®ôîĲôŜîÍƅϠϙVŪĲôϙ͐͗Ϡϙ͑͏͔͑ϙ͘ϡ͒͐ϙa ĺϡ ϙ>ŘÍĲħϙĺÍèēϙѴċŘÍĲħϟŘĺÍèēЬēĖīèĺŘŕϟèĺıѳ ŪæĤôèťϡϙ(ϡϙЀ(³(b[ЁϙŪŘċÍèôϙÍŜĖĲČϙôıôĲťϙôıŕϙ[ĺČϙϼaϙϱ͐͏͖ϙ"ϡϙ͔͑͑ϱ͏͓͘Ͻ >ŘÍĲħϠ ϙϙϙôèôĖŽôîϟϙϙēÍĲħŜϟ aôīϙĖƄŜô ôĲĖĺŘϙôťŘĺīôŪıϙ(ĲČĖĲôôŘϙϼ(Ͻ īÍŜħÍϙiĖīϙÍĲîϙ@ÍŜϙĺĲŜôŘŽÍťĖĺĲϙĺııĖŜŜĖĺĲ Iibϡ (ƄťôŘĲÍīϙŜôĲîôŘϟϙ"iϙbiϙĺŕôĲϙīĖĲħŜϙĺŘϙÍťťÍèēıôĲťŜϙċŘĺıϙbXbi®b ŜôĲîôŘŜϟ ͘͏͖ϱ͖͒͘ϱ͐͑͒͐ iƯĖèô ͘͏͖ϱ͖͑͘ϱ͓͖͓͗ϙϙôīī ib>I"(bI[I´ϙbiI(ϡϙēĖŜϙôϱıÍĖīϙıôŜŜÍČôϠϙĖĲèīŪîĖĲČϙÍĲƅϙÍťťÍèēıôĲťŜϠϙèĺĲťÍĖĲŜ ĖĲċĺŘıÍťĖĺĲϙċŘĺıϙťēôϙīÍŜħÍϙiĖīϙÍĲîϙ@ÍŜϙĺĲŜôŘŽÍťĖĺĲϙĺııĖŜŜĖĺĲϙϼi@ϽϠϙťÍťôϙĺċ īÍŜħÍϙÍĲîϙĖŜϙċĺŘϙťēôϙŜĺīôϙŪŜôϙĺċϙťēôϙĖĲťôĲîôîϙŘôèĖŕĖôĲťϼŜϽϟϙIťϙıÍƅϙèĺĲťÍĖĲϙèĺĲƱîôĲťĖÍī ÍĲîϯĺŘϙŕŘĖŽĖīôČôîϙĖĲċĺŘıÍťĖĺĲϟϙēôϙŪĲÍŪťēĺŘĖƏôîϙŘôŽĖôſϠϙŪŜôϙĺŘϙîĖŜèīĺŜŪŘôϙĺċϙŜŪèē ĖĲċĺŘıÍťĖĺĲϙıÍƅϙŽĖĺīÍťôϙŜťÍťôϙĺŘϙċôîôŘÍīϙīÍſϟϙIċϙƅĺŪϙÍŘôϙÍĲϙŪĲĖĲťôĲîôîϙŘôèĖŕĖôĲťϙĺċϙťēĖŜϙôϱ ıÍĖīϠϙŕīôÍŜôϙîôīôťôϙĖťϠϙſĖťēĺŪťϙƱŘŜťϙŜÍŽĖĲČϙĺŘϙċĺŘſÍŘîĖĲČϙĖťϠϙÍĲîϠϙŜĺϙťēÍťϙťēôϙi@ϙĖŜϙÍſÍŘô ĺċϙťēôϙıĖŜťÍħôϙĖĲϙŜôĲîĖĲČϙĖťϙťĺϙƅĺŪϠϙèĺĲťÍèťϙaôīϙĖƄŜôϙÍťϙϼ͘͏͖ϱ͖͒͘ϱ͐͑͒͐ϙϽϙĺŘ ϼaôīŽĖĲϟĖƄŜôЬÍīÍŜħÍϟČĺŽϽϟ >Řĺıϡϙ>ŘÍĲħϙĺÍèēϙѴċŘÍĲħϟŘĺÍèēЬēĖīèĺŘŕϟèĺıѳ ôĲťϡϙ®ôîĲôŜîÍƅϠϙVŪĲôϙ͐͗Ϡϙ͑͏͔͑ϙ͘ϡ͓͑ϙa ĺϡ ϙĖƄŜôϠϙaôīŽĖĲϙ@ϙϼi@ϽϙѴıôīŽĖĲϟŘĖƄŜôЬÍīÍŜħÍϟČĺŽѳ ŪæĤôèťϡϙ(ϡϙЀ(³(b[ЁϙŪŘċÍèôϙÍŜĖĲČϙôıôĲťϙôıŕϙ[ĺČϙϼaϙϱ͐͏͖ϙ"ϡϙ͔͑͑ϱ͏͓͘Ͻ aôīϠ ®ĖīīϙîĺϠϙŜĖŘϟ ôèÍŕŕĖĲČϙťēĖŜϙıĺŘĲĖĲČЍŜϙŽĺĖèôıÍĖīϙſĖťēϙŜĺıôϙıĺŘôϙĖĲċĺŘıÍťĖĺĲϡ ôıôĲťϙĤĺæϙĺĲϙaϙϱ͐͏͖ϙƱĲĖŜēôîϙīÍŜťϙĲĖČēťϙſĖťēϙťĺŕϙŕīŪČϙæŪıŕĖĲČϙÍťϙѹ͑͏ϡ͏͏ϙēŘŜϟ ĲċĺŘťŪĲÍťôīƅϠϙſôϙŜťÍŘťôîϙĖĲĤôèťĖĲČϙÍſÍƅϙſĖťēϙ͑͏ϙææīŜϙŜŕÍèôŘϙťĺϙŜŪŘċÍèôϟ Iibϡ ēĖŜϙôıÍĖīϙĺŘĖČĖĲÍťôîϙċŘĺıϙĺŪťŜĖîôϙťēôϙťÍťôϙĺċϙīÍŜħÍϙıÍĖīϙŜƅŜťôıϟϙ"ĺϙĲĺť èīĖèħϙīĖĲħŜϙĺŘϙĺŕôĲϙÍťťÍèēıôĲťŜϙŪĲīôŜŜϙƅĺŪϙŘôèĺČĲĖƏôϙťēôϙŜôĲîôŘϙÍĲîϙħĲĺſϙťēôϙèĺĲťôĲť ĖŜϙŜÍċôϟ ÍŜĖĲČϙſÍŜϙŘŪĲϙſĖťēϙĲĺϙĖŜŜŪôŜϟϙĺĲîĖťĖĺĲĖĲČϙſôĲťϙſĖťēϙĲĺϙĖŜŜŪôŜϙÍŜϙſôīīϟϙôťŪŘĲŜϙŜťĺŕŕôî ÍċťôŘϙÍīīϙèôıôĲťϙſÍŜϙŕŪıŕôîϙÍĲîϙſôŘôϙŜťÍŘťĖĲČϙîĖŜŕīÍèôıôĲťϙſĖťēϙťēôϙŘĖČϟϙŕÍèôŘϙſÍŜ ĺæŜôŘŽôîϙÍťϙŜŪŘċÍèôϙſēôĲϙƱĲĖŜēĖĲČϙŪŕϙŕŪıŕĖĲČϙťÍĖīϟϙĺŕϙŕīŪČϙſÍŜϙîŘĺŕŕôîϙſĖťēϙťēôϙèôıôĲť ŪĲĖťϙèīôÍĲĖĲČϙŪŕϙĺĲϙťĺŕϙĺċϙťēôϙŕīŪČϟϙ>ĖĲÍīϙŕŘôŜŜŪŘôϙſēôĲϙťēôϙèôıôĲťϙŪĲĖťϙƱĲĖŜēôîϙĖťŜ èīôÍĲŪŕϙſÍŜϙ͔͔͏ϙŕŜĖϟϙ®ēôĲϙťēôϙŘĖČϙŕŪıŕŜϙſôŘôϙæŘĺŪČēťϙĺĲϙťĺϙèĺĲťĖĲŪôϙîĖŜŕīÍèôıôĲťϙſĖťē ıŪîϠϙĲĺϙŘôťŪŘĲŜϙſôŘôϙĺæŜôŘŽôîϙſēĖīôϟϙIĲĖťĖÍīϙŕŘôŜŜŪŘôϙſÍŜϙ͖͐͐ŕŜĖϙÍťϙ͗ϟ͏æŕıϟϙ"ĖŜŕīÍèôıôĲť èĺĲťĖĲŪôîϙſĖťēϙÍťťôıŕťŜϙťĺϙŘôČÍĖĲϙŘôťŪŘĲŜϙæƅϙŽÍŘƅĖĲČϙƲĺſϙŘÍťôϙÍĲîϙÍťťôıŕťĖĲČϙťĺ ŘôèĖŕŘĺèÍťôϙèÍŜĖĲČϟϙŪıŕϙŕŘôŜŜŪŘôϙŜťÍŘťôîϙťĺϙĖĲèŘôÍŜôϙſēôĲϙťÍĖīϙèôıôĲťϙſÍŜϙťŪŘĲĖĲČϙťēô èĺŘĲôŘϠϙĖĲîĖèÍťĖĲČϙèôıôĲťϙſÍŜϙīĖċťĖĲČϙċŘĺıϙťēôϙæĺťťĺıϟϙĺŕϙŕīŪČϙæŪıŕôîϙ͕ϙææīŜϙôÍŘīƅϟ ŘôŜŜŪŘôϙæôċĺŘôϙŕīŪČϙæŪıŕϙſÍŜϙ͖͔͒ϙŕŜĖϙÍťϙ͒ϟ͏ϙæŕıϟϙôťſôôĲϙŜôôĖĲČϙŜŕÍèôŘϙÍťϙŜŪŘċÍèôϠ ŕŘôŜŜŪŘôϙĖĲèŘôÍŜĖĲČϙÍŜϙťÍĖīϙťŪŘĲôîϙťēôϙèĺŘĲôŘϠϙÍĲîϙťēôϙŕŘôŜŜŪŘôϙÍťϙťēÍťϙťĖıôϙÍĲîϙæôċĺŘôϙŕīŪČ æŪıŕϠϙĖĲîĖèÍťĖĺĲŜϙÍŘôϙèôıôĲťϙĖŜϙèīĺŜôϙťĺϙŜŪŘċÍèôϟ īÍĲϙċĺŘſÍŘîϙĖŜϙťĺϙŘŪĲϙÍϙťôıŕôŘÍťŪŘôϙīĺČϙťĺϙîôťôŘıĖĲôϙiϙϼôƄŕôèťĖĲČϙťĺϙŘŪĲϙťēôϙīĺČϙÍŘĺŪĲî ͔͐ϡ͏͏ϙťēĖŜϙÍċťôŘĲĺĺĲϽϟϙĺťēϙÍĲϙôϱīĖĲôϙŪĲĖťϙÍĲîϙťôıŕôŘÍťŪŘôϙīĺČϙÍŘôϙĺĲϙťēôϙſôŜťϙŜĖîôϙĺċϙťēô XŪŕÍŘŪħϙĖŽôŘϙŜĺϙæŘĖîČôϙĺŪťÍČôϙſĺĲЍťϙæôϙÍĲϙĖŜŜŪôϙċĺŘϙČôťťĖĲČϙťēôϙīĺČϟϙ>ĺīīĺſĖĲČϙťēôϙīĺČϠϙŕĖŕô ſĖīīϙæôϙŘŪĲϙæôťſôôĲϙťēôϙèÍŜĖĲČϙÍĲîϙèĺĲîŪèťĺŘϙċĺŘϙÍϙťĺŕϙĤĺæϟϙēôϙ"aŜϙŜôĲťϙĲĺťĖƱèÍťĖĺĲϙīÍŜť ĲĖČēťϙťĺϙťēôϙťÍťôϙĖĲŜŕôèťĺŘŜϙċĺŘϙĺŕŕĺŘťŪĲĖťƅϙťĺϙſĖťĲôŜŜϙťēôϙťĺŕϙĤĺæϟϙŪŜťĖĲϙaè[ôĺî ŘôŜŕĺĲîôîϙťēĖŜϙıĺŘĲĖĲČϙſĖťēϙŪīīƅϙŪīīĖŽÍĲϙÍĲîϙVĺŜēϙFŪĲťϙèЍîϠϙÍŜħĖĲČϙťĺϙæôϙħôŕťϙĖĲϙťēô īĺĺŕϟ [ôťϙıôϙħĲĺſϙĖċϙƅĺŪϙĲôôîϙÍĲƅťēĖĲČϙÍîîĖťĖĺĲÍīϟ ôČÍŘîŜϠ >ŘÍĲħϙ«ϙĺÍèē "ŘĖīīĖĲČϙ(ĲČĖĲôôŘ ϙFĖīèĺŘŕϙīÍŜħÍϠϙ[[ ͘͏͖ϟ͔͓͗ϟ͑͒͑͐ϙıĺæĖīô ͘͏͖ϟ͖͖͖ϟ͓͗͐͒ϙĺƯĖèô _____________________________________________________________________________________ Edited By: FVR 6/18/2025 AS-DRILLED SCHEMATIC Milne Point Unit Well: MPU R-107 Last Completed: TBD PTD: 225-049 TD =4,330’(MD) / TD =2,281’(TVD) 20” Orig. KB Elev.: 63.30’ / GL Elev.: 16.7’ 13-3/8” PBTD =4,194’ (MD) / PBTD =2,183’(TVD) CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 117’ N/A 13-3/8” Surface 68 / L-80 / CDC 12.415” Surface 4,319’ 0.1497 OPEN HOLE / CEMENT DETAIL 42” 20 yds Concrete 16" Lead –1500 sx / Tail –~594 sx / Top Job - WELL INCLINATION DETAIL KOP @ 308’ Max Angle = 82° @ 3,617’ TREE & WELLHEAD Tree Wellhead GENERAL WELL INFO API: 50-029-23819.00.00 Completion Date: Page48 2025-0619_Surface_Csg_Topjob_MPU R-107_jh Page 1 of 2 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 6/20/2025 P. I. Supervisor FROM: Josh Hunt SUBJECT: Surface Casing Cement Top Job Petroleum Inspector Milne Point Unit R-107 Hilcorp Alaska LLC PTD 2250490 6/19/2025: I traveled to Parker Rig 273 for a surface cement top job over MPU R-107. I met with Hilcorp representative Bryan Lafleur and we went over the plan forward. The surface riser was still in place, the surface casing was on bottom and cemented but still rigged up to the top drive. Bryan informed me they plan to run emergency slips on this well once the top job is complete. This meant that they had to run the pipe into the well from the rig floor. They were already running 10-foot sticks of ¾-inch conduit into the conductor by surface casing annulus when I arrived and were able to work the pipe down to about 183 feet RKB. The bottom of the conductor is 127.2 feet RKB giving a total of 55.8 feet of open hole below the conductor. The conduit was run into the annulus with ease. Bryan LaFleur was not comfortable proceeding with the conduit so he had 1-inch Hydril pipe brought to location. The ¾-inch conduit was pulled and replaced with 1-inch Hydril pipe, giving them a bigger ID pipe to allow for more flow and a higher-pressure rating. They tagged up in the exact same spot and attempted to work it down for a while with no luck. Each tag was solid, so the decision was made to circulate and pump cement. They rigged up to the 1-inch pipe and circulated 127 bbls of drilling mud while they had a crew change and safety meeting. The fluid returns looked very clean. Halliburton started pumping cement at 07:36 pm and pumped a total of 47 bbls of cement at a rate of 2 bbls/min. At 47 bbls away they grabbed a sample and got a good cement weight at 10.7 ppg going in and coming out of the annulus. The cement was in place at 08:21 pm. Halliburton pumped some additional cement to empty their mixing tank then the pumps were shut to allow the cement time to settle. There were zero fluid losses during this job and instant returns every time the pump was kicked on. There were also no clays or cuttings in the return flow up the annulus throughout the top job. This was the quickest and cleanest top job I have witnessed thus far. The calculated displacement was 45 to 50 bbls including allowance for formation wash-out. Attachments: Photos         2025-0619_Surface_Csg_Topjob_MPU R-107_jh Page 2 of 2 Surface Casing Top Job – MPU R-107 (PTD 2250490) Photos by AOGCC Inspector J. Hunt 6/19/2025 Mule shoe on 1-inch Hydril pipe Returns coming out of one of the 4-inch valves on the conductor From:Rixse, Melvin G (OGC) To:AOGCC Permitting (CED sponsored); AOGCC Records (CED sponsored) Subject:20250619 1536 APPROVAL MPU R-107 13-3/8" Surface Casing Cement Job Evaluation and Top Job (PTD: 225- 049) Date:Thursday, June 19, 2025 3:37:22 PM From: Rixse, Melvin G (OGC) Sent: Thursday, June 19, 2025 9:29 AM To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: Re: [EXTERNAL] RE: MPU R-107 13-3/8" Surface Casing Cement Job Evaluation and Top Job (PTD: 225-049) Verbal approval. Okay to perform top job with state witness of TOC utilizing spaghetti string. Mel Rixse On Jun 19, 2025, at 9:11 AM, Joseph Lastufka <Joseph.Lastufka@hilcorp.com> wrote: Morning Mel, Appreciate all your (late night) efforts, does this constitute as a verbal approval? I have the sundry ready to submit but prefer to have the date included in the verbal approval area. There is a possibility that we could be pumping cement today. Please let me know if you have any questions. Thanks! Thanks, Joe Lastufka Sr. Drilling Technologist Hilcorp North Slope, LLC Office: (907)777-8400, Cell:(907)227-8496 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, June 18, 2025 11:20 PM To: Frank Roach <frank.roach@hilcorp.com> Subject: [EXTERNAL] RE: MPU R-107 13-3/8" Surface Casing Cement Job Evaluation and Top Job (PTD: 225-049) CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Frank, Thanks for the log. Do you think the shift at ~350’ could be TOC? Anyway, should be good to go with your top job as long as inspectors witness the tag with spaghetti pipe. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Frank Roach <frank.roach@hilcorp.com> Sent: Wednesday, June 18, 2025 10:26 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: MPU R-107 13-3/8" Surface Casing Cement Job Evaluation and Top Job (PTD: 225-049) Mel, Attached is the temperature log run on the 13-3/8” surface casing. We managed to get down to ~2,378’ before losing weight. While there are some bobbles in temperature, I’m not seeing much contrast and would say it’s inconclusive data to pick TOC. Between the 20 bbls of spacer at surface before not seeing returns, fluid level remaining static, and building pressure during displacement and when tail rounded the shoe, all are indications that cement is close to surface. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Our top job cement is currently staged at the east side of the Kuparuk River. The water level has been receding, and folks up north are forecasting a window after midnight where the river will be low and slow enough to allow an escorted convoy across. If this is the case, we’ll be ready for picking up pipe for the top job. The rig has been in contact with inspector Josh Hunt throughout the day and will keep him updated on our status. Regards, Frank V Roach Drilling Engineer <image001.jpg> Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, June 18, 2025 2:56 PM To: Frank Roach <frank.roach@hilcorp.com> Subject: [EXTERNAL] RE: MPU R-107 13-3/8" Surface Casing Cement Job Evaluation and Top Job (PTD: 225-049) Frank, Thanks. Will look for the temperature log. Mel From: Frank Roach <frank.roach@hilcorp.com> Sent: Wednesday, June 18, 2025 11:15 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Subject: MPU R-107 13-3/8" Surface Casing Cement Job Evaluation and Top Job (PTD: 225-049) Mel, Following up with more information after receiving the industry guidance bulletin 13-01 email: Primary cement job details: 1. 763 bbls (1,500sx) 10.7ppg ArcticCem lead cement (2.855 cuft/sk) 2. 122 bbls (594 sx) 15.8ppg HalCem tail cement (1.153 cuft/sk) 3. No losses during casing run, mud conditioning, nor during the pumping of spacer, lead cement, and tail cement 4. 20 bbls spacer observed at surface 5. No returns when bringing on mud pumps for displacement 6. Fluid level static at surface during displacement Current Operations: 7. E-line with temperature log on the hook for running @ ~15:00 hrs. No tractor is available, so the log will be run as deep as possible (>70° inc @ ~2,360’). 8. DSM’s initially notified AOGCC inspectors for opportunity to witness top job with receipt by Austin McLeod. After industry guidance bulletin email received, a follow-up note to the inspectors for opportunity to witness temp log was sent. Josh Hunt has been in phone contact with our DSM’s as he’s currently west of the Kuparuk River. 9. Cement plan to follow. I will update you when the temperature log is completed. I’m also working with Joe Lastufka on the Sundry Application 10-403 to be submitted once we have the temperature log results. Let me know if you need anything additional. Regards, Frank V Roach Drilling Engineer <image001.jpg> Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, June 18, 2025 9:31 AM To: Frank Roach <frank.roach@hilcorp.com> Subject: RE: [EXTERNAL] Surface Casing Cement Temp Log (MPU R-107 PTD: 225-049) 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Frank, Received. Thanks. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Frank Roach <frank.roach@hilcorp.com> Sent: Wednesday, June 18, 2025 9:24 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] Surface Casing Cement Temp Log (MPU R-107 PTD: 225-049) Mel, Will do, sir. Recapping this morning’s voicemail with some more information: Cement job on MPU R-107 finished last night with top plug bumping at ~20:00 hrs. Unfortunately, we started injecting away with 20 bbls spacer to surface. Casing was run with no issues. Conditioning went with no issues as well. Returns stopped after all cement was pumped and were starting CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. displacement with the rig. Spacer was observed at surface when finishing up pumping tail. Top plug was dropped with the cement unit cleaning up on top of the plug. Final pressure when the cement unit finished its cleanup was 550 psi. When the rig pumps were brought on to continue displacement with mud, no returns were observed while. Initial pressure was 711psi at 8.0bpm. Displacement continued with attempts to regain returns by varying flow rate and attempting to reciprocate casing. Pump pressure started to increase when tail cement was turning the corner, indicating cement was lifting from the bottom. Top plug bumped 6 bbls early. Pressure before plug bump was 753 psi at 3.0 bpm. Between seeing spacer at surface, pressure increasing as tail turned the corner, and the pressure at that time and before plug bump, indications are cement is close to surface. Plan forward is to run a temperature log to determine TOC (expecting to run the log around 15:00 this afternoon). Both an e-line unit and temperature log are on the west side of the Kuparuk River so bridge outage won’t be an issue for getting the log. Following the log, pipe will be run between the casing and conductor for a top job. The DSMs sent notification last night to the State inspectors for opportunity to witness the top job. Austin McLeod responded this morning with Sully Sullivan and Josh Hunt Cc’d, asking to be kept in the loop. Let me know if you need anything additional. Regards, Frank V Roach Drilling Engineer <image001.jpg> Hilcorp Alaska, LLC 907.854.2321 mobile 907.777.8413 office From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, June 18, 2025 8:39 AM To: Frank Roach <frank.roach@hilcorp.com> Subject: [EXTERNAL] Surface Casing Cement Temp Log Frank, Call me when you get your temperature log. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received thismessage in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited.If you have received this email in error, please immediately notify us by return email or telephone if the sender's phonenumber is listed above, then promptly and permanently delete this message. 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While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient toensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems or data. No responsibility is accepted by the company in this regard and the recipient should carry out suchvirus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received thismessage in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited.If you have received this email in error, please immediately notify us by return email or telephone if the sender's phonenumber is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient toensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems or data. No responsibility is accepted by the company in this regard and the recipient should carry out suchvirus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only forthe use of the individual or entity named above. If you are not an intended recipient or if you have received thismessage in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient toensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect itssystems or data. No responsibility is accepted by the company in this regard and the recipient should carry out suchvirus and other checks as it considers appropriate. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Unmanned Flowback 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): ±XX,XXX'N/A Casing Collapse Structural N/A Conductor 2,260psi Surface 3,090psi Slotted Liner 6,390psi Slotted Liner 8,540psi See Schematic See Schematic Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Hayden Moser Contact Email:Hayden.Moser@hilcorp.com Contact Phone:907-793-1231 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ±23,682'4-1/2" ±XX,XXX' 3-1/2" ±XX,XXX' ±XX,XXX' ±XX,XXX' 1,349 N/A Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY MPU R-107 Millne Point Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): 7/14/2025 Subsequent Form Required: Suspension Expiration Date: 225-049 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-2381900-00 Hilcorp Alaska LLC C.O. 477.005 TVD Burst AOGCC USE ONLY 9.3 / L-80 / TXP ±11,182 STATE OF ALASKASTATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL025509, 388235, 355018 & 390615 ±XX,XXX' 4,319' ѷ͐͐Ϡ͏͏͖Д Length Size Proposed Pools: 80' 80' Schrader Bluff and Nikaitchuq N/A MD N/A 7,740psi 5,020psi 5,750psi ±2264 ±X,XXX' 20"20" 13-3/8" 9-5/8" 5-1/2" 9-5/8 SLZXP and N/A9-5/8 SLZXP and N/A ±XX,XXX' MD/ ±XX,XXX' TVD and N/A ±15,182' Perforation Depth MD (ft): ±15,182' 9,020psi No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Wells Manager Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2025.06.17 11:35:29 - 08'00' Taylor Wellman (2143) 325-366 By Grace Christianson at 1:16 pm, Jun 17, 2025 10-407 (origninal well completion sundry) & Nikaitchuq SFD 50-029-23819-00-00 SFD SFD 7/12/2025MGR30JUN2025 YES 11JULY2025 MEL RIXSE (PE) * Approved for 30 days of initial production flow back DSR-6/18/25 477B SFD JLC 7/14/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.14 09:09:34 -08'00'07/14/25 RBDMS JSB 071425 New Drill Injector Well: MPU R-107 Date: 06/13/2025 Well Name:MPU R-107 API Number:50-029-23819-00-00 Current Status:Drilling Rig:N/A Estimated Start Date:07/14/2025 Estimated Duration:1day Reg.Approval Req’d?Yes Date Reg. Approval Rec’vd:TBD Regulatory Contact:Tom Fouts Permit to Drill Number:225-049 First Call Engineer:Taylor Wellman 907-947-9533 Second Call Engineer:Hayden Moser 479-899-8940 Current Bottom Hole Pressure:N/A Max. Proposed Surface Pressure:1349 psig Min ID:2.810” @ TBD’ Sliding Sleeve Brief Well Summary and Objective MPU R-107 is currently being drilled as a lateral injector in the Schrader OA. It is currently approved for a 30 day flowback. With the recent approval from the AOGCC on unmanned flowbacks, we would like to obtain approval for this well. Notes on Well Condition x SSV Pilot Settings: o Production SSV low pressure trip will be set to 25% of FTP or 50% of inlet separator pressure. o Production SSV high pressure trip will be set at 1100 psig. o Power fluid XV low pressure trip will be set to 50% of header pressure. o Power Fluid XV to be actuated if vertical run tubing SSV is actuated (within 2 minutes). x AOGCC will be notified for opportunity to witness before production begins. x Visual leak check by pad operator performed at least once per tower (i.e. ~ every 12 hours). x SCADA screen available in control room for pressure and flow sensors on injection line and well’s flow line. x Pilot trip pressures, both high and low, documented in permitting documents for Hilcorp pad operators and AOGCC inspectors. Post-Rig Work (Sundried Step): 1. MU surface lines from power fluid header to the tubing. Rig up piping and instrumentation per Unmanned Injector Flowback Diagram. a. Pressure test lines at existing power fluid head pressure (3,500 psi) 2. Rig up piping and instrumentation to the production header per Unmanned Injector Flowback Diagram. Pressure test to 3,500 psi. Attachments: 1. Unmanned Injector Flowback Diagram New Drill Injector Well: MPU R-107 Date: 06/13/2025 _____________________________________________________________________________________ Revised By: TDF 6/16/2025 PROPOSED Milne Point Unit Well: MPU R-107 Last Completed: TBD PTD: TBD TD =23,682’(MD) / TD =4,014’(TVD) 4 20” Orig. KB Elev.: 63.65’ / GL Elev.: 16.7’ 9-5/8” 5 8 13-3/8” 1 3 See Slotted Liner Detail PBTD =23,681’(MD) / PBTD =4,014’(TVD) 7 5,6 3-1/2” 3 2 4 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface ±80’ N/A 13-3/8” Surface 68 / L-80 / CDC 12.415” Surface ±4,121’ 0.1497 9-5/8” Intermediate 40 / L-80 / BTC 8.835” Surface ±11,007’ 0.0758 5-1/2” Slotted Liner 17 / L-80 / JFE Bear 4.892” 10,857’ ±15,182’ 0.0232 4-1/2” Slotted Liner 13.5 / L-80 / Hyd 625 3.920” 15,182’ ±23,682’ 0.0149 TUBING DETAIL 3-1/2" Tubing 9.3# / L-80 / TXP 2.992” Surface ±11,182’ 0.0087 OPEN HOLE / CEMENT DETAIL 42” 20 yds Concrete 16" Lead –~1453 sx / Tail –~595 sx 12-1/4” Lead –~839 sx / Tail –~573 sx 8-1/2” Uncemented Slotted Liner WELL INCLINATION DETAIL KOP @ 325’ 90° Hole Angle = @ 11,343’, Max = ±94° TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 13-5/8” 5K bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: Completion Date: SLOTTED LINER DETAIL Top (MD) Top (TVD) Btm (MD) Btm (TVD) 5-1/2” 4-1/2” JEWELRY DETAIL No Top MD Item ID UPPER COMPLETION 1 ~2,700’ X-Nipple, 2.813” 2.813” 2 TBD Sliding Sleeve 2.810” 3 TBD Zenith Gauge Mandrel 3.953” 4 TBD XN Nipple, 2.813” 2.813” 5 TBD Locater Sub, 3.5” x 8.25” No Go (bottom of locator spaced out 3.78’) 3.240” 6 TBD Bullet Seals –7” H511 x Ratcheting Mule Shoe 6.160” LOWER COMPLETION 7 ~10,857’ 9-5/8” SLZXP Liner Top Packer 6.180” 8 ~23,682’ Shoe 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 Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Milne Point Unit Field, Schrader Bluff and Nikaitchuq Oil, MPU R-107 Hilcorp Alaska, LLC Permit to Drill Number: 225-049 Surface Location: 5144' FSL, 4182' FEL, Sec. 07, T13N, R10E, UM, AK Bottomhole Location: 2276' FSL, 1127' FEL, Sec. 28, T14N, R09E, UM, AK Dear Mr. McLaughlin: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 5th day of June 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.05 08:23:08 -08'00' Joe Engel for Sean McLaughlin By Grace Christianson at 1:33 pm, May 07, 2025 Digitally signed by Joseph Engel (2493) DN: cn=Joseph Engel (2493) Date: 2025.05.07 13:07:15 - 08'00' Joseph Engel (2493) A.Dewhurst 04JUN25 * BOPE test to 3000 psi. Annular to 2500 psi. * MIT-IA to 3500 psi with rig after landing tubing. * 10-403 required for 30 day POP prior to injection if no 24/7 man watch while on production. * MIT-IA to 2000 psi after 5 days of stabilized injection. State to witness. 50-029-23819-00-00 MGR02JUN2025 225-049 DSR-5/8/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.05 08:23:20 -08'00' 06/05/25 06/05/25 Pink squares are Top OA tops Proposed TD Prognosed Top Schrader (R-107)OP05-06OP05-06L1Purple cylinder represents area within ¼ mile radius of R-107 PTDAPIWELLSTATUSTop of SBOA (MD)Top of SBOA (TVD)Top ofCement(MD)Top ofCement(TVD)Schrader OAstatusZonal Isolation224-121 50-029-23802-00-00 MPU R-104Active Producer - Schrader11522 3949 7605 3107 OpenThe 9-5/8" was cemented with 242 bbls of 12ppg lead cement and 56 bbls of 15.8ppgtail cement inside 12-1/4" hole. No losses were observed during the job. Assuming20% washout, TOC is 7605' MD.222-118 50-029-23730-00-00 MPU M-30Active Producer - Schrader6857 3976 Surface Surface OpenThe 9-5/8" casing was cemented to surface via a 2 stage cement job with over 200bbls returned to surface.222-128 50-029-23734-00-00 MPU M-32Active Producer - Schrader8352 3993 Surface Surface OpenThe 9-5/8" casing was cemented to surface via a 2 stage cement job with over 270bbls returned to surface.222-119 50-029-23731-00-00 MPU M-31Active Injector- Schrader7563 3992 Surface Surface OpenThe 9-5/8" casing was cemented to surface via a 2 stage cement job with over 250bbls returned to surface.222-137 50-029-23736-00-00 MPU M-33Active Injector- Schrader8020 4026 Surface Surface OpenThe 9-5/8" casing was cemented to surface via a 2 stage cement job with over 257bbls returned to surface.223-006 50-029-23744-00-00 MPU M-62Active Producer - Schrader9053 4038 Surface Surface OpenThe 9-5/8" casing was cemented to surface via a 2 stage cement job with over 273bbls returned to surface.210-080 50-029-23427-00-00 OP05-06Active Producer - Schrader8423 3804 6586 -3276 OpenThe 9-5/8" was cemented with 157bbls of 12.5ppg inside 12-1/4" hole. The drillingreport does not mention any notes about losses or returns. Assuming 30% washout,TOC is 6586' MD.213-115 50-029-23427-60-00 OP05-06L1Active Producer - Schrader8423 3804 6586 -3276 OpenThe 9-5/8" was cemented with 157bbls of 12.5ppg inside 12-1/4" hole. The drillingreport does not mention any notes about losses or returns. Assuming 30% washout,TOC is 6586' MD.225-017 50-029-23815-00-00 MPU R-105 Active drillwell -Schrader (in production hole) 11359 3949 5127OpenThe 9-5/8" was cemented with 285 bbls of 14ppg lead cement and 126bbls of 15.8 tailcement inside of 12-1/4" hole. 70bbl losses during entire job. TOC at 5,127' MD (CBLrun on 4/20/2025).225-033 50-029-23816-00-00 Future R-106TBDTBD Future R-107TBDTBD Future R-108TBDTBD Future R-109TBDTBD Future R-110Area of Review MPU R-107 SB OAn/a Milne Point Unit (MPU) R-107 Drilling Program Version 0 4/30/2025 Table of Contents 1.0 Well Summary .......................................................................................................................... 2 2.0 Management of Change Information ....................................................................................... 3 3.0 Tubular Program:..................................................................................................................... 4 4.0 Drill Pipe Information: ............................................................................................................. 4 5.0 Internal Reporting Requirements ............................................................................................ 5 6.0 Planned Wellbore Schematic .................................................................................................... 6 7.0 Drilling / Completion Summary ............................................................................................... 7 8.0 Mandatory Regulatory Compliance / Notifications ................................................................. 8 9.0 R/U and Preparatory Work .................................................................................................... 11 10.0 N/U 21-1/4” 2M Diverter System ............................................................................................ 12 11.0 Drill 16” Hole Section ............................................................................................................. 14 12.0 Run 13-3/8” Surface Casing ................................................................................................... 17 13.0 Cement 13-3/8” Surface Casing .............................................................................................. 20 14.0 N/U BOP and Test................................................................................................................... 23 15.0 Drill 12-1/4” Hole Section ....................................................................................................... 24 16.0 Run 9-5/8” Intermediate Casing ............................................................................................. 28 17.0 Cement 9-5/8” Intermediate Casing ....................................................................................... 31 18.0 Drill 8-1/2” Hole Section ......................................................................................................... 34 19.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) ..................................................... 39 20.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................ 44 21.0 RDMO ..................................................................................................................................... 45 22.0 Post-Rig Work ........................................................................................................................ 46 23.0 Parker 273 Diverter Schematic .............................................................................................. 47 24.0 Parker 273 BOP Schematic .................................................................................................... 48 25.0 Wellhead Schematic ................................................................................................................ 49 26.0 Days vs Depth .......................................................................................................................... 50 27.0 Formation Tops & Information.............................................................................................. 51 28.0 Anticipated Drilling Hazards ................................................................................................. 54 29.0 Parker 273 Layout .................................................................................................................. 59 30.0 FIT Procedure ......................................................................................................................... 60 31.0 Parker 273 Choke Manifold Schematic.................................................................................. 61 32.0 Casing Design .......................................................................................................................... 62 33.0 12-1/4” Hole Section MASP .................................................................................................... 63 34.0 8-1/2” Hole Section MASP ...................................................................................................... 64 35.0 Spider Plot (NAD 27) (Governmental Sections) ..................................................................... 65 36.0 Surface Plat (As-Staked) (NAD 27) ........................................................................................ 66 Page 2 Milne Point Unit R-107 SB Injector Drilling Procedure 1.0 Well Summary Well MPU R-107 Pad Milne Point “R” Pad Planned Completion Type 3-1/2” Injection Tubing Target Reservoir(s)Schrader Bluff Oa Sand Planned Well TD, MD / TVD 23,682’ MD / 4,014’ TVD PBTD, MD / TVD 23,681’ MD / 4,014’ TVD Surface Location (Governmental) 5,144' FSL, 4,182' FEL, Sec. 07, T13N, R10E, UM, AK Surface Location (NAD 27)X= 540,396.97 Y=6,033,308.92 Top of Productive Horizon (Governmental)477' FSL, 1,177' FEL, Sec 35, T14N, R9E, UM, AK TPH Location (NAD 27)X= 532,927.51 Y= 6,039,163.66 BHL (Governmental)2,276' FSL, 1,127' FEL, Sec 28, T14N, R9E, UM, AK BHL (NAD 27)X= 522,381.00 Y= 6,046,202.00 AFE Drilling Days 34 days AFE Completion Days 2 days Maximum Anticipated Pressure (Surface)1349 psig Maximum Anticipated Pressure (Downhole/Reservoir)1746 psig Work String 5-1/2” 21.9# S-135 Delta 544 KB Elevation above MSL:46.95 ft + 16.6 ft = 63.65 ft GL Elevation above MSL:16.7 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit R-107 SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit R-107 SB Injector Drilling Procedure 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 20” 19.25”---X-52Weld 16” 13-3/8” 12.415” 12.259” 14.375” 68 L-80 CDC 5,020 2,260 1,556 12-1/4” 9-5/8” 8.835” 8.679” 10.625” 40 L-80 BTC 5,750 3,090 916 8-1/2” 5-1/2” 4.892” 4.767” 6.050” 17 L-80 JFE Bear 7,740 6,290 397 8-1/2” 4-1/2” 3.960”3.795” 4.714” 13.5 L-80 H625 9020 8540 279 Tubing 3-1/2” 2.992” 2.867” 4.500” 9.3 L-80 EUE 8RD 9289 7399 163 4.0 Drill Pipe Information: Hole Section OD (in) ID (in) TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface, INT, & Production 5-1/2” 4.778” 4.000” 6.625” 21.9 S-135 Delta 544 41,900 58,700 786klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Milne Point Unit R-107 SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to sean.mclaughlin@hilcorp.com, frank.roach@hilcorp.com,brad.gorham@hilcorp.com, and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to sean.mclaughlin@hilcorp.com,frank.roach@hilcorp.com, brad.gorham@hilcorp.com, and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to sean.mclaughlin@hilcorp.com, frank.roach@hilcorp.com,brad.gorham@hilcorp.com, and joseph.lastufka@hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Email Drilling Manager Sean McLaughlin 907.777.8300 sean.mclaughlin@hilcorp.com Drilling Engineer Frank Roach 907.777.8413 frank.roach@hilcorp.com Drilling Engineer Brad Gorham 907.263.3917 brad.gorham@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 twellman@hilcorp.com Geologist Graham Emerson 907.564.5242 graham.emerson@hilcorp.com Reservoir Engineer Pedro San Blas 907.564.4056 pedro.sanblas@hilcorp.com Drilling Env. Coordinator Adrian Kersten 907.564.4820 adrian.kersten@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com _____________________________________________________________________________________ Edited By: FVR 4/23/2025 PROPOSED SCHEMATIC Milne Point Unit Well: MPU R-107 Last Completed: TBD PTD: TBD TD =23,682’ (MD) / TD =4,014’(TVD) 4 20” Orig. KB Elev.: 63.65’ / GL Elev.: 16.7’ 9-5/8” 5 8 13-3/8” 1 3 See Slotted Liner Detail PBTD =23,681’ (MD) / PBTD =4,014’ (TVD) 7 5,6 3-1/2” 3 2 4 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20"Conductor 129.5 / X52 / Weld N/A Surface 80’ N/A 13-3/8”Surface 68 / L-80 / CDC 12.415” Surface 4,121’ 0.1497 9-5/8” Intermediate 40 / L-80 / BTC 8.835” Surface 11,007’ 0.0758 5-1/2” Slotted Liner 17 / L-80 / JFE Bear 4.892” 10,857’ 15,182’ 0.0232 4-1/2” Slotted Liner 13.5 / L-80 / Hyd 625 3.920” 15,182’ 23,682’ 0.0149 TUBING DETAIL 3-1/2"Tubing 9.3# / L-80 / TXP 2.992” Surface 11,182’ 0.0087 OPEN HOLE / CEMENT DETAIL 42” 20 yds Concrete 16" Lead – ~1453 sx / Tail – ~595 sx 12-1/4” Lead – ~839 sx / Tail – ~573 sx 8-1/2” Uncemented Slotted Liner WELL INCLINATION DETAIL KOP @ 325’ 90° Hole Angle = @ 11,343’, Max = 94° TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 13-5/8” 5K bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: Completion Date: 5-1/2” x 4-1/2” Slotted LINER DETAIL Top (MD) Top (TVD) Btm (MD) Btm (TVD) 5-1/2” 4-1/2” JEWELRY DETAIL No Top MD Item ID Upper Completion 1 ~2,700’ X-Nipple, 2.813” 2.813” 2 TBD Sliding Sleeve 2.810” 3 TBD Zenith Gauge Mandrel 3.953” 4 TBD XN Nipple, 2.813”2.813” 5 TBD Locater Sub, 3.5” x 8.25” No Go (bottom of locator spaced out 3.78’) 3.240” 6 TBD Bullet Seals – 7” H511 x Ratcheting Mule Shoe 6.160” Lower Completion 7 ~10,857’ 9-5/8” SLZXP Liner Top Packer 6.180” 8 ~23,682’ Shoe Page 7 Milne Point Unit R-107 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary MPU R-107 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. R-107 is part of a multi well development program targeting the Schrader Bluff sand on R-pad. Hilcorp requests to pre- produce R-107 for up to 30 days. The directional plan is a horizontal well with 16” surface hole with 13-3/8” surface casing set in the SV1. A 12-1/4” intermediate hole with 9-5/8” intermediate casing set into the top of the Schrader Bluff sand. An 8- 1/2” lateral section will be drilled. An injection liner will be run in the open hole section. The Parker 273 will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately June 10th, 2025, pending rig schedule. Surface casing will be run to ~4,121’ MD / 2,264’ TVD and cemented to surface. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility. General sequence of operations: 1. MIRU Parker 273 to well site 2. N/U & Test 21-1/4” Diverter and 16” diverter line 3. Drill 16” surface hole to TD of surface hole section. Run and cement 13-3/8” surface casing 4. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser 5. Drill 12-1/4” hole to TD of intermediate hole section. Run and cement 9-5/8” surface casing 6. Drill 8-1/2” lateral to well TD. 7. Run 5-1/2” x 4-1/2” injection liner. 8. Run 3-1/2” tubing. 9. N/D BOP, N/U Tree, RDMO. Reservoir Evaluation Plan: 1. Surface Hole: No mud logging. Remote geologist. LWD: GR + Res 2. Intermediate Hole: No mud logging. Remote geologist. LWD: GR + Res 3. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering) Page 8 Milne Point Unit R-107 SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that all drilling and completion operations comply with all applicable AOGCC regulations. Operations stated in this PTD application may be altered based on sound engineering judgement as wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU R-107. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the PTD. x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the well bore, AOGCC is to be notified and we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. Page 9 Milne Point Unit R-107 SB Injector Drilling Procedure AOGCC Regulation Variance Requests: 1) Hilcorp is requesting approval for a test period of pre-producing R-107 for up to 30 days via a forward circulating jet pump completion. This will allow us to measure skin and evaluate the benefits of pre- producing our injectors in the future. During flow back, Hilcorp will have a 24/7 man watch while the well is online and producing. Section 22 details the steps required to make this happen. Note also that the MIT-IA has been changed from 2,000 psi to 3,500 psi. * Separate 10-403 required if Hilcorp wants to pre-produce this well without 24/7 man watch. Page 10 Milne Point Unit R-107 SB Injector Drilling Procedure Summary of BOP Equipment & Notifications Hole Section Equipment Test Pressure (psi) 12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only 12-1/4” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 Annular: 250/2500 Subsequent Tests: 250/3000 Annular 250/2500 8-1/2” x 13-5/8” x 5M Annular BOP x 13-5/8” x Double Gate o Blind ram in btm cavity x Mud cross w/ 3-1/8” x 5M side outlets x 13-5/8” x Single ram x 3” x 5M Choke Line x 2” x 5M Kill line x 3” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 Annular: 250/2500 Subsequent Tests: 250/3000 Annular 250/2500 Primary closing unit: Sara Koomey Control Unit, 3,000 psi, 316 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an air-driven pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOP’s utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in PTD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 11 Milne Point Unit R-107 SB Injector Drilling Procedure 9.0 R/U and Preparatory Work 9.1 R-107 will utilize a newly set 20” conductor on R-Pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Parker 273. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mix spud mud for 16” surface hole section. Ensure mud temperatures are cool (<80qF). 9.9 Ensure 6” or 6-1/4” liners in mud pumps. x NOV 12-P-160 1,600 HP mud pump ratings: x 6” Liners: 4,670 psi, 507 gpm @ 120 spm @ 96% volumetric efficiency. x 6-1/4” Liners: 4,305 psi, 551 gpm @ 120 spm @ 96% volumetric efficiency. Page 12 Milne Point Unit R-107 SB Injector Drilling Procedure 10.0 N/U 21-1/4” 2M Diverter System 10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program). x N/U 20” riser to BOP Deck x N/U 20”, 5M diverter “T”. x NU Knife gate & 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID greater than 20”) 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking x A prohibition on ignition sources or running equipment x A prohibition on staged equipment or materials x Restriction of traffic to essential foot or vehicle traffic only. Page 13 Milne Point Unit R-107 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 14 Milne Point Unit R-107 SB Injector Drilling Procedure 11.0 Drill 16” Hole Section 11.1 P/U 16” directional drilling assembly: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Use GWD until 1,500’ or MWD surveys clean up, whichever is deeper. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5-1/2” 21.9# S-135. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 16” hole section to section TD, in the SV1. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Efforts should be made to minimize dog legs in the surface hole. Do not exceed 5 deg / 100. If a DLS > 5 deg / 100 is measured, immediately backream stand to knock down severity. x Do not exceed 80° inclination in interval. If survey shows inc > 80°, immediately backream stand to knock down inclination. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Mud rheology is the primary method of transporting cuttings. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 gpm, staying between 400 and 450 gpm through the permafrost. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increases in pump pressure, or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). x Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when MWD surveys clean up or after 1,500’ (whichever is deeper). Page 15 Milne Point Unit R-107 SB Injector Drilling Procedure x Be ready for the dead zone around base permafrost and the formation horizons at and just below base permafrost. Can be in 100% slide and still lose angle in the dead zone. However, BHA can deflect (ie. high DLS) when drilling through formation horizons. Remember, the intermediate hole section has minimal directional work until the last ~300’ so there’s plenty of footage to get back on plan. x Gas hydrates have not been seen on pads adjacent to R-Pad (F-Pad and L-Pad). However, be prepared for them. In MPU they have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be prepared for hydrates: x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. x AC: All wells have a clearance factor greater than 1.0 in the surface interval. 16” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with 9.2+ ppg. Depth Interval MW (ppg) Surface – Base Permafrost 8.8+ Base Permafrost - TD 9.2+ x PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. x Rheology: MI-Gel should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: PolyPac Supreme UL should be used for filtrate control. Background LCM (10 ppb total) can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. x Wellbore and mud stability:Additions of SCREENKLEEN are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of BUSAN 1060 MUST be made to control bacterial action. Page 16 Milne Point Unit R-107 SB Injector Drilling Procedure x Casing Running:Attempt to maintain mud rheology until casing is on bottom. Reduce system YP with DESCO and SAPP as last resort for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type:8.8 – 9.8 ppg Pre-Hydrated MI-Gel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 –9.8 75-300 20 - 40 25-45 <10 8.5 –9.0 70 F System Formulation:Gel + FW spud mud Product- Surface hole Size Pkg ppb or (% liquids) M-I Gel 50 lb sx 25 Soda Ash 50 lb sx 0.25 PolyPac Supreme UL 50 lb sx 0.08 Caustic Soda 50 lb sx 0.1 SCREENCLEEN 55 gal dm 0.5 11.4 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.5 RIH to bottom, proceed to BROOH to HWDP x Prior to pulling off bottom, ensure GWD is configured in out-run mode x Pump at full drill rate (400-600 gpm) and maximize rotation. x Pull slowly, 5 – 10 ft / minute. x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 11.6 TOOH and LD BHA Page 17 Milne Point Unit R-107 SB Injector Drilling Procedure 12.0 Run 13-3/8” Surface Casing 12.1 R/U Parker Wellbore 13-3/8” casing running equipment (CRT & Tongs) x Ensure 13-3/8” CDC x Delta 544 XO on rig floor and M/U to FOSV. x Use API Modified thread compound. Dope pin end only w/ paint brush. x R/U CRT x Discuss circulation strategy with drilling engineer prior to running casing. x Ensure all casing has been drifted to 12-1/4” on the location prior to running. x Note that 68# drift is 12.259” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.2 P/U shoe joint, visually verify no debris inside joint. 12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of: 13-3/8” Float Shoe 1 joint – 13-3/8” CDC, 2 Centralizers 10’ from each end w/ stop rings 1 joint –13-3/8” CDC, 1 Centralizer mid joint w/ stop ring 1 joint – 13-3/8” CDC, 1 Centralizer mid joint w/ stop ring 13-3/8” Float Collar x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. 12.4 Continue running 13-3/8” surface casing x Fill casing on the fly, through the CRT. x Use API Modified thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 2500’ MD from shoe x 1 centralizer every other joint to ~200’ below surface x Utilize a collar clamp until weight is sufficient to keep slips set properly. x If casing run indicates poor hole conditions prior to reaching base permafrost, discuss washing down casing with the drilling engineer. x Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 13-3/8” 68# L-80 CDC Make-Up Torques: Casing OD Minimum Maximum Yield 13-3/8”17,000 ft-lbs 21,000 ft-lbs 73,900 ft-lbs Page 18 Milne Point Unit R-107 SB Injector Drilling Procedure Page 19 Milne Point Unit R-107 SB Injector Drilling Procedure 12.5 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.6 Slow in and out of slips. 12.7 MU last joint of casing and tag TD. Position the casing shoe +/- 10’ from TD. Ensure casing is spaced out such that a collar is not in the wellhead slip area. 12.8 Lower casing to setting depth. Confirm measurements. 12.9 Have slips staged in cellar along with all necessary equipment for the operation. 12.10 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 Milne Point Unit R-107 SB Injector Drilling Procedure 13.0 Cement 13-3/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Drop first bottom plug – HEC rep to witness. Pump spacer. 13.7 Drop second bottom plug – HEC rep to witness. Mix and pump lead cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 13.8 Drop third bottom plug – HEC rep to witness. Mix and pump tail cement per below calculations, confirm actual cement volumes with cementer after TD is reached. x Cement volume based on annular volume + open hole excess (250% for lead above base permafrost and 40% for all cement below base permafrost). Job will consist of lead & tail, TOC brought to surface. Page 21 Milne Point Unit R-107 SB Injector Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights. If the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.10 After pumping cement, drop top plug – HEC rep to witness, and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.11 Ensure rig pump is used to displace cement. 13.12 Displacement calculation is in the Stage 1 Table in step 13.8. 13.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. Lead Slurry Tail Slurry System ArcticCem HalCem Density 10.7 lb/gal 15.8 lb/gal Yield 2.88 ft3/sk 1.16 ft3/sk Mix Water 22.02 gal/sk 4.95 gal/sk Page 22 Milne Point Unit R-107 SB Injector Drilling Procedure 13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. 13.16 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and diverter stack that may have come in contact with the cement. 13.17 Install slips and make initial cut on 13-3/8” casing as follows: x PU Riser and speed head x PU on casing with 100k over string weight and set slops per wellhead rep x Set speed head back down and disconnect from riser. x PU rider and make initial cut on 13-3/8” casing. Set riser back down on speed head and LD cut joint. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to frank.roach@hilcorp.com, brad.gorham@hilcorp.com, and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 23 Milne Point Unit R-107 SB Injector Drilling Procedure 14.0 N/U BOP and Test 14.1 N/D the diverter T, knife gate, and diverter line. Dress off 13-3/8” casing stub. N/U 13-5/8” x 13-5/8” 5M casing spool. 14.2 N/U 13-5/8” x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 3-1/2” x 5-1/2” VBRs or 5-1/2” solid body rams in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 3-1/2” x 5-1/2” VBRs x N/U bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve 14.3 Install BOP test plug 14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Test 3-1/2” x 5-1/2” rams with the 3-1/2” and 5-1/2” test joints x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.5 R/D BOP test equipment 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix LSND fluid for intermediate hole. Ensure LSND mud weight matches the weight at TD of surface hole. 14.8 Set wearbushing in wellhead. 14.9 Rack back as much 5-1/2” DP in derrick as possible to be used while drilling the hole section. 14.10 Ensure 6” or 6-1/4” liners in mud pumps. Page 24 Milne Point Unit R-107 SB Injector Drilling Procedure 15.0 Drill 12-1/4” Hole Section 15.1 M/U 12-1/4” Cleanout BHA (Milltooth Bit & 1.50° PDM) 15.2 TIH w/ 12-1/4” cleanout BHA to float equipment. Note depth TOC tagged on AM report. 15.3 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5020 / 2 = ~2510 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.4 Drill out shoe track and 20’ of new formation. 15.5 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 15.6 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as the casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 10.6 ppg FIT is the minimum required to drill ahead x 10.6 ppg provides >25 bbls based on 9.2 ppg MW, 8.46 ppg PP (swabbed kick at 9.2 ppg BHP) 15.7 POOH & LD Cleanout BHA 15.8 P/U 12-1/4” RSS directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is R/U and operational. MWD cannot be the same tool used in the 16” surface BHA (independent verification of data). x Ensure GWD is included in the BHA. Both gyro and HOC used cannot be the same tools used in the 16” surface BHA (independent verification of data). x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5-1/2” 21.9# S-135 Delta 544. x Run float in the intermediate hole section. Float can be ported or non-ported. 15.9 12-1/4” hole section mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. * Email casing test and FIT digital data to AOGCC upon completion of FIT. Page 25 Milne Point Unit R-107 SB Injector Drilling Procedure x Solids Concentration: Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions reasonably low. Utilize sweeps (weighted, high vis, tandem) to inform hole cleaning efficiency. Ensure 6 rpm is > 12 (~hole diameter) for sufficient hole cleaning x Run the centrifuge as needed while drilling the intermediate hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:8.9 – 9.8 ppg LSND drilling fluid Properties: Interval Density PV YP API FL Total Solids MBT Hardness Intermediate 8.9-9.8 5-20 - ALAP 15 - 30 <8 <10% <8 <200 15.10 TIH with 12-1/4” directional assembly to bottom 15.11 Displace wellbore to LSND drilling fluid 15.12 Begin drilling 12-1/4” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.13 Drill 12-1/4” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 700-950 gpm. Target 950 GPM. AV’s 194 ft/min, 950 gpm x RPM: 120-180. Target 150-180rpm x Utilize GWD surveys for entire 12-1/4” hole section x Efforts should be made to minimize dog legs in the intermediate hole. x Keep any directional work needed to maintain plan to DLS < 3 deg / 100. Any doglegs over 3 deg / 100 need to be addressed before drilling ahead. There is plenty of length in this hole section to get back on plan. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Page 26 Milne Point Unit R-107 SB Injector Drilling Procedure x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Screen down to 100’s before drilling Ugnu. Screen up as hole conditions allow to 170/200’s. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD/GWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across sands for any extended period of time. x When drilling through the Ugnu sections (UG4, UG4A, UG3, UG1), limit ROP to 150 fph. This is to handle the sand on the shaker screens at the high flow rate x Ensure ScreenKleen concentration is between 1.5% and 2.5% before drilling Ugnu sands. Have additional ScreenKleen available in shaker room to pressure wash and scrub shaker screens during connections. x Minimize the amount of water used on the screens. Clean with ScreenKleen instead. x Ensure mud is warm before drilling Ugnu. Use steam lines in pits if needed. x Watch for packoffs while drilling through UG2 and UG1 coals. These are the most problematic in the Ugnu formation. x Once below the Ugnu, limit maximum instantaneous ROP to < 200 fph. The formations will drill faster than this, but if a concretion is hit closer to TD when drilling this fast, cutter damage can occur. x Target ROP is as fast as we can clean the hole (under 200 fph) without having to backream connections x Note depths of the Ugnu coals for ghost reamer crossings and post-TD backreaming awareness x A/C: All wells have a clearance factor greater than 1.0 in the intermediate interval. 15.14 At TD, CBU (minimum 5-7X, more if needed) at max rate and rotation (120+ rpm). Pump tandem sweeps if needed x Rack back a stand at each bottoms up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary x Ensure lubricant concentration is at least 2.5% in and out before pulling off bottom. 15.15 BROOH with the drilling assembly to the 13-3/8” casing shoe. x Circulate at full drill rate unless losses are seen. x Rotate at maximum rpm that can be sustained. x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but adjust as hole conditions dictate. x Slow pulling speed when backreaming through coal depths seen when drilling. Page 27 Milne Point Unit R-107 SB Injector Drilling Procedure x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. x Monitor returns during the backream for increase in cuttings. Cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary. 15.16 CBU 13-3/8” shoe (minimum 4x) and clean casing with high vis sweeps. Be prepared for the hole to unload. This may take 4-6 BU before clean. Pump an EP Mud Lube pill to coat the surface casing before POOH. 15.17 Monitor well for flow. 15.18 POOH and LD BHA. Be prepared to pump out of the hole until entering vertical section. If needing to pump out, continue until BHA enters vertical section. CBU to clean casing once BHA is in the vertical section. This may take several BU volumes to achieve. 15.19 Change upper rams from 3-1/2” x 5-1/2” VBRs to 9-5/8” casing rams and test to 250 psi low, 3,000 psi high for 5/5 minutes with 9-5/8” test joint. Page 28 Milne Point Unit R-107 SB Injector Drilling Procedure 16.0 Run 9-5/8” Intermediate Casing 16.1 R/U Parker Wellbore 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” BTC x Delta 544 XO on rig floor and M/U to FOSV. x Use API Modified thread compound. Dope pin end only w/ paint brush. x R/U CRT and ensure torque rings are installed prior to running casing. x Fill casing on the fly through CRT x Discuss circulation strategy with drilling engineer prior to running casing. x Ensure all casing has been drifted to 8-1/2” on the location prior to running. x Note that 40# drift is 8.679” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2 P/U shoe joint, visually verify no debris inside joint. 16.3 Continue M/U & thread locking 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” BTC, 2 Centralizers 10’ from each end w/ stop rings 1 joint –9-5/8” BTC, 1 Centralizer mid joint w/ stop ring 1 joint – 9-5/8” BTC, 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar 1 joint – 9-5/8” BTC, 1 Centralizer mid joint with stop ring 16.4 Continue running 9-5/8” surface casing x Fill casing on the fly, through the CRT. x Use API Modified thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer (locked mid-joint) every joint to ~ 3,000’ MD from 9-5/8” shoe x 1 centralizer (locked mid-joint) every 2 joints to ~100’ MD below 13-3/8” shoe x Utilize a collar clamp until weight is sufficient to keep slips set properly. 9-5/8” 40# L-80 BTC Make-Up Torques with Torque Rings Casing OD Minimum Maximum 9-5/8”20,000 ft-lbs 29,990 ft-lbs Page 29 Milne Point Unit R-107 SB Injector Drilling Procedure Page 30 Milne Point Unit R-107 SB Injector Drilling Procedure 16.5 CBU at 13-3/8” shoe, prior to entering open hole. 16.6 Continue to RIH with 9-5/8” intermediate casing to TD. Break circulation every 10 joints and wash down. Take special care when staging pumps up and down to avoid surging and breaking down the formation. If hookloads indicate excess drag or dirty hole, increase circulation frequency to every 5 joints. 16.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.8 Slow in and out of slips. 16.9 P/U landing joint/hanger assembly and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 16.10 Lower casing and land hanger to confirm depth. Confirm measurements. 16.11 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 31 Milne Point Unit R-107 SB Injector Drilling Procedure 17.0 Cement 9-5/8” Intermediate Casing 17.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x How to handle unlikely cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap pit levels during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 17.2 Document efficiency of all possible displacement pumps prior to cement job. 17.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 17.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and all bottom plugs to ensure done in correct order. 17.5 Fill surface cement lines with water and pressure test. 17.6 Drop first bottom plug – HEC rep to witness. Pump spacer. 17.7 Drop second bottom plug – HEC rep to witness. Mix and pump lead cement per below calculations. Confirm actual cement volumes with cementer after TD is reached. 17.8 Drop third bottom plug – HEC rep to witness. Mix and pump tail cement per below calculations. Confirm actual cement volumes with cementer after TD is reached. a. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead and tail cement, TOC brought to ~6,600’ MD, 2,916’ TVD. Depth chosen provides 250’ TVD coverage above deepest freshwater intervals (<10,000 mg/L TDS), determined from MPU R-103 log data. That data shows deepest freshwater intervals~200’ TVD above LA3 top. Depths and volumes to be confirmed with as-drilled log data. x NOTE: If AEO-2A is approved before the cement job is performed, cement volumes will be adjusted to ensure cement 250’ TVD above top of pool. Page 32 Milne Point Unit R-107 SB Injector Drilling Procedure Estimated Total Cement Volume: Cement Slurry Design: 17.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, If the hole gets “sticky”, cease pipe reciprocation, land hanger on profile, and continue with the cement job. 17.10 After pumping cement, drop top plug and displace cement with spud mud out of mud pits. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 17.11 Ensure rig pump is used to displace cement. 17.12 Displacement calculation is in the Table in step 17.8. 17.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 17.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 17.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. Lead Slurry Tail Slurry System VersaCem SwiftCem Density 14.0 lb/gal 15.3 lb/gal Yield 1.519 ft3/sk 1.237 ft3/sk Mix Water 7.696 gal/sk 5.562 gal/sk Page 33 Milne Point Unit R-107 SB Injector Drilling Procedure 17.16 While unlikely, be prepared for cement returns to surface. Dump cement returns through the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may come in contact with cement returns. 17.17 Back off and LD landing joint. Install packoff and test per wellhead tech. 17.18 Freeze protect 13-3/8” x 9-5/8” casing annulus to ~2,700’ MD with dead crude or diesel after cement tests indicate cement has reached 500 psi compressive strength. x Freeze protect with ~162 bbls of dead crude/diesel x Establish breakdown pressure and inject 5 bbls past breakdown to confirm annulus is clear x Ensure total injection volume injected down the annulus (including mud used to keep annulus open) doesn’t exceed 110% of the 13-3/8” x 9-5/8” annular volume. 17.19 Change upper rams from 9-5/8” casing rams to 3-1/2” x 5-1/2” VBRs and test to 250 psi low, 3,000 psi high with 3-1/2” and 5-1/2” test joints. 17.20 Once cement is in place long enough to start building compressive strength, MU 8-1/2” Cleanout BHA. RIH and tag plugs. Circulate and condition mud. POOH & LD BHA. 17.21 RU e-line and RIH w/CBL on tractor. Log 9-5/8” casing from plugs up to confirm TOC for both freshwater protection and 250’ TVD above top of pool (injector isolation). POOH and LD logging tools. RD e-line. x NOTE: If AEO-2A is approved before CBL is performed, log will be run to confirm cement 250’ TVD above top of pool for injector isolation. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to frank.roach@hilcorp.com, brad.gorham@hilcorp.com, and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 34 Milne Point Unit R-107 SB Injector Drilling Procedure 18.0 Drill 8-1/2” Hole Section 18.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.50° PDM) 18.2 TIH to TOC above the float collar. Note depth TOC tagged on morning report. 18.3 R/U and test casing to 3000 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 18.4 Drill out shoe track and 20’ of new formation. 18.5 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to clean up debris. 18.6 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 10.2 ppg FIT is the minimum required to drill ahead x 10.2 ppg provides >25 bbls based on 9.2ppg MW, 8.46ppg PP (swabbed kick at 9.2ppg BHP) 18.7 POOH & LD Cleanout BHA 18.8 P/U 8-1/2” RSS directional BHA. x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Ensure MWD is R/U and operational. x Ensure GWD is included in the BHA x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5-1/2” 21.9# S-135 Delta 544. x Run two non-ported floats in the production hole section. Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 * Email casing test and FIT digital data to AOGCC upon completion of FIT. Page 35 Milne Point Unit R-107 SB Injector Drilling Procedure 18.9 8-1/2” hole section mud program summary: x Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, & Toolpusher office. System Type:8.9 – 9.5 ppg FloPro drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPHT Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 Page 36 Milne Point Unit R-107 SB Injector Drilling Procedure System Formulation: Product- production Size Pkg ppb or (% liquids) Busan 1060 55 gal dm 0.095 FLOTROL 55 lb sx 6 CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2 FLO-VIS PLUS 25 lb sx 0.7 KCl 50 lb sx 10.7 SMB 50 lb sx 0.45 LOTORQ 55 gal dm 1.0 SAFE-CARB 10 (verify)50 lb sx 10 SAFE-CARB 20 (verify)50 lb sx 10 Soda Ash 50 lb sx 0.5 18.10 TIH with 8-1/2” directional assembly to bottom 18.11 Install MPD RCD 18.12 Displace wellbore to 8.9 ppg FloPro drilling fluid 18.13 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 18.15 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 gpm, target min. AV’s 200 ft/min, 385 gpm x RPM: 120+ x Utilize GWD surveys for entire 8-1/2” hole section x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Surveys can be taken more frequently if deemed necessary. x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Use ADR to stay in section. Page 37 Milne Point Unit R-107 SB Injector Drilling Procedure x Limit maximum instantaneous ROP to < 200 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter and/or tool damage can occur. x Target ROP is as fast as we can clean the hole (under 200 fph) without having to backream connections x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up on connections x Schrader Bluff OA Concretions: 4-6% Historically x AC: All wells have a clearance factor greater than 1.0 in the surface interval. 18.16 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. x Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up. x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 18.17 At TD, CBU (minimum 5-7X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed x Rack back a stand at each bottoms-up and reciprocate a full stand in between (while circulating the BU). Keep the pipe moving while pumping. x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a consistent stream so circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 18.18 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. Page 38 Milne Point Unit R-107 SB Injector Drilling Procedure 18.19 Displace 1.5 OH + Liner volume with viscosified brine. x Proposed brine blend (aiming for an 8 on the 6 RPM reading) - KCl: 7.1bbp for 2% NaCl: 60.9 ppg for 9.4 ppg Lotorq: 1.5% Lube 776: 1.5% Soda Ash: as needed for 9.5pH Busan 1060: 0.42 ppb Flo-Vis Plus: 1.25 ppb x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further discussion needed prior to BROOH. 18.20 BROOH with the drilling assembly to the 9-5/8” casing shoe. Note: PST test is NOT required. x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses) x Rotate at maximum rpm that can be sustained. x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but adjust as hole conditions dictate. x When pulling across any OHST depths, turn pumps off and rotary off to minimize disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct hole section, check with ABI compared to as drilled surveys 18.21 CBU minimum 3 times at 9-5/8” shoe and clean casing with high vis sweeps. Once clean, pump EP Mud Lube pill with spacers ahead and behind. Dump spacers and pill when returned to surface. 18.22 Monitor well for flow. Increase mud weight if necessary x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure seen 18.23 Pull RCD Bearing and install trip nipple. 18.24 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Page 39 Milne Point Unit R-107 SB Injector Drilling Procedure 19.0 Run 5-1/2” x 4-1/2” Injection Liner (Lower Completion) 19.1 Well control preparedness: In the event of an influx of formation fluids while running the injection liner with slotted liner, the following well control response procedure will be followed: x With 4-1/2” joint across BOP: P/U & M/U the 4-1/2” safety joint (with 4-1/2” crossover installed on bottom, FOSV valve in open position on top, 4-1/2” handling joint above FOSV). This joint shall be fully M/U and available prior to running the first joint of 4-1/2” liner. x With a 5-1/2” joint across the BOP: P/U & M/U the 5-1/2” safety joint (with 5-1/2” crossover installed on bottom, FOSV valve in open position on top, 5-1/2” handling joint above FOSV). This joint shall be fully M/U and available prior to running the first joint of 5-1/2” liner. 19.2 Confirm VBR’s have been tested to cover 3-1/2” and 5-1/2” pipe sizes to 250 psi low/3000 psi high. 19.3 R/U 4-1/2” liner running equipment. x Ensure 5-1/2” JFE Bear and 4-1/2” Hydril 625 x Delta 544 crossovers are on rig floor and M/U to FOSV. x Ensure the liner has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 19.4 Run 5-1/2” x 4-1/2” injection liner. x Injection liner will be a combination of slotted and solid joints. Every third joint in the open hole is to be a slotted joint. Confirm with OE. x Uppermost 3,500’ will be 5-1/2”. x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the slots. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Use lift nubbins and stabbing guides for the liner run. x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each jt outside of the surface shoe. This is to mitigate sticking risk while running inner string. x Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm Page 40 Milne Point Unit R-107 SB Injector Drilling Procedure 4-1/2” 13.5# L-80 H625 Casing OD Minimum Optimum Maximum Operating Torque 4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs Page 41 Milne Point Unit R-107 SB Injector Drilling Procedure 5-1/2” 17# L-80 JFE Bear Casing OD Minimum Optimum Maximum Operating Torque 5.5” 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs Page 42 Milne Point Unit R-107 SB Injector Drilling Procedure 19.5 Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe. x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection. 19.6 Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 19.7 M/U Baker SLZXP liner top packer to 4-1/2” x 5-1/2” liner. 19.8 Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 19.9 RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 5-1/2” DP/HWDP has been drifted x The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 19.10 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 19.11 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 19.12 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 19.13 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 19.14 Rig up to pump down the work string with the rig pumps. 19.15 Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker 19.16 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 19.17 Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do not allow ball to slam into ball seat. Page 43 Milne Point Unit R-107 SB Injector Drilling Procedure 19.18 Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 19.19 Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 19.20 PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 19.21 Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 19.22 PU pulling running tool free of the packer and displace at max rate to wash the liner top. Pump sweeps as needed. 19.23 POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 44 Milne Point Unit R-107 SB Injector Drilling Procedure 20.0 Run 3-1/2” Tubing (Upper Completion) 20.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the completion as per 20 AAC 25.412 (e). 20.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min. x Ensure wear bushing is pulled. x Ensure 3-½” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. x Monitor displacement from wellbore while RIH. 3-1/2” 9.3# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs 3-½” Upper Completion Running Order x 3-½” Baker Ported seal with ratcheting mule shoe (stung into the tie back receptacle) x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” “XN” nipple at TBD x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” SGM-FS XDPG Gauge at TBD x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” Sliding Sleeve at TBD x 3-½” 9.3#/ft, L-80 EUE 8RD tubing x 3-½” “X” nipple at ~2,500’ (below base permafrost) x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing x Tubing hanger with 3-1/2” EUE 8RD pin down Page 45 Milne Point Unit R-107 SB Injector Drilling Procedure 20.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals engaged. 20.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all space out pups below the first full joint of the completion. 20.5 MU tubing hanger and landing joint. 20.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down to 250 psi. PU until ports in seal assembly exposed. 20.7 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel. i. Contact Wellsite Supervisor or Wells Foreman to confirm if freeze protect is needed. 20.8 Land hanger. RILDS and test hanger. 20.9 Continue pressuring up and test the annulus to 3,500 psi and test for 30 charted minutes. i. Note this test must be witnessed by the AOGCC representative. ii. Complete form 10-426 and submit to the required recipients. Copy frank.roach@hilcorp.com,brad.gorham@hilcorp.com, and twellman@hilcorp.com on the e-mail. 20.10 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 20.11 Pull BPV. Set TWC. Test tree to 5000 psi. 20.12 Pull TWC. Set BPV. Bullhead tubing freeze protect. 20.13 Secure the tree and cellar. 21.0 RDMO 21.1 RDMO Parker 273 Page 46 Milne Point Unit R-107 SB Injector Drilling Procedure 22.0 Post-Rig Work Operations-Convert well on surface with hard line to a jet pump producer. 22.1 MU surface lines from power fluid header to the tubing. x Pressure test lines at existing power fluid header pressure (3,500 psi) 22.2 Rig up hardline to the production header and test header. Pressure test to 3,500 psi. 22.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi. i. Contingency (if SL is unable to reach depth via pump down): Use RU coil tubing and pressure test to 250psi low / 3,000psi high. Use coil tubing to perform same runs as outlined below. 22.4 Shift Sliding sleeve open 22.5 Set 12B jet pump 22.6 RDMO SL/FB- After 30 days of production 22.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi. 22.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2,000’ on IA i. Contingency (if SL was unsuccessful in reaching depth): Use RU coil tubing and pressure test to 250psi low / 3,000psi high. Use coil tubing to perform same runs as outlined below. 22.9 Pull Jet Pump 22.10 Shift sliding sleeve closed 22.11 MIT-IA test to 2,000 psi 22.12 POI 22.13 After 5 days of stabilized injection MIT-IA to 2,000 psi (Charted and state witnessed) * 24/7 man watch during 30 day pre-production period unless 10-403 submitted describing trips and piping for un- manned pre-production. Page 47 Milne Point Unit R-107 SB Injector Drilling Procedure 23.0 Parker 273 Diverter Schematic Page 48 Milne Point Unit R-107 SB InjectorDrilling Procedure24.0 Parker 273 BOP Schematic Page 49 Milne Point Unit R-107 SB Injector Drilling Procedure 25.0 Wellhead Schematic Page 50 Milne Point Unit R-107 SB Injector Drilling Procedure 26.0 Days vs Depth Page 51 Milne Point Unit R-107 SB Injector Drilling Procedure 27.0 Formation Tops & Information TOP NAME TVD (FT) TVDSS (FT) MD (FT) Formation Pressure (psi) EMW (ppg) SV5 1,394 1,330 1,497 613 8.46 Base Permafrost 1,874 1,810 2,587 824 8.46 SV1 2,070 2,006 3,358 911 8.46 LA3 3,366 3,302 8,453 1481 8.46 UG_MB 3,812 3,748 10,207 1677 8.46 SB_Na 3,854 3,790 10,372 1695 8.46 SB_Oa 3,968 3,904 10,999 1746 8.46 Page 52 Milne Point Unit R-107 SB Injector Drilling Procedure L-Pad and F-Pad Data Sheets Formation Descriptions (Closest & Most Analogous MPU Pads to Moose Pad) Page 53 Milne Point Unit R-107 SB Injector Drilling Procedure Page 54 Milne Point Unit R-107 SB Injector Drilling Procedure 28.0 Anticipated Drilling Hazards 16” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Raven pad. However, be prepared for them. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of wells in close proximity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well specific A/C: x There are no wells with a CF < 1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 55 Milne Point Unit R-107 SB Injector Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 56 Milne Point Unit R-107 SB Injector Drilling Procedure 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Gas hyrates have not been seen on Raven pad. However, be prepared for them. While the likely depths for hydrates are in the surface interval, remain vigilant. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals if motor is used. Do not out drill our ability to clean the hole. Anti-Collison: There are wells in close proximity and deviation from plan could have a trickle-down effect on the pattern for subsequent wells. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well specific A/C: x There are no wells with a CF < 1.0 Wellbore stability (running sands, Ungu coals and hard streaks): Ugnu Coals in the UG3 and UG2 have proven challenging in the first Raven Pad wells. High TOH and RIH speeds, coupled with the high sail angle, can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Ensure ghost reamer is in the drillstring and located where it will have wiped the trouble coals prior to reaching TD. Maintain mud parameters and increase MW to combat running sand formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 57 Milne Point Unit R-107 SB Injector Drilling Procedure 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 58 Milne Point Unit R-107 SB Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is one mapped fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on R- Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well specific AC: x There are no wells with a CF < 1.0 Page 59 Milne Point Unit R-107 SB InjectorDrilling Procedure29.0 Parker 273 Layout Page 60 Milne Point Unit R-107 SB Injector Drilling Procedure 30.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 61 Milne Point Unit R-107 SB Injector Drilling Procedure 31.0 Parker 273 Choke Manifold Schematic Page 62 Milne Point Unit R-107 SB Injector Drilling Procedure 32.0 Casing Design Page 63 Milne Point Unit R-107 SB Injector Drilling Procedure 33.0 12-1/4” Hole Section MASP Page 64 Milne Point Unit R-107 SB Injector Drilling Procedure 34.0 8-1/2” Hole Section MASP Page 65 Milne Point Unit R-107 SB Injector Drilling Procedure 35.0 Spider Plot (NAD 27) (Governmental Sections) Page 66 Milne Point Unit R-107 SB Injector Drilling Procedure 36.0 Surface Plat (As-Staked) (NAD 27) Standard Proposal Report 25 April, 2025 Plan: MPU R-107 wp02 Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Plan: MPU R-107 MPU R-107 -125001250250037505000True Vertical Depth (2500 usft/in)-1250 0 1250 2500 3750 5000 6250 7500 8750 10000 11250 12500 13750 15000 16250 17500 18750 20000 21250 22500Vertical Section at 305.90° (2500 usft/in)MPR-107 wp02 tgt7MPR-107 wp02 tgt21MPR-107 wp02 tgt1MPR-107 wp02 tgt9MPR-107 wp02 tgt19MPR-107 wp02 tgt11MPR-107 wp02 tgt13MPR-107 wp02 tgt5MPR-107 wp02 tgt3MPR-107 wp02 tgt17MPR-107 wp02 tgt1513 3/8" x 16"9 5/8" x 12 1/4"4 1/2" x 8 1/2"50010001500200025003000350040004500500055006000650070007500800085009000950010000105001100011 500 12000 12500 13 0001350014000 14500 15 00 0 1550016000165001700017500 18000185001900019500200002050021000215002200022500230002350023682MPU R-107 wp02Start Dir 3º/100' : 325' MD, 325'TVDStart Dir 4º/100' : 575' MD, 574.29'TVDEnd Dir : 2305.86' MD, 1802.46' TVDStart Dir 4º/100' : 10595.74' MD, 3910.92'TVDEnd Dir : 10856.55' MD, 3955.58' TVDBegin GeosteeringTotal Depth : 23682.14' MD, 4013.65' TVDSV5Base PermafrostSV1LA3UG_MBSB_NaSB_OaHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU R-10716.70+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.006033308.92540396.97 70° 30' 6.9817 N 149° 40' 10.4773 WSURVEY PROGRAMDate: 2024-03-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool46.95 4121.00 MPU R-107 wp02 (MPU R-107) GYD_Quest GWD7121.00 11007.00 MPU R-107 wp02 (MPU R-107) GYD_Quest GWD11007.00 23682.14 MPU R-107 wp02 (MPU R-107) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1393.65 1330.00 1496.33 SV51873.65 1810.00 2585.77 Base Permafrost2069.65 2006.00 3356.38 SV13365.65 3302.00 8451.89 LA33811.65 3748.00 10205.44 UG_MB3853.65 3790.00 10370.57 SB_Na3967.65 3904.00 10995.08 SB_OaREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-107, True NorthVertical (TVD) Reference:R-107 as built RKB @ 63.65usftMeasured Depth Reference:R-107 as built RKB @ 63.65usftCalculation Method: Minimum CurvatureProject:Milne PointSite:M Pt Raven PadWell:Plan: MPU R-107Wellbore:MPU R-107Design:MPU R-107 wp02CASING DETAILSTVD TVDSS MD SizeName2264.12 2200.47 4121.00 13-3/8 13 3/8" x 16"3968.69 3905.04 11007.00 9-5/8 9 5/8" x 12 1/4"4013.65 3950.00 23682.14 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 46.95 0.00 0.00 46.95 0.00 0.00 0.00 0.00 0.002 325.00 0.00 0.00 325.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 325' MD, 325'TVD3 575.00 7.50 325.00 574.29 13.38 -9.37 3.00 325.00 15.44 Start Dir 4º/100' : 575' MD, 574.29'TVD4 800.00 16.44 330.51 794.18 53.20 -33.52 4.00 10.00 58.355 2305.86 75.27 307.83 1802.46 750.74 -783.93 4.00 -25.44 1075.23 End Dir : 2305.86' MD, 1802.46' TVD6 10595.74 75.27 307.83 3910.92 5668.18 -7116.02 0.00 0.00 9087.94 Start Dir 4º/100' : 10595.74' MD, 3910.92'TVD7 10856.55 85.00 304.02 3955.58 5818.63 -7323.87 4.00 -21.46 9344.53 End Dir : 10856.55' MD, 3955.58' TVD8 11006.55 85.00 304.02 3968.65 5902.23 -7447.73 0.00 0.00 9493.88 MPR-107 wp02 tgt1 Begin Geosteering9 11016.38 85.22 304.13 3969.49 5907.72 -7455.84 2.50 27.53 9503.6710 11140.97 85.22 304.13 3979.88 5977.39 -7558.61 0.00 0.00 9627.7711 11343.91 90.29 304.02 3987.83 6090.97 -7726.52 2.50 -1.29 9830.3812 12168.91 90.29 304.02 3983.65 6552.54 -8410.30 0.00 0.00 10654.93 MPR-107 wp02 tgt313 12295.80 93.46 303.97 3979.50 6623.43 -8515.43 2.50 -0.93 10781.6614 12441.66 93.46 303.97 3970.69 6704.78 -8636.18 0.00 0.00 10927.1715 12555.80 90.61 304.07 3966.63 6768.60 -8730.72 2.50 177.96 11041.1716 13305.80 90.61 304.07 3958.65 7188.73 -9351.95 0.00 0.00 11790.74 MPR-107 wp02 tgt517 13514.59 85.39 303.97 3965.93 7305.43 -9524.84 2.50 -178.88 11999.2218 13803.74 85.39 303.97 3989.17 7466.46 -9763.87 0.00 0.00 12287.2719 14010.56 90.56 304.10 3996.47 7582.10 -9935.10 2.50 1.47 12493.7820 14810.56 90.56 304.10 3988.65 8030.59 -10597.51 0.00 0.00 13293.35 MPR-107 wp02 tgt721 14931.20 93.58 304.05 3984.30 8098.13 -10697.36 2.50 -0.94 13413.8322 15030.39 93.58 304.05 3978.11 8153.57 -10779.39 0.00 0.00 13512.7823 15173.43 90.00 304.00 3973.65 8233.55 -10897.86 2.50 -179.19 13655.6524 15973.43 90.00 304.00 3973.65 8680.90 -11561.09 0.00 0.00 14455.21 MPR-107 wp02 tgt925 16135.00 85.96 304.14 3979.34 8771.35 -11694.82 2.50 177.98 14616.5726 16257.49 85.96 304.14 3987.96 8839.92 -11795.94 0.00 0.00 14738.6927 16419.00 90.00 304.06 3993.65 8930.40 -11929.57 2.50 -1.17 14899.9928 16744.00 90.00 304.06 3993.65 9112.42 -12198.81 0.00 0.00 15224.82 MPR-107 wp02 tgt1129 16898.18 86.15 303.88 3998.83 9198.50 -12326.59 2.50 -177.30 15378.8030 17147.02 86.15 303.88 4015.54 9336.90 -12532.71 0.00 0.00 15626.9231 17337.11 90.90 304.02 4020.43 9442.99 -12690.31 2.50 1.71 15816.7932 18087.11 90.90 304.02 4008.65 9862.55 -13311.86 0.00 0.00 16566.29 MPR-107 wp02 tgt1333 18188.26 93.43 303.95 4004.83 9919.05 -13395.66 2.50 -1.59 16667.3034 18292.43 93.43 303.95 3998.60 9977.12 -13481.92 0.00 0.00 16771.2235 18440.42 89.73 304.08 3994.53 10059.86 -13604.52 2.50 177.98 16919.0636 19315.42 89.73 304.08 3998.65 10550.16 -14329.24 0.00 0.00 17793.61 MPR-107 wp02 tgt1537 19480.04 85.63 303.78 4005.32 10641.95 -14465.68 2.50 -175.84 17957.9538 19603.23 85.63 303.78 4014.72 10710.25 -14567.77 0.00 0.00 18080.7039 19757.94 89.49 303.94 4021.31 10796.36 -14696.10 2.50 2.36 18235.1440 20582.94 89.49 303.94 4028.65 11256.96 -15380.52 0.00 0.00 19059.63 MPR-107 wp02 tgt1741 20744.83 93.53 304.11 4024.38 11347.49 -15514.61 2.50 2.43 19221.3442 20848.18 93.53 304.11 4018.01 11405.34 -15600.02 0.00 0.00 19324.4543 20989.62 90.00 303.98 4013.65 11484.48 -15717.14 2.50 -177.86 19465.7244 21989.62 90.00 303.98 4013.65 12043.38 -16546.37 0.00 0.00 20465.16 MPR-107 wp02 tgt1945 22113.97 86.90 304.19 4017.02 12113.04 -16649.32 2.50 176.17 20589.3946 22301.81 86.90 304.19 4027.18 12218.43 -16804.46 0.00 0.00 20776.8747 22457.14 90.78 304.09 4030.33 12305.56 -16932.97 2.50 -1.44 20932.0648 23682.14 90.78 304.09 4013.65 12992.11 -17947.37 0.00 0.00 22156.33 MPR-107 wp02 tgt21 Total Depth : 23682.14' MD, 4013.65' TVD 010002000300040005000600070008000900010000110001200013000South(-)/North(+) (2000 usft/in)-18000 -17000 -16000 -15000 -14000 -13000 -12000 -11000 -10000 -9000 -8000 -7000 -6000 -5000 -4000 -3000 -2000 -1000 0West(-)/East(+) (2000 usft/in)MPR-107 wp02 tgt15MPR-107 wp02 tgt17MPR-107 wp02 tgt3MPR-107 wp02 tgt5MPR-107 wp02 tgt13MPR-107 wp02 tgt11MPR-107 wp02 tgt19MPR-107 wp02 tgt9MPR-107 wp02 tgt1MPR-107 wp02 tgt21MPR-107 wp02 tgt713 3/8" x 16"9 5/8" x 12 1/4"4 1/2" x 8 1/2"25050075010001250150017502000225025002750300032503500375040004014MPU R-107 wp02Start Dir 3º/100' : 325' MD, 325'TVDStart Dir 4º/100' : 575' MD, 574.29'TVDEnd Dir : 2305.86' MD, 1802.46' TVDStart Dir 4º/100' : 10595.74' MD, 3910.92'TVDEnd Dir : 10856.55' MD, 3955.58' TVDBegin GeosteeringTotal Depth : 23682.14' MD, 4013.65' TVDCASING DETAILSTVDTVDSS MDSize Name2264.12 2200.47 4121.00 13-3/8 13 3/8" x 16"3968.69 3905.04 11007.00 9-5/8 9 5/8" x 12 1/4"4013.65 3950.00 23682.14 4-1/2 4 1/2" x 8 1/2"Project: Milne PointSite: M Pt Raven PadWell: Plan: MPU R-107Wellbore: MPU R-107Plan: MPU R-107 wp02WELL DETAILS: Plan: MPU R-10716.70+N/-S +E/-W Northing EastingLatittudeLongitude0.00 0.006033308.92540396.97 70° 30' 6.9817 N149° 40' 10.4773 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-107, True NorthVertical (TVD) Reference:R-107 as built RKB @ 63.65usftMeasured Depth Reference:R-107 as built RKB @ 63.65usftCalculation Method:Minimum Curvature Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Milne Point, ACT, MILNE POINT Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Site Position: From: Site Latitude: Longitude: Position Uncertainty: Northing: Easting: Grid Convergence: M Pt Raven Pad usft Map usft usft °0.31Slot Radius:"13-3/16 6,033,201.00 540,134.00 5.00 70° 30' 5.9343 N 149° 40' 18.2376 W Well Well Position Longitude: Latitude: Easting: Northing: usft +E/-W +N/-S Position Uncertainty usft usft usftGround Level: Plan: MPU R-107 usft usft 0.00 0.00 6,033,308.92 540,396.97 16.70Wellhead Elevation:usft0.50 70° 30' 6.9817 N 149° 40' 10.4773 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU R-107 Model NameMagnetics BGGM2024 3/26/2024 14.32 80.78 57,253.84461473 Phase:Version: Audit Notes: Design MPU R-107 wp02 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:46.95 305.900.000.0046.95 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True Inclination (°) Azimuth (°) +E/-W (usft) Tool Face (°) +N/-S (usft) Measured Depth (usft) Vertical Depth (usft) Dogleg Rate (°/100usft) Build Rate (°/100usft) Turn Rate (°/100usft) Plan Sections TVD System usft 0.000.000.000.000.000.0046.950.000.0046.95 -16.70 0.000.000.000.000.000.00325.000.000.00325.00 261.35 325.000.003.003.00-9.3713.38574.29325.007.50575.00 510.64 10.002.453.974.00-33.5253.20794.18330.5116.44800.00 730.53 -25.44-1.513.914.00-783.93750.741,802.46307.8375.272,305.86 1,738.81 0.000.000.000.00-7,116.025,668.183,910.92307.8375.2710,595.74 3,847.27 -21.46-1.463.734.00-7,323.875,818.633,955.58304.0285.0010,856.55 3,891.93 0.000.000.000.00-7,447.735,902.233,968.65304.0285.0011,006.55 3,905.00 27.531.162.222.50-7,455.845,907.723,969.49304.1385.2211,016.38 3,905.84 0.000.000.000.00-7,558.615,977.393,979.88304.1385.2211,140.97 3,916.23 -1.29-0.062.502.50-7,726.526,090.973,987.83304.0290.2911,343.91 3,924.18 0.000.000.000.00-8,410.306,552.543,983.65304.0290.2912,168.91 3,920.00 -0.93-0.042.502.50-8,515.436,623.433,979.50303.9793.4612,295.80 3,915.85 0.000.000.000.00-8,636.186,704.783,970.69303.9793.4612,441.66 3,907.04 177.960.09-2.502.50-8,730.726,768.603,966.63304.0790.6112,555.80 3,902.98 0.000.000.000.00-9,351.957,188.733,958.65304.0790.6113,305.80 3,895.00 -178.88-0.05-2.502.50-9,524.847,305.433,965.93303.9785.3913,514.59 3,902.28 0.000.000.000.00-9,763.877,466.463,989.17303.9785.3913,803.74 3,925.52 1.470.062.502.50-9,935.107,582.103,996.47304.1090.5614,010.56 3,932.82 0.000.000.000.00-10,597.518,030.593,988.65304.1090.5614,810.56 3,925.00 -0.94-0.042.502.50-10,697.368,098.133,984.30304.0593.5814,931.20 3,920.65 0.000.000.000.00-10,779.398,153.573,978.11304.0593.5815,030.39 3,914.46 -179.19-0.04-2.502.50-10,897.868,233.553,973.65304.0090.0015,173.43 3,910.00 0.000.000.000.00-11,561.098,680.903,973.65304.0090.0015,973.43 3,910.00 177.980.09-2.502.50-11,694.828,771.353,979.34304.1485.9616,135.00 3,915.69 0.000.000.000.00-11,795.948,839.923,987.96304.1485.9616,257.49 3,924.31 -1.17-0.052.502.50-11,929.578,930.403,993.65304.0690.0016,419.00 3,930.00 0.000.000.000.00-12,198.819,112.423,993.65304.0690.0016,744.00 3,930.00 -177.30-0.12-2.502.50-12,326.599,198.503,998.83303.8886.1516,898.18 3,935.18 0.000.000.000.00-12,532.719,336.904,015.54303.8886.1517,147.02 3,951.89 1.710.072.502.50-12,690.319,442.994,020.43304.0290.9017,337.11 3,956.78 0.000.000.000.00-13,311.869,862.554,008.65304.0290.9018,087.11 3,945.00 -1.59-0.072.502.50-13,395.669,919.054,004.83303.9593.4318,188.26 3,941.18 0.000.000.000.00-13,481.929,977.123,998.60303.9593.4318,292.43 3,934.95 177.980.09-2.502.50-13,604.5210,059.863,994.53304.0889.7318,440.42 3,930.88 0.000.000.000.00-14,329.2410,550.163,998.65304.0889.7319,315.42 3,935.00 -175.84-0.18-2.492.50-14,465.6810,641.954,005.32303.7885.6319,480.04 3,941.67 0.000.000.000.00-14,567.7710,710.254,014.72303.7885.6319,603.23 3,951.07 2.360.102.502.50-14,696.1010,796.364,021.31303.9489.4919,757.94 3,957.66 0.000.000.000.00-15,380.5211,256.964,028.65303.9489.4920,582.94 3,965.00 2.430.112.502.50-15,514.6111,347.494,024.38304.1193.5320,744.83 3,960.73 0.000.000.000.00-15,600.0211,405.344,018.01304.1193.5320,848.18 3,954.36 -177.86-0.09-2.502.50-15,717.1411,484.484,013.65303.9890.0020,989.62 3,950.00 0.000.000.000.00-16,546.3712,043.384,013.65303.9890.0021,989.62 3,950.00 176.170.17-2.492.50-16,649.3212,113.044,017.02304.1986.9022,113.97 3,953.37 0.000.000.000.00-16,804.4612,218.434,027.18304.1986.9022,301.81 3,963.53 -1.44-0.062.502.50-16,932.9712,305.564,030.33304.0990.7822,457.14 3,966.68 0.000.000.000.00-17,947.3712,992.114,013.65304.0990.7823,682.14 3,950.00 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS -16.70 Vert Section 46.95 0.00 46.95 0.00 0.000.00 540,396.976,033,308.92-16.70 0.00 0.00 100.00 0.00 100.00 0.00 0.000.00 540,396.976,033,308.9236.35 0.00 0.00 200.00 0.00 200.00 0.00 0.000.00 540,396.976,033,308.92136.35 0.00 0.00 300.00 0.00 300.00 0.00 0.000.00 540,396.976,033,308.92236.35 0.00 0.00 325.00 0.00 325.00 0.00 0.000.00 540,396.976,033,308.92261.35 0.00 0.00 Start Dir 3º/100' : 325' MD, 325'TVD 400.00 2.25 399.98 1.21 -0.84325.00 540,396.126,033,310.12336.33 3.00 1.39 500.00 5.25 499.76 6.56 -4.60325.00 540,392.346,033,315.46436.11 3.00 7.57 575.00 7.50 574.29 13.38 -9.37325.00 540,387.536,033,322.25510.64 3.00 15.44 Start Dir 4º/100' : 575' MD, 574.29'TVD 600.00 8.49 599.04 16.25 -11.33326.18 540,385.556,033,325.11535.39 4.00 18.71 700.00 12.45 697.36 31.63 -21.00329.02 540,375.806,033,340.44633.71 4.00 35.56 800.00 16.44 794.18 53.20 -33.52330.51 540,363.176,033,361.94730.53 4.00 58.35 900.00 20.12 889.12 79.71 -50.23325.51 540,346.326,033,388.34825.47 4.00 87.42 1,000.00 23.90 981.82 109.87 -72.44322.03 540,323.946,033,418.38918.17 4.00 123.10 1,100.00 27.74 1,071.82 143.54 -100.05319.45 540,296.156,033,451.901,008.17 4.00 165.21 1,200.00 31.62 1,158.68 180.55 -132.92317.46 540,263.086,033,488.731,095.03 4.00 213.54 1,300.00 35.52 1,241.99 220.73 -170.89315.86 540,224.906,033,528.701,178.34 4.00 267.86 1,400.00 39.44 1,321.33 263.88 -213.77314.55 540,181.786,033,571.611,257.68 4.00 327.90 1,496.33 43.23 1,393.65 308.06 -259.54313.47 540,135.786,033,615.531,330.00 4.00 390.88 SV5 1,500.00 43.37 1,396.32 309.79 -261.37313.43 540,133.956,033,617.251,332.67 4.00 393.37 1,600.00 47.31 1,466.59 358.23 -313.43312.47 540,081.636,033,665.411,402.94 4.00 463.95 1,700.00 51.26 1,531.80 408.98 -369.72311.62 540,025.076,033,715.841,468.15 4.00 539.30 1,800.00 55.22 1,591.64 461.78 -429.95310.87 539,964.556,033,768.311,527.99 4.00 619.05 1,900.00 59.17 1,645.81 516.37 -493.84310.18 539,900.386,033,822.541,582.16 4.00 702.82 2,000.00 63.14 1,694.04 572.49 -561.07309.54 539,832.856,033,878.291,630.39 4.00 790.18 2,100.00 67.10 1,736.11 629.86 -631.31308.95 539,762.306,033,935.281,672.46 4.00 880.73 2,200.00 71.07 1,771.81 688.22 -704.23308.39 539,689.086,033,993.231,708.16 4.00 974.01 2,305.86 75.27 1,802.46 750.74 -783.93307.83 539,609.046,034,055.311,738.81 4.00 1,075.23 End Dir : 2305.86' MD, 1802.46' TVD 2,400.00 75.27 1,826.40 806.58 -855.84307.83 539,536.846,034,110.761,762.75 0.00 1,166.23 2,500.00 75.27 1,851.84 865.90 -932.22307.83 539,460.146,034,169.651,788.19 0.00 1,262.88 2,585.77 75.27 1,873.65 916.78 -997.74307.83 539,394.366,034,220.171,810.00 0.00 1,345.78 Base Permafrost 2,600.00 75.27 1,877.27 925.22 -1,008.61307.83 539,383.456,034,228.551,813.62 0.00 1,359.54 2,700.00 75.27 1,902.70 984.54 -1,084.99307.83 539,306.756,034,287.451,839.05 0.00 1,456.20 2,800.00 75.27 1,928.14 1,043.86 -1,161.37307.83 539,230.056,034,346.341,864.49 0.00 1,552.85 2,900.00 75.27 1,953.57 1,103.17 -1,237.76307.83 539,153.366,034,405.241,889.92 0.00 1,649.51 3,000.00 75.27 1,979.01 1,162.49 -1,314.14307.83 539,076.666,034,464.141,915.36 0.00 1,746.16 3,100.00 75.27 2,004.44 1,221.81 -1,390.52307.83 538,999.966,034,523.031,940.79 0.00 1,842.82 3,200.00 75.27 2,029.88 1,281.13 -1,466.91307.83 538,923.266,034,581.931,966.23 0.00 1,939.48 3,300.00 75.27 2,055.31 1,340.45 -1,543.29307.83 538,846.576,034,640.831,991.66 0.00 2,036.13 3,356.38 75.27 2,069.65 1,373.89 -1,586.36307.83 538,803.326,034,674.042,006.00 0.00 2,090.63 SV1 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 2,017.09 Vert Section 3,400.00 75.27 2,080.74 1,399.77 -1,619.67307.83 538,769.876,034,699.722,017.09 0.00 2,132.79 3,500.00 75.27 2,106.18 1,459.09 -1,696.06307.83 538,693.176,034,758.622,042.53 0.00 2,229.45 3,600.00 75.27 2,131.61 1,518.40 -1,772.44307.83 538,616.486,034,817.522,067.96 0.00 2,326.10 3,700.00 75.27 2,157.05 1,577.72 -1,848.82307.83 538,539.786,034,876.412,093.40 0.00 2,422.76 3,800.00 75.27 2,182.48 1,637.04 -1,925.21307.83 538,463.086,034,935.312,118.83 0.00 2,519.42 3,900.00 75.27 2,207.91 1,696.36 -2,001.59307.83 538,386.386,034,994.212,144.26 0.00 2,616.07 4,000.00 75.27 2,233.35 1,755.68 -2,077.97307.83 538,309.696,035,053.102,169.70 0.00 2,712.73 4,100.00 75.27 2,258.78 1,815.00 -2,154.36307.83 538,232.996,035,112.002,195.13 0.00 2,809.39 4,121.00 75.27 2,264.12 1,827.45 -2,170.40307.83 538,216.886,035,124.372,200.47 0.00 2,829.68 13 3/8" x 16" 4,200.00 75.27 2,284.22 1,874.32 -2,230.74307.83 538,156.296,035,170.902,220.57 0.00 2,906.04 4,300.00 75.27 2,309.65 1,933.63 -2,307.12307.83 538,079.606,035,229.792,246.00 0.00 3,002.70 4,400.00 75.27 2,335.09 1,992.95 -2,383.51307.83 538,002.906,035,288.692,271.44 0.00 3,099.36 4,500.00 75.27 2,360.52 2,052.27 -2,459.89307.83 537,926.206,035,347.592,296.87 0.00 3,196.01 4,600.00 75.27 2,385.95 2,111.59 -2,536.27307.83 537,849.506,035,406.482,322.30 0.00 3,292.67 4,700.00 75.27 2,411.39 2,170.91 -2,612.66307.83 537,772.816,035,465.382,347.74 0.00 3,389.32 4,800.00 75.27 2,436.82 2,230.23 -2,689.04307.83 537,696.116,035,524.282,373.17 0.00 3,485.98 4,900.00 75.27 2,462.26 2,289.54 -2,765.42307.83 537,619.416,035,583.172,398.61 0.00 3,582.64 5,000.00 75.27 2,487.69 2,348.86 -2,841.81307.83 537,542.726,035,642.072,424.04 0.00 3,679.29 5,100.00 75.27 2,513.12 2,408.18 -2,918.19307.83 537,466.026,035,700.972,449.47 0.00 3,775.95 5,200.00 75.27 2,538.56 2,467.50 -2,994.57307.83 537,389.326,035,759.862,474.91 0.00 3,872.61 5,300.00 75.27 2,563.99 2,526.82 -3,070.96307.83 537,312.626,035,818.762,500.34 0.00 3,969.26 5,400.00 75.27 2,589.43 2,586.14 -3,147.34307.83 537,235.936,035,877.662,525.78 0.00 4,065.92 5,500.00 75.27 2,614.86 2,645.46 -3,223.72307.83 537,159.236,035,936.552,551.21 0.00 4,162.58 5,600.00 75.27 2,640.30 2,704.77 -3,300.11307.83 537,082.536,035,995.452,576.65 0.00 4,259.23 5,700.00 75.27 2,665.73 2,764.09 -3,376.49307.83 537,005.846,036,054.352,602.08 0.00 4,355.89 5,800.00 75.27 2,691.16 2,823.41 -3,452.87307.83 536,929.146,036,113.242,627.51 0.00 4,452.55 5,900.00 75.27 2,716.60 2,882.73 -3,529.26307.83 536,852.446,036,172.142,652.95 0.00 4,549.20 6,000.00 75.27 2,742.03 2,942.05 -3,605.64307.83 536,775.746,036,231.042,678.38 0.00 4,645.86 6,100.00 75.27 2,767.47 3,001.37 -3,682.02307.83 536,699.056,036,289.932,703.82 0.00 4,742.52 6,200.00 75.27 2,792.90 3,060.69 -3,758.41307.83 536,622.356,036,348.832,729.25 0.00 4,839.17 6,300.00 75.27 2,818.33 3,120.00 -3,834.79307.83 536,545.656,036,407.732,754.68 0.00 4,935.83 6,400.00 75.27 2,843.77 3,179.32 -3,911.17307.83 536,468.966,036,466.622,780.12 0.00 5,032.48 6,500.00 75.27 2,869.20 3,238.64 -3,987.56307.83 536,392.266,036,525.522,805.55 0.00 5,129.14 6,600.00 75.27 2,894.64 3,297.96 -4,063.94307.83 536,315.566,036,584.422,830.99 0.00 5,225.80 6,700.00 75.27 2,920.07 3,357.28 -4,140.32307.83 536,238.866,036,643.312,856.42 0.00 5,322.45 6,800.00 75.27 2,945.51 3,416.60 -4,216.71307.83 536,162.176,036,702.212,881.86 0.00 5,419.11 6,900.00 75.27 2,970.94 3,475.92 -4,293.09307.83 536,085.476,036,761.112,907.29 0.00 5,515.77 7,000.00 75.27 2,996.37 3,535.23 -4,369.47307.83 536,008.776,036,820.002,932.72 0.00 5,612.42 7,100.00 75.27 3,021.81 3,594.55 -4,445.86307.83 535,932.086,036,878.902,958.16 0.00 5,709.08 7,200.00 75.27 3,047.24 3,653.87 -4,522.24307.83 535,855.386,036,937.802,983.59 0.00 5,805.74 7,300.00 75.27 3,072.68 3,713.19 -4,598.62307.83 535,778.686,036,996.693,009.03 0.00 5,902.39 7,400.00 75.27 3,098.11 3,772.51 -4,675.01307.83 535,701.986,037,055.593,034.46 0.00 5,999.05 7,500.00 75.27 3,123.54 3,831.83 -4,751.39307.83 535,625.296,037,114.493,059.89 0.00 6,095.71 7,600.00 75.27 3,148.98 3,891.15 -4,827.77307.83 535,548.596,037,173.383,085.33 0.00 6,192.36 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 6 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,110.76 Vert Section 7,700.00 75.27 3,174.41 3,950.46 -4,904.16307.83 535,471.896,037,232.283,110.76 0.00 6,289.02 7,800.00 75.27 3,199.85 4,009.78 -4,980.54307.83 535,395.206,037,291.183,136.20 0.00 6,385.68 7,900.00 75.27 3,225.28 4,069.10 -5,056.92307.83 535,318.506,037,350.073,161.63 0.00 6,482.33 8,000.00 75.27 3,250.72 4,128.42 -5,133.31307.83 535,241.806,037,408.973,187.07 0.00 6,578.99 8,100.00 75.27 3,276.15 4,187.74 -5,209.69307.83 535,165.106,037,467.873,212.50 0.00 6,675.64 8,200.00 75.27 3,301.58 4,247.06 -5,286.07307.83 535,088.416,037,526.763,237.93 0.00 6,772.30 8,300.00 75.27 3,327.02 4,306.38 -5,362.46307.83 535,011.716,037,585.663,263.37 0.00 6,868.96 8,400.00 75.27 3,352.45 4,365.69 -5,438.84307.83 534,935.016,037,644.563,288.80 0.00 6,965.61 8,451.89 75.27 3,365.65 4,396.48 -5,478.48307.83 534,895.216,037,675.123,302.00 0.00 7,015.77 LA3 8,500.00 75.27 3,377.89 4,425.01 -5,515.22307.83 534,858.326,037,703.453,314.24 0.00 7,062.27 8,600.00 75.27 3,403.32 4,484.33 -5,591.61307.83 534,781.626,037,762.353,339.67 0.00 7,158.93 8,700.00 75.27 3,428.75 4,543.65 -5,667.99307.83 534,704.926,037,821.253,365.10 0.00 7,255.58 8,800.00 75.27 3,454.19 4,602.97 -5,744.37307.83 534,628.226,037,880.143,390.54 0.00 7,352.24 8,900.00 75.27 3,479.62 4,662.29 -5,820.76307.83 534,551.536,037,939.043,415.97 0.00 7,448.90 9,000.00 75.27 3,505.06 4,721.61 -5,897.14307.83 534,474.836,037,997.943,441.41 0.00 7,545.55 9,100.00 75.27 3,530.49 4,780.92 -5,973.52307.83 534,398.136,038,056.833,466.84 0.00 7,642.21 9,200.00 75.27 3,555.93 4,840.24 -6,049.91307.83 534,321.446,038,115.733,492.28 0.00 7,738.87 9,300.00 75.27 3,581.36 4,899.56 -6,126.29307.83 534,244.746,038,174.633,517.71 0.00 7,835.52 9,400.00 75.27 3,606.79 4,958.88 -6,202.67307.83 534,168.046,038,233.523,543.14 0.00 7,932.18 9,500.00 75.27 3,632.23 5,018.20 -6,279.06307.83 534,091.346,038,292.423,568.58 0.00 8,028.84 9,600.00 75.27 3,657.66 5,077.52 -6,355.44307.83 534,014.656,038,351.323,594.01 0.00 8,125.49 9,700.00 75.27 3,683.10 5,136.84 -6,431.82307.83 533,937.956,038,410.213,619.45 0.00 8,222.15 9,800.00 75.27 3,708.53 5,196.15 -6,508.21307.83 533,861.256,038,469.113,644.88 0.00 8,318.80 9,900.00 75.27 3,733.96 5,255.47 -6,584.59307.83 533,784.566,038,528.013,670.31 0.00 8,415.46 10,000.00 75.27 3,759.40 5,314.79 -6,660.97307.83 533,707.866,038,586.903,695.75 0.00 8,512.12 10,100.00 75.27 3,784.83 5,374.11 -6,737.36307.83 533,631.166,038,645.803,721.18 0.00 8,608.77 10,200.00 75.27 3,810.27 5,433.43 -6,813.74307.83 533,554.466,038,704.703,746.62 0.00 8,705.43 10,205.44 75.27 3,811.65 5,436.65 -6,817.89307.83 533,550.296,038,707.903,748.00 0.00 8,710.69 UG_MB 10,300.00 75.27 3,835.70 5,492.75 -6,890.12307.83 533,477.776,038,763.593,772.05 0.00 8,802.09 10,370.57 75.27 3,853.65 5,534.61 -6,944.03307.83 533,423.646,038,805.163,790.00 0.00 8,870.30 SB_Na 10,400.00 75.27 3,861.14 5,552.07 -6,966.51307.83 533,401.076,038,822.493,797.49 0.00 8,898.74 10,500.00 75.27 3,886.57 5,611.38 -7,042.89307.83 533,324.376,038,881.393,822.92 0.00 8,995.40 10,595.74 75.27 3,910.92 5,668.18 -7,116.02307.83 533,250.946,038,937.773,847.27 0.00 9,087.94 Start Dir 4º/100' : 10595.74' MD, 3910.92'TVD 10,600.00 75.42 3,912.00 5,670.70 -7,119.28307.77 533,247.676,038,940.283,848.35 4.00 9,092.06 10,700.00 79.15 3,934.00 5,729.42 -7,197.15306.28 533,169.496,038,998.573,870.35 4.00 9,189.57 10,800.00 82.89 3,949.61 5,786.84 -7,277.49304.83 533,088.846,039,055.553,885.96 4.00 9,288.32 10,856.55 85.00 3,955.58 5,818.63 -7,323.87304.02 533,042.296,039,087.083,891.93 4.00 9,344.53 End Dir : 10856.55' MD, 3955.58' TVD 10,900.00 85.00 3,959.36 5,842.85 -7,359.75304.02 533,006.296,039,111.103,895.71 0.00 9,387.79 10,995.08 85.00 3,967.65 5,895.84 -7,438.25304.02 532,927.516,039,163.663,904.00 0.00 9,482.46 SB_Oa 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 7 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,905.00 Vert Section 11,006.55 85.00 3,968.65 5,902.23 -7,447.73304.02 532,918.006,039,170.003,905.00 0.00 9,493.88 11,007.00 85.01 3,968.69 5,902.48 -7,448.10304.03 532,917.636,039,170.253,905.04 2.50 9,494.33 9 5/8" x 12 1/4" 11,007.10 85.01 3,968.70 5,902.54 -7,448.18304.03 532,917.546,039,170.303,905.05 2.50 9,494.43 Begin Geosteering 11,016.38 85.22 3,969.49 5,907.72 -7,455.84304.13 532,909.866,039,175.443,905.84 2.50 9,503.67 11,100.00 85.22 3,976.46 5,954.48 -7,524.81304.13 532,840.646,039,221.823,912.81 0.00 9,586.96 11,140.97 85.22 3,979.88 5,977.39 -7,558.61304.13 532,806.726,039,244.553,916.23 0.00 9,627.77 11,200.00 86.69 3,984.04 6,010.41 -7,607.36304.10 532,757.806,039,277.303,920.39 2.50 9,686.62 11,300.00 89.19 3,987.63 6,066.40 -7,690.13304.04 532,674.736,039,332.833,923.98 2.50 9,786.50 11,343.91 90.29 3,987.83 6,090.97 -7,726.52304.02 532,638.226,039,357.203,924.18 2.50 9,830.38 11,400.00 90.29 3,987.54 6,122.35 -7,773.01304.02 532,591.566,039,388.333,923.89 0.00 9,886.44 11,500.00 90.29 3,987.04 6,178.30 -7,855.89304.02 532,508.386,039,443.823,923.39 0.00 9,986.39 11,600.00 90.29 3,986.53 6,234.25 -7,938.77304.02 532,425.216,039,499.313,922.88 0.00 10,086.33 11,700.00 90.29 3,986.02 6,290.19 -8,021.66304.02 532,342.036,039,554.803,922.37 0.00 10,186.28 11,800.00 90.29 3,985.52 6,346.14 -8,104.54304.02 532,258.856,039,610.293,921.87 0.00 10,286.22 11,900.00 90.29 3,985.01 6,402.09 -8,187.42304.02 532,175.676,039,665.783,921.36 0.00 10,386.17 12,000.00 90.29 3,984.50 6,458.04 -8,270.30304.02 532,092.496,039,721.273,920.85 0.00 10,486.11 12,100.00 90.29 3,984.00 6,513.98 -8,353.19304.02 532,009.326,039,776.763,920.35 0.00 10,586.06 12,168.91 90.29 3,983.65 6,552.54 -8,410.30304.02 531,952.006,039,815.003,920.00 0.00 10,654.93 12,200.00 91.07 3,983.28 6,569.93 -8,436.07304.01 531,926.146,039,832.253,919.63 2.50 10,686.00 12,295.80 93.46 3,979.50 6,623.43 -8,515.43303.97 531,846.496,039,885.323,915.85 2.50 10,781.66 12,300.00 93.46 3,979.24 6,625.78 -8,518.91303.97 531,843.006,039,887.643,915.59 0.00 10,785.85 12,400.00 93.46 3,973.20 6,681.55 -8,601.70303.97 531,759.936,039,942.963,909.55 0.00 10,885.61 12,441.66 93.46 3,970.69 6,704.78 -8,636.18303.97 531,725.326,039,966.003,907.04 0.00 10,927.17 12,500.00 92.00 3,967.91 6,737.37 -8,684.50304.02 531,676.836,039,998.323,904.26 2.50 10,985.41 12,555.80 90.61 3,966.63 6,768.60 -8,730.72304.07 531,630.446,040,029.293,902.98 2.50 11,041.17 12,600.00 90.61 3,966.16 6,793.36 -8,767.33304.07 531,593.706,040,053.853,902.51 0.00 11,085.34 12,700.00 90.61 3,965.10 6,849.37 -8,850.16304.07 531,510.586,040,109.413,901.45 0.00 11,185.29 12,800.00 90.61 3,964.03 6,905.39 -8,932.99304.07 531,427.456,040,164.973,900.38 0.00 11,285.23 12,900.00 90.61 3,962.97 6,961.41 -9,015.82304.07 531,344.336,040,220.533,899.32 0.00 11,385.17 13,000.00 90.61 3,961.91 7,017.43 -9,098.65304.07 531,261.206,040,276.093,898.26 0.00 11,485.12 13,100.00 90.61 3,960.84 7,073.44 -9,181.48304.07 531,178.076,040,331.663,897.19 0.00 11,585.06 13,200.00 90.61 3,959.78 7,129.46 -9,264.31304.07 531,094.956,040,387.223,896.13 0.00 11,685.00 13,305.80 90.61 3,958.65 7,188.73 -9,351.95304.07 531,007.006,040,446.003,895.00 0.00 11,790.74 13,400.00 88.26 3,959.58 7,241.46 -9,429.99304.02 530,928.686,040,498.303,895.93 2.50 11,884.88 13,500.00 85.76 3,964.81 7,297.30 -9,512.78303.98 530,845.606,040,553.683,901.16 2.50 11,984.68 13,514.59 85.39 3,965.93 7,305.43 -9,524.84303.97 530,833.496,040,561.753,902.28 2.50 11,999.22 13,600.00 85.39 3,972.79 7,352.99 -9,595.45303.97 530,762.646,040,608.923,909.14 0.00 12,084.31 13,700.00 85.39 3,980.83 7,408.69 -9,678.11303.97 530,679.686,040,664.163,917.18 0.00 12,183.93 13,803.74 85.39 3,989.17 7,466.46 -9,763.87303.97 530,593.626,040,721.463,925.52 0.00 12,287.27 13,900.00 87.80 3,994.88 7,520.19 -9,843.53304.03 530,513.686,040,774.753,931.23 2.50 12,383.30 14,000.00 90.30 3,996.55 7,576.18 -9,926.35304.09 530,430.556,040,830.293,932.90 2.50 12,483.23 14,010.56 90.56 3,996.47 7,582.10 -9,935.10304.10 530,421.786,040,836.163,932.82 2.50 12,493.78 14,100.00 90.56 3,995.59 7,632.24 -10,009.16304.10 530,347.466,040,885.903,931.94 0.00 12,583.18 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 8 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,930.97 Vert Section 14,200.00 90.56 3,994.62 7,688.31 -10,091.96304.10 530,264.366,040,941.503,930.97 0.00 12,683.12 14,300.00 90.56 3,993.64 7,744.37 -10,174.76304.10 530,181.266,040,997.103,929.99 0.00 12,783.07 14,400.00 90.56 3,992.66 7,800.43 -10,257.56304.10 530,098.166,041,052.713,929.01 0.00 12,883.01 14,500.00 90.56 3,991.69 7,856.49 -10,340.36304.10 530,015.076,041,108.313,928.04 0.00 12,982.96 14,600.00 90.56 3,990.71 7,912.55 -10,423.17304.10 529,931.976,041,163.923,927.06 0.00 13,082.90 14,700.00 90.56 3,989.73 7,968.61 -10,505.97304.10 529,848.876,041,219.523,926.08 0.00 13,182.85 14,800.00 90.56 3,988.75 8,024.67 -10,588.77304.10 529,765.776,041,275.133,925.10 0.00 13,282.80 14,810.56 90.56 3,988.65 8,030.59 -10,597.51304.10 529,757.006,041,281.003,925.00 0.00 13,293.35 14,900.00 92.80 3,986.03 8,080.69 -10,671.56304.06 529,682.696,041,330.693,922.38 2.50 13,382.70 14,931.20 93.58 3,984.30 8,098.13 -10,697.36304.05 529,656.806,041,347.993,920.65 2.50 13,413.83 15,000.00 93.58 3,980.01 8,136.58 -10,754.26304.05 529,599.706,041,386.133,916.36 0.00 13,482.47 15,030.39 93.58 3,978.11 8,153.57 -10,779.39304.05 529,574.486,041,402.973,914.46 0.00 13,512.78 15,100.00 91.84 3,974.83 8,192.48 -10,837.00304.03 529,516.666,041,441.573,911.18 2.50 13,582.28 15,173.43 90.00 3,973.65 8,233.55 -10,897.86304.00 529,455.596,041,482.303,910.00 2.50 13,655.65 15,200.00 90.00 3,973.65 8,248.41 -10,919.89304.00 529,433.486,041,497.043,910.00 0.00 13,682.21 15,300.00 90.00 3,973.65 8,304.33 -11,002.79304.00 529,350.286,041,552.503,910.00 0.00 13,782.15 15,400.00 90.00 3,973.65 8,360.25 -11,085.70304.00 529,267.086,041,607.963,910.00 0.00 13,882.10 15,500.00 90.00 3,973.65 8,416.17 -11,168.60304.00 529,183.886,041,663.433,910.00 0.00 13,982.04 15,600.00 90.00 3,973.65 8,472.09 -11,251.50304.00 529,100.686,041,718.893,910.00 0.00 14,081.99 15,700.00 90.00 3,973.65 8,528.01 -11,334.41304.00 529,017.496,041,774.353,910.00 0.00 14,181.93 15,800.00 90.00 3,973.65 8,583.93 -11,417.31304.00 528,934.296,041,829.813,910.00 0.00 14,281.88 15,900.00 90.00 3,973.65 8,639.84 -11,500.22304.00 528,851.096,041,885.283,910.00 0.00 14,381.82 15,973.43 90.00 3,973.65 8,680.90 -11,561.09304.00 528,790.006,041,926.003,910.00 0.00 14,455.21 16,000.00 89.34 3,973.80 8,695.77 -11,583.12304.02 528,767.896,041,940.743,910.15 2.50 14,481.77 16,100.00 86.84 3,977.14 8,751.75 -11,665.90304.11 528,684.816,041,996.273,913.49 2.50 14,581.65 16,135.00 85.96 3,979.34 8,771.35 -11,694.82304.14 528,655.796,042,015.713,915.69 2.50 14,616.57 16,200.00 85.96 3,983.92 8,807.74 -11,748.48304.14 528,601.946,042,051.803,920.27 0.00 14,681.37 16,257.49 85.96 3,987.96 8,839.92 -11,795.94304.14 528,554.316,042,083.723,924.31 0.00 14,738.69 16,300.00 87.03 3,990.56 8,863.73 -11,831.06304.12 528,519.066,042,107.343,926.91 2.50 14,781.10 16,400.00 89.53 3,993.57 8,919.76 -11,913.83304.07 528,436.006,042,162.913,929.92 2.50 14,881.00 16,419.00 90.00 3,993.65 8,930.40 -11,929.57304.06 528,420.216,042,173.463,930.00 2.50 14,899.99 16,500.00 90.00 3,993.65 8,975.77 -11,996.67304.06 528,352.866,042,218.463,930.00 0.00 14,980.95 16,600.00 90.00 3,993.65 9,031.77 -12,079.52304.06 528,269.726,042,274.013,930.00 0.00 15,080.90 16,700.00 90.00 3,993.65 9,087.78 -12,162.36304.06 528,186.586,042,329.563,930.00 0.00 15,180.85 16,744.00 90.00 3,993.65 9,112.42 -12,198.81304.06 528,150.006,042,354.003,930.00 0.00 15,224.82 16,800.00 88.60 3,994.33 9,143.75 -12,245.22303.99 528,103.436,042,385.083,930.68 2.50 15,280.79 16,898.18 86.15 3,998.83 9,198.50 -12,326.59303.88 528,021.776,042,439.383,935.18 2.50 15,378.80 16,900.00 86.15 3,998.95 9,199.52 -12,328.10303.88 528,020.266,042,440.383,935.30 0.00 15,380.62 17,000.00 86.15 4,005.67 9,255.13 -12,410.93303.88 527,937.136,042,495.543,942.02 0.00 15,480.33 17,100.00 86.15 4,012.38 9,310.75 -12,493.77303.88 527,854.006,042,550.703,948.73 0.00 15,580.04 17,147.02 86.15 4,015.54 9,336.90 -12,532.71303.88 527,814.926,042,576.643,951.89 0.00 15,626.92 17,200.00 87.47 4,018.48 9,366.40 -12,576.62303.92 527,770.866,042,605.903,954.83 2.50 15,679.79 17,300.00 89.97 4,020.71 9,422.24 -12,659.54303.99 527,687.646,042,661.283,957.06 2.50 15,779.70 17,337.11 90.90 4,020.43 9,442.99 -12,690.31304.02 527,656.776,042,681.873,956.78 2.50 15,816.79 17,400.00 90.90 4,019.44 9,478.17 -12,742.42304.02 527,604.466,042,716.763,955.79 0.00 15,879.63 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 9 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,954.22 Vert Section 17,500.00 90.90 4,017.87 9,534.11 -12,825.30304.02 527,521.306,042,772.243,954.22 0.00 15,979.57 17,600.00 90.90 4,016.30 9,590.06 -12,908.17304.02 527,438.136,042,827.733,952.65 0.00 16,079.50 17,700.00 90.90 4,014.73 9,646.00 -12,991.04304.02 527,354.966,042,883.213,951.08 0.00 16,179.44 17,800.00 90.90 4,013.16 9,701.94 -13,073.92304.02 527,271.796,042,938.703,949.51 0.00 16,279.37 17,900.00 90.90 4,011.59 9,757.88 -13,156.79304.02 527,188.626,042,994.183,947.94 0.00 16,379.30 18,000.00 90.90 4,010.02 9,813.82 -13,239.67304.02 527,105.456,043,049.663,946.37 0.00 16,479.24 18,087.11 90.90 4,008.65 9,862.55 -13,311.86304.02 527,033.006,043,098.003,945.00 0.00 16,566.29 18,100.00 91.22 4,008.41 9,869.76 -13,322.54304.01 527,022.286,043,105.153,944.76 2.50 16,579.17 18,188.26 93.43 4,004.83 9,919.05 -13,395.66303.95 526,948.906,043,154.033,941.18 2.50 16,667.30 18,200.00 93.43 4,004.13 9,925.59 -13,405.39303.95 526,939.156,043,160.523,940.48 0.00 16,679.02 18,292.43 93.43 3,998.60 9,977.12 -13,481.92303.95 526,862.346,043,211.633,934.95 0.00 16,771.22 18,300.00 93.24 3,998.16 9,981.34 -13,488.19303.96 526,856.056,043,215.813,934.51 2.50 16,778.78 18,400.00 90.74 3,994.69 10,037.22 -13,571.04304.04 526,772.916,043,271.243,931.04 2.50 16,878.66 18,440.42 89.73 3,994.53 10,059.86 -13,604.52304.08 526,739.306,043,293.693,930.88 2.50 16,919.06 18,500.00 89.73 3,994.81 10,093.24 -13,653.87304.08 526,689.786,043,326.813,931.16 0.00 16,978.60 18,600.00 89.73 3,995.28 10,149.28 -13,736.69304.08 526,606.666,043,382.383,931.63 0.00 17,078.55 18,700.00 89.73 3,995.75 10,205.31 -13,819.52304.08 526,523.546,043,437.963,932.10 0.00 17,178.50 18,800.00 89.73 3,996.22 10,261.35 -13,902.34304.08 526,440.426,043,493.543,932.57 0.00 17,278.45 18,900.00 89.73 3,996.69 10,317.38 -13,985.17304.08 526,357.306,043,549.123,933.04 0.00 17,378.40 19,000.00 89.73 3,997.16 10,373.42 -14,067.99304.08 526,274.186,043,604.693,933.51 0.00 17,478.35 19,100.00 89.73 3,997.63 10,429.45 -14,150.82304.08 526,191.066,043,660.273,933.98 0.00 17,578.29 19,200.00 89.73 3,998.11 10,485.49 -14,233.64304.08 526,107.946,043,715.853,934.46 0.00 17,678.24 19,300.00 89.73 3,998.58 10,541.52 -14,316.47304.08 526,024.826,043,771.433,934.93 0.00 17,778.19 19,315.42 89.73 3,998.65 10,550.16 -14,329.24304.08 526,012.006,043,780.003,935.00 0.00 17,793.61 19,400.00 87.62 4,000.60 10,597.45 -14,399.33303.93 525,941.666,043,826.903,936.95 2.50 17,878.11 19,480.04 85.63 4,005.32 10,641.95 -14,465.68303.78 525,875.076,043,871.043,941.67 2.50 17,957.95 19,500.00 85.63 4,006.84 10,653.02 -14,482.22303.78 525,858.476,043,882.023,943.19 0.00 17,977.84 19,603.23 85.63 4,014.72 10,710.25 -14,567.77303.78 525,772.626,043,938.773,951.07 0.00 18,080.70 19,700.00 88.04 4,020.06 10,764.04 -14,648.03303.88 525,692.086,043,992.123,956.41 2.50 18,177.25 19,757.94 89.49 4,021.31 10,796.36 -14,696.10303.94 525,643.846,044,024.173,957.66 2.50 18,235.14 19,800.00 89.49 4,021.68 10,819.84 -14,731.00303.94 525,608.826,044,047.463,958.03 0.00 18,277.18 19,900.00 89.49 4,022.57 10,875.67 -14,813.96303.94 525,525.576,044,102.843,958.92 0.00 18,377.12 20,000.00 89.49 4,023.46 10,931.50 -14,896.92303.94 525,442.326,044,158.213,959.81 0.00 18,477.05 20,100.00 89.49 4,024.35 10,987.33 -14,979.87303.94 525,359.066,044,213.583,960.70 0.00 18,576.99 20,200.00 89.49 4,025.24 11,043.16 -15,062.83303.94 525,275.816,044,268.953,961.59 0.00 18,676.93 20,300.00 89.49 4,026.13 11,098.99 -15,145.79303.94 525,192.566,044,324.333,962.48 0.00 18,776.87 20,400.00 89.49 4,027.02 11,154.82 -15,228.75303.94 525,109.306,044,379.703,963.37 0.00 18,876.80 20,500.00 89.49 4,027.91 11,210.65 -15,311.71303.94 525,026.056,044,435.073,964.26 0.00 18,976.74 20,582.94 89.49 4,028.65 11,256.96 -15,380.52303.94 524,957.006,044,481.003,965.00 0.00 19,059.63 20,600.00 89.92 4,028.74 11,266.48 -15,394.67303.96 524,942.806,044,490.453,965.09 2.50 19,076.68 20,700.00 92.41 4,026.71 11,322.40 -15,477.54304.06 524,859.636,044,545.913,963.06 2.50 19,176.60 20,744.83 93.53 4,024.38 11,347.49 -15,514.61304.11 524,822.436,044,570.803,960.73 2.50 19,221.34 20,800.00 93.53 4,020.98 11,378.38 -15,560.21304.11 524,776.676,044,601.433,957.33 0.00 19,276.38 20,848.18 93.53 4,018.01 11,405.34 -15,600.02304.11 524,736.716,044,628.183,954.36 0.00 19,324.45 20,900.00 92.24 4,015.40 11,434.35 -15,642.88304.06 524,693.706,044,656.953,951.75 2.50 19,376.17 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 10 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True Measured Depth (usft) Inclination (°) Azimuth (°) +E/-W (usft) Map Northing (usft) Map Easting (usft) +N/-S (usft) Planned Survey Vertical Depth (usft) TVDss usft DLS 3,950.00 Vert Section 20,989.62 90.00 4,013.65 11,484.48 -15,717.14303.98 524,619.186,044,706.673,950.00 2.50 19,465.72 21,000.00 90.00 4,013.65 11,490.28 -15,725.75303.98 524,610.546,044,712.423,950.00 0.00 19,476.10 21,100.00 90.00 4,013.65 11,546.17 -15,808.67303.98 524,527.326,044,767.853,950.00 0.00 19,576.04 21,200.00 90.00 4,013.65 11,602.06 -15,891.60303.98 524,444.106,044,823.293,950.00 0.00 19,675.98 21,300.00 90.00 4,013.65 11,657.95 -15,974.52303.98 524,360.896,044,878.723,950.00 0.00 19,775.93 21,400.00 90.00 4,013.65 11,713.84 -16,057.44303.98 524,277.676,044,934.153,950.00 0.00 19,875.87 21,500.00 90.00 4,013.65 11,769.73 -16,140.36303.98 524,194.456,044,989.593,950.00 0.00 19,975.81 21,600.00 90.00 4,013.65 11,825.62 -16,223.29303.98 524,111.236,045,045.023,950.00 0.00 20,075.76 21,700.00 90.00 4,013.65 11,881.51 -16,306.21303.98 524,028.016,045,100.453,950.00 0.00 20,175.70 21,800.00 90.00 4,013.65 11,937.40 -16,389.13303.98 523,944.806,045,155.893,950.00 0.00 20,275.65 21,900.00 90.00 4,013.65 11,993.29 -16,472.06303.98 523,861.586,045,211.323,950.00 0.00 20,375.59 21,989.62 90.00 4,013.65 12,043.38 -16,546.37303.98 523,787.006,045,261.003,950.00 0.00 20,465.16 22,000.00 89.74 4,013.67 12,049.19 -16,554.98304.00 523,778.366,045,266.763,950.02 2.50 20,475.53 22,100.00 87.25 4,016.30 12,105.20 -16,637.77304.16 523,695.286,045,322.313,952.65 2.50 20,575.44 22,113.97 86.90 4,017.02 12,113.04 -16,649.32304.19 523,683.696,045,330.093,953.37 2.50 20,589.39 22,200.00 86.90 4,021.67 12,161.31 -16,720.37304.19 523,612.386,045,377.963,958.02 0.00 20,675.25 22,301.81 86.90 4,027.18 12,218.43 -16,804.46304.19 523,527.996,045,434.623,963.53 0.00 20,776.87 22,400.00 89.35 4,030.39 12,273.53 -16,885.67304.13 523,446.496,045,489.273,966.74 2.50 20,874.95 22,457.14 90.78 4,030.33 12,305.56 -16,932.97304.09 523,399.026,045,521.053,966.68 2.50 20,932.06 22,500.00 90.78 4,029.74 12,329.59 -16,968.47304.09 523,363.396,045,544.883,966.09 0.00 20,974.90 22,600.00 90.78 4,028.38 12,385.63 -17,051.28304.09 523,280.296,045,600.463,964.73 0.00 21,074.84 22,700.00 90.78 4,027.02 12,441.68 -17,134.09304.09 523,197.196,045,656.053,963.37 0.00 21,174.78 22,800.00 90.78 4,025.66 12,497.72 -17,216.89304.09 523,114.086,045,711.643,962.01 0.00 21,274.72 22,900.00 90.78 4,024.30 12,553.76 -17,299.70304.09 523,030.986,045,767.233,960.65 0.00 21,374.66 23,000.00 90.78 4,022.94 12,609.81 -17,382.51304.09 522,947.886,045,822.823,959.29 0.00 21,474.60 23,100.00 90.78 4,021.57 12,665.85 -17,465.32304.09 522,864.776,045,878.403,957.92 0.00 21,574.54 23,200.00 90.78 4,020.21 12,721.90 -17,548.13304.09 522,781.676,045,933.993,956.56 0.00 21,674.48 23,300.00 90.78 4,018.85 12,777.94 -17,630.94304.09 522,698.576,045,989.583,955.20 0.00 21,774.42 23,400.00 90.78 4,017.49 12,833.98 -17,713.74304.09 522,615.466,046,045.173,953.84 0.00 21,874.36 23,500.00 90.78 4,016.13 12,890.03 -17,796.55304.09 522,532.366,046,100.763,952.48 0.00 21,974.30 23,600.00 90.78 4,014.77 12,946.07 -17,879.36304.09 522,449.266,046,156.343,951.12 0.00 22,074.25 23,682.14 90.78 4,013.65 12,992.11 -17,947.37304.09 522,381.006,046,202.003,950.00 0.00 22,156.33 Total Depth : 23682.14' MD, 4013.65' TVD 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 11 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True Target Name - hit/miss target - Shape TVD (usft) Northing (usft) Easting (usft) +N/-S (usft) +E/-W (usft) Targets Dip Angle (°) Dip Dir. (°) MPR-107 wp02 tgt7 3,988.65 6,041,281.00 529,757.008,030.59 -10,597.510.00 0.00 - plan hits target center - Point MPR-107 wp02 tgt21 4,013.65 6,046,202.00 522,381.0012,992.11 -17,947.370.00 0.00 - plan hits target center - Point MPR-107 wp02 tgt1 3,968.65 6,039,170.00 532,918.005,902.23 -7,447.730.00 0.00 - plan hits target center - Point MPR-107 wp02 tgt9 3,973.65 6,041,926.00 528,790.008,680.90 -11,561.090.00 0.00 - plan hits target center - Point MPR-107 wp02 tgt19 4,013.65 6,045,261.00 523,787.0012,043.38 -16,546.370.00 0.00 - plan hits target center - Point MPR-107 wp02 tgt11 3,993.65 6,042,354.00 528,150.009,112.42 -12,198.810.00 0.00 - plan hits target center - Point MPR-107 wp02 tgt13 4,008.65 6,043,098.00 527,033.009,862.55 -13,311.860.00 0.00 - plan hits target center - Point MPR-107 wp02 tgt5 3,958.65 6,040,446.00 531,007.007,188.73 -9,351.950.00 0.00 - plan hits target center - Point MPR-107 wp02 tgt3 3,983.65 6,039,815.00 531,952.006,552.54 -8,410.300.00 0.00 - plan hits target center - Point MPR-107 wp02 tgt17 4,028.65 6,044,481.00 524,957.0011,256.96 -15,380.520.00 0.00 - plan hits target center - Point MPR-107 wp02 tgt15 3,998.65 6,043,780.00 526,012.0010,550.16 -14,329.240.00 0.00 - plan hits target center - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 9 5/8" x 12 1/4"3,968.6911,007.00 9-5/8 12-1/4 4 1/2" x 8 1/2"4,013.6523,682.14 4-1/2 8-1/2 13 3/8" x 16"2,264.124,121.00 13-3/8 16 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 12 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Standard Proposal Report Well: Wellbore: Plan: MPU R-107 MPU R-107 Survey Calculation Method:Minimum Curvature R-107 as built RKB @ 63.65usft Design:MPU R-107 wp02 Database:Alaska MD Reference:R-107 as built RKB @ 63.65usft North Reference: Well Plan: MPU R-107 True Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations Vertical Depth SS 8,451.89 3,365.65 LA3 10,205.44 3,811.65 UG_MB 10,370.57 3,853.65 SB_Na 3,356.38 2,069.65 SV1 1,496.33 1,393.65 SV5 10,995.08 3,967.65 SB_Oa 2,585.77 1,873.65 Base Permafrost Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 325.00 325.00 0.00 0.00 Start Dir 3º/100' : 325' MD, 325'TVD 575.00 574.29 13.38 -9.37 Start Dir 4º/100' : 575' MD, 574.29'TVD 2,305.86 1,802.46 750.74 -783.93 End Dir : 2305.86' MD, 1802.46' TVD 10,595.74 3,910.92 5,668.18 -7,116.02 Start Dir 4º/100' : 10595.74' MD, 3910.92'TVD 10,856.55 3,955.58 5,818.63 -7,323.87 End Dir : 10856.55' MD, 3955.58' TVD 11,007.10 3,968.70 5,902.54 -7,448.18 Begin Geosteering 23,682.14 4,013.65 12,992.11 -17,947.37 Total Depth : 23682.14' MD, 4013.65' TVD 4/25/2025 12:19:46PM COMPASS 5000.17 Build 04 Page 13 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU R-107 - MPU R-107 wp02Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool46.95 4,121.00 MPU R-107 wp02 GYD_Quest GWD7,121.00 11,007.00 MPU R-107 wp02 GYD_Quest GWD11,007.00 23,682.14 MPU R-107 wp02 GYD_Quest GWDEllipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.25 April, 2025 - 13:07COMPASSPage 5 of 7 Clearance SummaryAnticollision Report25 April, 2025Hilcorp Alaska, LLCMilne PointM Pt Raven PadPlan: MPU R-107MPU R-107MPU R-107 wp02Reference Design: M Pt Raven Pad - Plan: MPU R-107 - MPU R-107 - MPU R-107 wp02Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,033,308.92 N, 540,396.97 E (70° 30' 06.98" N, 149° 40' 10.48" W)Datum Height: R-107 as built RKB @ 63.65usftScan Range: 0.00 to 23,682.14 usft. Measured Depth.Geodetic Scale Factor AppliedVersion: 5000.17 Build: 04Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftNO GLOBAL FILTER: Using user defined selection & filtering criteriaScan Type:Scan Type:25.00 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU R-107 - MPU R-107 wp02Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 0.00 to 23,682.14 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Raven Pad - Plan: MPU R-107 - MPU R-107 - MPU R-107 wp02MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt Moose PadMPU M-30 - MPU M-30 - MPU M-301,030.81 10,125.00 803.32 17,035.00 4.53110,125.00Clearance Factor Pass - MPU M-30 - MPU M-30 - MPU M-301,026.14 10,200.00 800.88 17,035.00 4.55510,200.00Ellipse Separation Pass - MPU M-30 - MPU M-30 - MPU M-301,025.80 10,226.52 801.62 17,035.00 4.57610,226.52Centre Distance Pass - MPU M-31 - MPU M-31 - MPU M-31592.98 10,250.00 377.27 18,561.00 2.74910,250.00Clearance Factor Pass - MPU M-31 - MPU M-31 - MPU M-31591.08 10,275.00 376.40 18,561.00 2.75310,275.00Ellipse Separation Pass - MPU M-31 - MPU M-31 - MPU M-31590.19 10,307.45 377.45 18,561.00 2.77410,307.45Centre Distance Pass - MPU M-32 - MPU M-32 - MPU M-32302.33 10,232.52 200.86 19,000.00 2.97910,232.52Ellipse Separation Pass - MPU M-32 - MPU M-32 - MPU M-32302.83 10,250.00 201.03 19,000.00 2.97510,250.00Clearance Factor Pass - MPU M-33 - MPU M-33 - MPU M-33455.13 9,924.46 340.46 18,054.12 3.9699,924.46Centre Distance Pass - MPU M-33 - MPU M-33 - MPU M-33469.87 10,175.00 315.09 18,277.20 3.03610,175.00Ellipse Separation Pass - MPU M-33 - MPU M-33 - MPU M-33473.03 10,200.00 315.78 18,282.00 3.00810,200.00Clearance Factor Pass - MPU M-62 - MPU M-62 - MPU M-62606.52 9,151.22 490.96 18,266.45 5.2499,151.22Centre Distance Pass - MPU M-62 - MPU M-62 - MPU M-62617.43 9,350.00 482.95 18,419.51 4.5919,350.00Ellipse Separation Pass - MPU M-62 - MPU M-62 - MPU M-62720.46 9,850.00 541.04 18,832.00 4.0159,850.00Clearance Factor Pass - MPU M-63 - MPU M-63 - MPU M-63819.39 8,395.55 716.72 16,701.77 7.9808,395.55Centre Distance Pass - MPU M-63 - MPU M-63 - MPU M-63822.69 8,500.00 713.40 16,772.00 7.5288,500.00Ellipse Separation Pass - MPU M-63 - MPU M-63 - MPU M-631,053.92 9,675.00 862.81 17,909.67 5.5159,675.00Clearance Factor Pass - M Pt Raven PadMPU R-101 - MPU R-101 - MPU R-101114.60 606.25 109.47 602.78 22.353606.25Ellipse Separation Pass - MPU R-101 - MPU R-101 - MPU R-1012,420.00 20,675.00 2,067.64 20,560.00 6.86820,675.00Clearance Factor Pass - MPU R-101 - MPU R-101 PB1 - MPU R-101 PB1114.60 606.25 109.47 602.78 22.353606.25Ellipse Separation Pass - MPU R-101 - MPU R-101 PB1 - MPU R-101 PB1939.60 4,725.00 819.72 4,541.00 7.8384,725.00Clearance Factor Pass - MPU R-102 - MPU R-102 - MPU R-10289.77 302.12 86.72 302.08 29.449302.12Centre Distance Pass - MPU R-102 - MPU R-102 - MPU R-10290.13 400.00 86.49 398.02 24.754400.00Ellipse Separation Pass - MPU R-102 - MPU R-102 - MPU R-1022,008.64 20,375.00 1,658.53 20,243.00 5.73720,375.00Clearance Factor Pass - MPU R-102 - MPU R-102PB1 - MPU R-102PB189.77 302.12 86.61 302.08 28.429302.12Centre Distance Pass - MPU R-102 - MPU R-102PB1 - MPU R-102PB190.13 400.00 86.38 398.02 24.032400.00Ellipse Separation Pass - 25 April, 2025 - 13:11COMPASSPage 2 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU R-107 - MPU R-107 wp02Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 0.00 to 23,682.14 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Raven Pad - Plan: MPU R-107 - MPU R-107 - MPU R-107 wp02MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU R-102 - MPU R-102PB1 - MPU R-102PB1 780.36 4,675.00 675.28 4,485.00 7.4264,675.00Clearance Factor Pass - MPU R-103 - MPU R-103 - MPU R-103 59.80 46.95 57.57 46.85 26.88846.95Centre Distance Pass - MPU R-103 - MPU R-103 - MPU R-103 59.97 225.00 57.34 224.56 22.768225.00Ellipse Separation Pass - MPU R-103 - MPU R-103 - MPU R-103 1,615.10 21,150.00 1,246.33 21,180.00 4.38021,150.00Clearance Factor Pass - MPU R-103 - MPU R-103PB1 - MPU R-103PB1 59.80 46.95 57.57 46.85 26.88846.95Centre Distance Pass - MPU R-103 - MPU R-103PB1 - MPU R-103PB1 59.97 225.00 57.34 224.56 22.768225.00Ellipse Separation Pass - MPU R-103 - MPU R-103PB1 - MPU R-103PB1 1,593.21 11,850.00 1,374.54 11,848.00 7.28611,850.00Clearance Factor Pass - MPU R-104 - MPU R-104 - MPU R-104 72.49 846.98 66.66 862.47 12.435846.98Centre Distance Pass - MPU R-104 - MPU R-104 - MPU R-104 72.59 875.00 66.61 891.90 12.150875.00Ellipse Separation Pass - MPU R-104 - MPU R-104 - MPU R-104 1,190.00 21,325.00 813.03 21,369.00 3.15721,325.00Clearance Factor Pass - MPU R-104 - MPU R-104PB1 - MPU R-104PB1 72.49 846.98 66.66 862.47 12.435846.98Centre Distance Pass - MPU R-104 - MPU R-104PB1 - MPU R-104PB1 72.59 875.00 66.61 891.90 12.150875.00Ellipse Separation Pass - MPU R-104 - MPU R-104PB1 - MPU R-104PB1 1,231.19 12,000.00 952.43 12,082.00 4.41712,000.00Clearance Factor Pass - MPU R-141 - MPU R-141 - MPU R-141 149.88 46.95 147.81 48.45 72.48546.95Centre Distance Pass - MPU R-141 - MPU R-141 - MPU R-141 150.25 275.00 147.05 275.20 46.930275.00Ellipse Separation Pass - MPU R-141 - MPU R-141 - MPU R-141 1,579.42 8,700.00 1,412.27 13,029.35 9.4498,700.00Clearance Factor Pass - MPU R-142 - MPU R-142 - MPU R-142 115.79 450.00 111.87 454.64 29.539450.00Centre Distance Pass - MPU R-142 - MPU R-142 - MPU R-142 115.79 451.12 111.86 455.75 29.477451.12Ellipse Separation Pass - MPU R-142 - MPU R-142 - MPU R-142 1,771.88 8,250.00 1,625.22 11,557.54 12.0828,250.00Clearance Factor Pass - Plan: MPU R-106 - MPU R-106 - MPU R-106 wp02 30.03 291.63 26.96 291.73 9.782291.63Centre Distance Pass - Plan: MPU R-106 - MPU R-106 - MPU R-106 wp02406.2123,425.0018.7223,348.561.04823,425.00Clearance FactorPass - Plan: MPU R-109 - MPU R-109 - MPU R-109 wp02 172.88 1,380.22 159.81 1,446.29 13.2291,380.22Centre Distance Pass - Plan: MPU R-109 - MPU R-109 - MPU R-109 wp02 173.76 1,500.00 159.13 1,573.92 11.8751,500.00Ellipse Separation Pass - Plan: MPU R-109 - MPU R-109 - MPU R-109 wp02 949.76 22,350.00 579.74 22,595.72 2.56722,350.00Clearance Factor Pass - Plan: MPU R-110 - MPU R-110 - MPU R-110 wp02 27.69 876.12 20.11 878.32 3.652876.12Centre Distance Pass - Plan: MPU R-110 - MPU R-110 - MPU R-110 wp02 28.23 975.00 19.68 978.00 3.301975.00Ellipse Separation Pass - Plan: MPU R-110 - MPU R-110 - MPU R-110 wp02 35.31 1,250.00 23.49 1,255.23 2.9881,250.00Clearance Factor Pass - Plan: MPU R-111 - MPU R-111 - MPU R-111 wp02 61.07 325.00 57.78 325.00 18.570325.00Centre Distance Pass - Plan: MPU R-111 - MPU R-111 - MPU R-111 wp02 61.13 350.00 57.67 350.00 17.695350.00Ellipse Separation Pass - Plan: MPU R-111 - MPU R-111 - MPU R-111 wp02 1,740.32 22,925.00 1,363.04 23,205.18 4.61322,925.00Clearance Factor Pass - 25 April, 2025 - 13:11COMPASSPage 3 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU R-107 - MPU R-107 wp02Comparison Well Name - Wellbore Name - Design@MeasuredDepth(usft)MinimumDistance(usft)EllipseSeparation(usft)@MeasuredDepthusftClearanceFactorScan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usftSite NameScan Range: 0.00 to 23,682.14 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Raven Pad - Plan: MPU R-107 - MPU R-107 - MPU R-107 wp02MeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPU R-112 - MPU R-112 - MPU R-112 wp02 221.54 1,109.42 211.06 1,152.03 21.1411,109.42Centre Distance Pass - Plan: MPU R-112 - MPU R-112 - MPU R-112 wp02 222.26 1,200.00 210.58 1,246.66 19.0301,200.00Ellipse Separation Pass - Plan: MPU R-112 - MPU R-112 - MPU R-112 wp02 2,189.08 23,325.00 1,803.50 23,655.63 5.67723,325.00Clearance Factor Pass - Plan: MPU R-113 - MPU R-113 - MPU R-113 wp02 245.23 1,093.89 234.64 1,138.37 23.1491,093.89Centre Distance Pass - Plan: MPU R-113 - MPU R-113 - MPU R-113 wp02 245.61 1,150.00 234.25 1,195.95 21.6341,150.00Ellipse Separation Pass - Plan: MPU R-113 - MPU R-113 - MPU R-113 wp02 2,601.07 23,575.00 2,211.27 23,955.86 6.67323,575.00Clearance Factor Pass - Plan: MPU R-114 - MPU R-114 - MPU R-114 wp02 280.46 1,041.59 270.48 1,087.02 28.0981,041.59Centre Distance Pass - Plan: MPU R-114 - MPU R-114 - MPU R-114 wp02 280.88 1,100.00 270.13 1,147.27 26.1291,100.00Ellipse Separation Pass - Plan: MPU R-114 - MPU R-114 - MPU R-114 wp02 2,974.83 23,682.14 2,582.12 24,338.26 7.57523,682.14Clearance Factor Pass - Rig: MPU R-105 - MPU R-105 - MPU R-105 118.71 1,347.16 109.07 1,416.48 12.3131,347.16Centre Distance Pass - Rig: MPU R-105 - MPU R-105 - MPU R-105 118.72 1,350.00 109.06 1,419.35 12.2911,350.00Ellipse Separation Pass - Rig: MPU R-105 - MPU R-105 - MPU R-105 734.01 11,775.00 522.82 11,924.82 3.47611,775.00Clearance Factor Pass - Rig: MPU R-105 - MPU R-105 - MPU R-105 wp07 150.33 325.00 146.92 325.00 44.087325.00Centre Distance Pass - Rig: MPU R-105 - MPU R-105 - MPU R-105 wp07 150.39 350.00 146.82 350.00 42.163350.00Ellipse Separation Pass - Rig: MPU R-105 - MPU R-105 - MPU R-105 wp07 833.86 23,150.00 441.56 23,317.97 2.12623,150.00Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool46.95 4,121.00 MPU R-107 wp02 GYD_Quest GWD7,121.00 11,007.00 MPU R-107 wp02 GYD_Quest GWD11,007.00 23,682.14 MPU R-107 wp02 GYD_Quest GWD25 April, 2025 - 13:11COMPASSPage 4 of 7 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU R-107 - MPU R-107 wp02Ellipse error terms are correlated across survey tool tie-on points.Separation is the actual distance between ellipsoids.Calculated ellipses incorporate surface errors.Clearance Factor = Distance Between Profiles / (Distance Between Profiles - Ellipse Separation).Distance Between centres is the straight line distance between wellbore centres.All station coordinates were calculated using the Minimum Curvature method.25 April, 2025 - 13:11COMPASSPage 5 of 7 0.001.002.003.004.00Separation Factor1250 2500 3750 5000 6250 7500 8750 10000 11250 12500 13750 15000 16250 17500 18750 20000 21250 22500 23750Measured Depth (2500 usft/in)MPU R-105 wp07MPU R-105MPU R-103MPU R-109 wp02MPU R-110 wp02MPU R-104PB1MPU R-104MPU R-106 wp02MPU M-33MPU M-31MPU M-32MPU M-30No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: MPU R-107 NAD 1927 (NADCON CONUS)Alaska Zone 0416.70+N/-S +E/-W Northing Easting Latittude Longitude0.000.006033308.92540396.9770° 30' 6.9817 N149° 40' 10.4773 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-107, True NorthVertical (TVD) Reference:R-107 as built RKB @ 63.65usftMeasured Depth Reference:R-107 as built RKB @ 63.65usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-03-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool46.95 4121.00 MPU R-107 wp02 (MPU R-107) GYD_Quest GWD7121.00 11007.00 MPU R-107 wp02 (MPU R-107) GYD_Quest GWD11007.00 23682.14 MPU R-107 wp02 (MPU R-107) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)1250 2500 3750 5000 6250 7500 8750 10000 11250 12500 13750 15000 16250 17500 18750 20000 21250 22500 23750Measured Depth (2500 usft/in)MPU R-141MPU R-105 wp07MPU R-102MPU R-101MPU R-103MPU R-142MPU R-110 wp02MPU R-106 wp02NO GLOBAL FILTER: Using user defined selection & filtering criteria46.95 To 23682.14Project: Milne PointSite: M Pt Raven PadWell: Plan: MPU R-107Wellbore: MPU R-107Plan: MPU R-107 wp02CASING DETAILSTVD TVDSS MD Size Name2264.12 2200.47 4121.00 13-3/8 13 3/8" x 16"3968.69 3905.04 11007.00 9-5/8 9 5/8" x 12 1/4"4013.65 3950.00 23682.14 4-1/2 4 1/2" x 8 1/2" 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. 225-049 MILNE POINT and NIKAITCHUQ MPU R-107 SCHRADER BLUFF OIL WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT R-107Initial Class/TypeSER / PENDGeoArea890Unit11328On/Off ShoreOnProgramSERWell bore segAnnular DisposalPTD#:2250490Field & Pool:MILNE POINT, SCHRADER BLFF OIL - 525140, NIKAITCHUQ, SCHRADER BLUFF OIL - 561100NA1Permit fee attachedYesADL025509 , ADL388235, ADL355018, and ADL3906152Lease number appropriateYes3Unique well name and numberYesMILNE POINT, SCHRADER BLFF OIL and NIKAITCHUQ, SCHRADER BLUFF OI4Well located in a defined poolNoProposed well crosses from MPU into Nikiaitchuq Unit. Ownership is the same.5Well 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 waitNoPending expansion of AIO 10C14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForYes15All wells within 1/4 mile area of review identified (For service well only)YesPre-produced injector: up to 30 days16Pre-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)Yes20" conductor grouted to 80'18Conductor string providedYes13-3/8" fully cemented to surface19Surface casing protects all known USDWsYes20CMT vol adequate to circulate on conductor & surf csgNo9-5/8" outer cement to cover all moveable hydrocarbon zones21CMT vol adequate to tie-in long string to surf csgYes9-5/8" landed in the SB reservoir and to be cemented above all hydrocarbon zones.22CMT will cover all known productive horizonsYes23Casing designs adequate for C, T, B & permafrostYesParker 273 has adequate tankage and good trucking support.24Adequate tankage or reserve pitNAThis is a grassroots well.25If a re-drill, has a 10-403 for abandonment been approvedYesHalliburton collision scan identifies no close approaches26Adequate wellbore separation proposedYesDiverter to exeed 75 feet from nearest ignition source.27If diverter required, does it meet regulationsYesAll fluids overbalance to pore pressure.28Drilling fluid program schematic & equip list adequateYes13-5/8" 5M 3 ram stack with 1 annular29BOPEs, do they meet regulationYes5000 psi stack tested to 3000 psi.30BOPE press rating appropriate; test to (put psig in comments)Yes31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNoH2S monitors in use on the rig.33Is presence of H2S gas probableYes34Mechanical condition of wells within AOR verified (For service well only)YesH2S not anticipated; however, rig will have H2S sensors and alarms.35Permit can be issued w/o hydrogen sulfide measuresYesAnticipating normally pressured reservoir. MPD to mitigate any abnormal pressures36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate04-Jun-25ApprMGRDate13-May-25ApprADDDate04-Jun-25AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateProposed well crosses from MPU into Nikiaitchuq Unit. Ownership is the same. Pending expansion of AIO 10C.*&:JLC 6/5/2025