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Home My WebLink About225-033Nolan 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-106 50029238160000 225033 6/8/2025 HALLIBURTON 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: 06/20/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL: WELL: MPU R-106 PTD: 225-033 API: 50-029-23816-00-00 FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (05/12/2025 to 06/04/2025) x EWR-M5, AGR, ABG, BaseStar, StrataStar, 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. 225-033 T40603 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.06.20 11:26:23 -08'00' From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20250521 1149 : PTD# 225-033: R-106 Intermediate Cement Density Change"s Date:Wednesday, May 21, 2025 2:57:12 PM From: Jacob Thompson <Jacob.Thompson@hilcorp.com> Sent: Wednesday, May 21, 2025 11:49 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Frank Roach <Frank.Roach@hilcorp.com> Subject: RE: [EXTERNAL] RE: PTD# 225-033: R-106 Intermediate Cement Density Change's Mel, I’ve added the estimated volumes based on TD of the intermediate hole section. There may be slight changes due to as drilled TD. Thanks, Lead Slurry Tail Slurry System EconoCem HalCem Density 14 lb/gal 15.3 lb/gal Yield 1.522 ft3/sk 1.239 ft3/sk Mix Water 7.686 gal/sk 5.56 gal/sk Bbls 239.8 bbls 126.3 bbl Sacks 884.4 sx 572.1 sx Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, May 21, 2025 11:24 AM To: Jacob Thompson <Jacob.Thompson@hilcorp.com> Cc: Frank Roach <Frank.Roach@hilcorp.com> Subject: [EXTERNAL] RE: PTD# 225-033: R-106 Intermediate Cement Density Change's 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. Jacob, Intermediate casing proposed cementing slurry yield changes, both lead and tail, as described below are approved. Please reply with the computed number of sacks, as the drilling permit is prognosed as the # of sacks. 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: Jacob Thompson <Jacob.Thompson@hilcorp.com> Sent: Wednesday, May 21, 2025 10:26 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Frank Roach <Frank.Roach@hilcorp.com> Subject: PTD# 225-033: R-106 Intermediate Cement Density Change's Mel, After consulting with our cement provider we would like to change the density of the intermediate cement slurries. The lead desity will be increased from 12 ppg to 14 ppg, and the tail slurry decreased from 15.8 ppg to 15.3 ppg. I’ve amended the table below for your reference. Also I wanted to inform you that the LA3 marker came in close to depth at 8,323’ MD / 3,299’ TVD putting our cement top at ~6,530’ MD 2849’ TVD. Let me know if you have any questions. Thanks, Lead Slurry Tail Slurry System EconoCem HalCem Density 14 lb/gal 15.3 lb/gal Yield 1.522 ft3/sk 1.239 ft3/sk Mix Water 7.686 gal/sk 5.56 gal/sk Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 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, 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 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. 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 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 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. 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, Schrader and Nikaitchuq Oil, MPU R-106 Hilcorp Alaska, LLC Permit to Drill Number: 225-033 Surface Location: 5137' FSL, 4211' FEL, Sec 07, T13N, R10E, UM, AK Bottomhole Location: 1805' FSL, 1154' 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 23rd day of April 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.23 13:55:42 -08'00' By Grace Christianson at 9:11 am, Apr 04, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.04.03 16:19:24 - 08'00' Sean McLaughlin (4311) 50-029-23816-00-00225-033 A.Dewhurst 15APR25 1501 MGR18APR2025 AOGCC review of CBL and determination that shallow freshwater zone is protected required. DSR-4/7/25 * BOPE test to 3000 psi. Annular to 2500 psi. * Casing test and FIT digital data to AOGCC immediately upon completion of FIT. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.23 13:55:57 -08'00'04/23/25 RBDMS JSB 042425 Milne Point Unit (MPU) R-106 Drilling Program Version 0 4/2/2025 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 ........................................................................................................ 10 10.0 N/U 21-1/4” 2M Diverter System ................................................................................................ 11 11.0 Drill 16” Hole Section .................................................................................................................. 13 12.0 Run 13-3/8” Surface Casing ........................................................................................................ 16 13.0 Cement 13-3/8” Surface Casing .................................................................................................. 19 14.0 N/U BOP and Test........................................................................................................................ 22 15.0 Drill 12-1/4” Hole Section ............................................................................................................ 23 16.0 Run 9-5/8” Intermediate Casing ................................................................................................. 27 17.0 Cement 9-5/8” Intermediate Casing ........................................................................................... 30 18.0 Drill 8-1/2” Hole Section .............................................................................................................. 34 19.0 Run 5-1/2” x 4-1/2” Production Liner (Lower Completion) .................................................... 39 20.0 Run 2-7/8” Tubing (Upper Completion) .................................................................................... 44 21.0 RDMO ........................................................................................................................................... 45 22.0 Parker 273 Diverter Schematic................................................................................................... 46 23.0 Parker 273 BOP Schematic ......................................................................................................... 47 24.0 Wellhead Schematic ..................................................................................................................... 48 25.0 Days vs Depth ............................................................................................................................... 49 26.0 Formation Tops & Information .................................................................................................. 50 27.0 Anticipated Drilling Hazards ...................................................................................................... 53 28.0 Parker 273 Layout ....................................................................................................................... 58 29.0 FIT Procedure .............................................................................................................................. 59 30.0 Parker 273 Choke Manifold Schematic ..................................................................................... 60 31.0 Casing Design ............................................................................................................................... 61 32.0 12-1/4” Hole Section MASP ........................................................................................................ 62 33.0 8-1/2” Hole Section MASP .......................................................................................................... 63 34.0 Spider Plot (NAD 27) (Governmental Sections) ........................................................................ 64 35.0 Surface Plat (As-Built) (NAD 27) ............................................................................................... 65 Page 2 Milne Point Unit R-106 SB Producer Drilling Procedure 1.0 Well Summary Well MPU R-106 Pad Milne Point “R” Pad Planned Completion Type ESP Target Reservoir(s) Schrader Bluff Oa Sand Planned Well TD, MD / TVD 23,365’ MD / 3,984’ TVD PBTD, MD / TVD 23,364’ MD / 3,984’ TVD Surface Location (Governmental) 5,137' FSL, 4,211' FEL, Sec. 07, T13N, R10E, UM, AK Surface Location (NAD 27) X= 540,367.95 Y= 6,033,301.20 Top of Productive Horizon (Governmental)131' FSL, 1,363' FEL, Sec 35, T14N, R9E, UM, AK TPH Location (NAD 27) X= 532,743.00 Y= 6,038,816.40 BHL (Governmental) 1,805' FSL, 1,154' FEL, Sec 28, T14N, R9E, UM, AK BHL (NAD 27) X= 522,357.00 Y= 6,045,731.00 AFE Drilling Days 31 days AFE Completion Days 3 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 + 16.8 ft = 63.75 ft GL Elevation above MSL: 16.8 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams Page 3 Milne Point Unit R-106 SB Producer Drilling Procedure 2.0 Management of Change Information Page 4 Milne Point Unit R-106 SB Producer 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-52 Weld 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” Screens 4.892” 4.767” 6.050” 17.0 L-80 JFEBEAR 7,740 6,290 318 4-1/2” Screens 3.960” 3.795” 4.714” 13.5 L-80 H625 9,020 8,540 279 Tubing 2-7/8” 2.441” 2.347” 3.688” 6.5 L-80 EUE 8RD 10,570 11,170 105 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 & 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-106 SB Producer 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 3/4/2025 PROPOSED SCHEMATIC Milne Point Unit Well: MPU R-106 Last Completed: TBD PTD: TBD TD =23,365’ (MD) / TD =3,984’(TVD) 4 20” Orig. KB Elev.: 63.75’ / GL Elev.: 16.8’ 9-5/8” 11/12 5 2/3/4 13 13-3/8” 10 1 5-1/2” 2 3 See Screen/ Solid Liner Detail PBTD =23,364’ (MD) / PBTD =3,984’ (TVD) 9 8 5/6/72-7/8” 4-1/2” CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X56 / Weld N/A Surface 127’ N/A 13-3/8” Surface 68 / L-80 / CDC 12.415 Surface ~4,238’ 0.1497 9-5/8” Intermediate 40 / L-80 / BTC 8.835 Surface ~11,100’ 0.0758 5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.778 ~10,950’ ~14,868’ 0.0222 4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 ~14,868’ ~23,365’ 0.0149 TUBING DETAIL 2-7/8" Tubing 6.5# / L-80 / EUE 8-Rd 2.441 Surface ~10,950’ 0.0058 OPEN HOLE / CEMENT DETAIL 42” 20 yds 16" Lead –~1496 sx / Tail –~595 sx 12-1/4” Lead –~578 sx / Tail –~611 sx 8-1/2” Uncemented Screen Liner WELL INCLINATION DETAIL KOP @ 300’ 90° Hole Angle = @ 11,102’ TREE & WELLHEAD Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing Wellhead FMC 13-5/8” 5K w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: TBD Completion Date: TBD JEWELRY DETAIL No. Top MD Item ID 1 TBD 3-1/2” x 1” BK-2 GLM w/ 1” SOV 2.915” 2 TBD Ported Pressure Sub 3 TBD Discharge Head: 513, MS1-015 4 TBD Pump: 513 Series 111 Stage SG2000 5 TBD Gas Separator: Tandem 400 Series 6 TBD Upper Tandem Seal: 513 Series 7 TBD Lower Tandem Seal: 513 Series 8 TBD Motor: 562 Series, KMS2, 300HP 9 TBD Sensor, Vigilant, 150C w/ Discharge 10 TBD Summit Centralizer / Anode: Bottom @ 5,466’ MD 11 TBD SLZXP LTP / Liner Hanger Lap ~178’ 6.190” 12 TBD 7” H563 x 5.5” EZGO HT XO 4.778” 13 23,365’ Shoe 5-1/2” x 4-1/2”SCREENS LINER DETAIL Size Top (MD) Top (TVD) Btm (MD) Btm (TVD) 5-1/2” 4-1/2” Page 7 Milne Point Unit R-106 SB Producer Drilling Procedure 7.0 Drilling / Completion Summary MPU R-106 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. R-106 is part of a multi well development program targeting the Schrader Bluff sand on R-pad. 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. A production 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 May 4th, 2025, pending rig schedule. Surface casing will be run to ~4,255’ MD / 2,280’ TVD and cemented to surface via a single-stage primary cement job. 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” production liner. 8. Run upper completion. 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-106 SB Producer 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-106. 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 APD. 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)”. AOGCC Regulation Variance Requests: None Page 9 Milne Point Unit R-106 SB Producer 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 10 Milne Point Unit R-106 SB Producer Drilling Procedure 9.0 R/U and Preparatory Work 9.1 R-106 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 are in the 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 11 Milne Point Unit R-106 SB Producer 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 12 Milne Point Unit R-106 SB Producer Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Milne Point Unit R-106 SB Producer 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 14 Milne Point Unit R-106 SB Producer 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 in previous R-Pad wells nor 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 8.9+ 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, Toolpusher office, and mud loggers 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 SKREENKLEEN are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH Page 15 Milne Point Unit R-106 SB Producer Drilling Procedure in the 8.5 – 9.0 range with caustic soda. Daily additions of BUSAN 1060 MUST be made to control bacterial action. 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. 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 16 Milne Point Unit R-106 SB Producer 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 BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. 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 –Non-Rotating x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment components. 12.4 Continue running 13-3/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 2,000’ 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 Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. 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 17 Milne Point Unit R-106 SB Producer Drilling Procedure Page 18 Milne Point Unit R-106 SB Producer 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 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. 12.8 Lower casing and land hanger on landing ring to confirm depth. Confirm measurements. 12.9 Have emergency slips staged in cellar along with all necessary equipment for the contingency 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 19 Milne Point Unit R-106 SB Producer 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 20 Milne Point Unit R-106 SB Producer 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. 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 13.7. 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. 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 17 bbl 93 cuft 1501 Page 21 Milne Point Unit R-106 SB Producer Drilling Procedure 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, ±9.0 bbls before consulting with Drilling Engineer. 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. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 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 BOP stack that may have come in contact with the cement. Ensure to report the following on WellView: 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 22 Milne Point Unit R-106 SB Producer Drilling Procedure 14.0 N/U BOP and Test 14.1 N/D the diverter T, knife gate, diverter line & N/U 13-5/8” x 13-5/8” 5M wellhead. 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 4-1/2” 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 production hole. Ensure LSND mud weight matches the weight at TD of surface hole. 14.8 Set wearbushing in wellhead. 14.9 If needed, 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 are in the mud pumps. Page 23 Milne Point Unit R-106 SB Producer Drilling Procedure 15.0 Drill 12-1/4” Hole Section 15.1 M/U 12-1/4” Cleanout BHA (Milltooth Bit & 1.22° 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 10.7 ppg FIT is the minimum required to drill ahead x 10.7 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. x Ensure GWD is included in the BHA 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 a non-ported float in the production hole section. Page 24 Milne Point Unit R-106 SB Producer Drilling Procedure 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. 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 8.9 ppg 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 Page 25 Milne Point Unit R-106 SB Producer Drilling Procedure 15.14 Drill 12-1/4” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 700-950 gpm, target min. AV’s 180 ft/min, 880 gpm x RPM: 120+ 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 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. Mud rheology is the primary method of transporting cuttings. 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 sands for any extended period of time. x 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 (up to 200 fph) without having to backream connections. Hole cleaning is key. 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 surface interval. 15.15 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 15.16 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. Slow pulling speed when backreaming through coal depths seen when drilling. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. Page 26 Milne Point Unit R-106 SB Producer Drilling Procedure 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. 15.17 CBU minimum two times at 13-3/8” shoe and clean casing with high vis sweeps. 15.18 Monitor well for flow. 15.19 POOH and LD BHA 15.20 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 27 Milne Point Unit R-106 SB Producer 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 BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to at least 8-1/2” on the location prior to running. x Note that 40# API 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 while running using fill up line on rig floor. x Use BOL 2000 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. x Fill casing while running using fill up line on rig floor. 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 the cement job. 9-5/8” 40# L-80 BTC Make-Up Torques - Make up to Mark 10 jts Take Average: Casing OD Optimum 9-5/8” To Mark Page 28 Milne Point Unit R-106 SB Producer Drilling Procedure Page 29 Milne Point Unit R-106 SB Producer 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 5 joints and wash down. Take special care when staging pumps up and down to avoid surging and breaking down the formation. 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 30 Milne Point Unit R-106 SB Producer 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 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. 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 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 ~6,500’ MD, 2,810’ TVDss. Depth chosen from MPU R-103 log data and used to isolate and protect shallower freshwater intervals (<10,000 mg/L TDS) by 250’ TVD. Depths and volumes to be confirmed with as-drilled log data. Depth chosen from MPU R-103 log,g,,,pg data and used to isolate and protect shallower freshwater intervals (<10,000 mg/L TDS) by 250’p( TVD. Depths and volumes to be confirmed with as-drilled log data. Page 31 Milne Point Unit R-106 SB Producer 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 Lead Slurry Tail Slurry System EconoCem HalCem Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 32 Milne Point Unit R-106 SB Producer Drilling Procedure cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 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 ~3,200’ MD with dead crude or diesel after cement tests indicate cement has reached 500 psi compressive strength. x Freeze protect with ~190 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 4-1/2” and 5-1/2” test joints. Page 33 Milne Point Unit R-106 SB Producer Drilling Procedure Ensure to report the following on WellView: 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-106 SB Producer Drilling Procedure 18.0 Drill 8-1/2” Hole Section 18.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM) 18.2 TIH w/ 8-1/2” cleanout BHA 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 10.1 ppg FIT is the minimum required to drill ahead x 10.1 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 a non-ported float 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 Page 35 Milne Point Unit R-106 SB Producer 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-106 SB Producer 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 225 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-106 SB Producer 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 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 3X, 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-106 SB Producer 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 two times at 9-5/8” shoe and clean casing with high vis sweeps. 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-106 SB Producer Drilling Procedure 19.0 Run 5-1/2” x 4-1/2” Production Liner (Lower Completion) 19.1 Well control preparedness: In the event of an influx of formation fluids while running the production liner with screens, the following well control response procedure will be followed: x With 4-1/2” joint across BOP: P/U & M/U the 5-1/2” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). 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, TIW valve in open position on top, 5-1/2” handling joint above TIW). 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 4-1/2” 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” production liner. x Production liner will be a combination of screened and solid joints. Confirm with geologist and OE for any solid joint placement. x The uppermost ~3,900’ will be 5-1/2” screened / slotted liner. x Use API Modified or “Best O Life 2000 AG” equivalent thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the screens 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 Centralization: x 1 centralizer every joint to ~ 100’ MD from intermediate shoe x Obtain up and down weights of the liner before picking up liner hanger assembly. Record rotating torque at 10 and 20 rpm Page 40 Milne Point Unit R-106 SB Producer 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-106 SB Producer Drilling Procedure 5-1/2” 17.0# L-80 JFEBEAR Casing OD Minimum Optimum Maximum 5.5” 6,660 ft-lbs 7,400 ft-lbs 8,140 ft-lbs Page 42 Milne Point Unit R-106 SB Producer 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 There is no inner string planned to be run, as opposed to previous wells. 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-106 SB Producer 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. 19.24 Install test plug. Change out upper rams to 2-7/8” x 5” VBR’s or 2-7/8” fixed body rams. Test to 250 psi low, 3,000 psi high with 2-7/8” test joint. Note: Once running tool is LD, swap to the completion AFE. Page 44 Milne Point Unit R-106 SB Producer Drilling Procedure 20.0 Run 2-7/8” Tubing (Upper Completion) 20.1 Well control preparedness: In the event of an influx of formation fluids while running the production liner with screens, the following well control response procedure will be followed: x With 2-7/8” joint across BOP: P/U & M/U the 5-1/2” safety joint (with 2-7/8” crossover installed on bottom, TIW valve in open position on top, 2-7/8” handling pup above TIW). This joint shall be fully M/U and available prior to running the first joint of 2-7/8” tubing. 20.2 M/U ESP assembly and RIH to setting depth. TIH no faster than 90 ft/min. x Ensure wear bushing is pulled. x Ensure 2-7/8” EUE 8RD x DELTA 544 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 Ensure that the ESP Cable spooler is rigged up to the rig floor. 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. 2-7/8” 6.5# L-80 EUE 8RD Casing OD Minimum Optimum Maximum Operating Torque 2.875” 1,690 ft-lbs 2,250 ft-lbs 2,810 ft-lbs 2-Ǭ” Upper Completion Running Order x Centralizer (OD = ±5.85”), Base at ±10,950’ MD – Confirm final set depth with Operations Engineer Taylor Wellman,twellman@hilcorp.com or 907-947-9533. The ideal set depth of the ESP has a DSL less than 1.0 deg. x Intake Sensor x 500Hp 562 Motor (OD = 5.62”) x Lower Seal Section x Upper Seal Section x Intake / Gas Separator x Pump Section 1 x Discharge Head x Joints 2-7/8”, 6.5#, L-80, EUE 8rd tubing x ±10’ Pup Joint 2-7/8”, 6.5#, L-80, EUE 8rd x 2-7/8” GLM (+/-140’ MD) Page 45 Milne Point Unit R-106 SB Producer Drilling Procedure x ±10’ Pup Joint 2-7/8”, 6.5#, L-80, EUE 8rd x 1 joint 2-7/8”, 6.5#, L-80, EUE 8rd tubing x 2-7/8”, 6.5#, L-80, EUE 8rd space out pups (if needed) x 1 joint 2-7/8”, 6.5#, L-80, EUE 8rd tubing x Tubing hanger with 2-7/8”, 6.5#, L-80, EUE 8rd pin down 20.3 Follow all service company procedures for handling, make up and deployment of the ESP system. x Typical clamping is every joint for the first 15 joints and then every other joint to surface. Make note of clamping performed in tally. x Perform electrical continuity checks every 2,000’ MD. 20.4 MU tubing hanger, install penetrator, and terminate ESP cable. Perform final continuity check. 20.5 RIH and land hanger. RILDS and test hanger. 20.6 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and tree. 20.7 Pull BPV. Set TWC. Test tree to 5000 psi. 20.8 Pull TWC. Set BPV. Bullhead tubing & IA freeze protect if/as needed. Contact MPU Wells Foreman, Aubrey Malik/Billy Kruskie for confirmation at 670-3330. 20.9 Secure the tree and cellar. 21.0 RDMO 21.1 RDMO Parker 273 Page 46 Milne Point Unit R-106 SB Producer Drilling Procedure 22.0 Parker 273 Diverter Schematic Page 47 Milne Point Unit R-106 SB Producer Drilling Procedure 23.0 Parker 273 BOP Schematic Page 48 Milne Point Unit R-106 SB Producer Drilling Procedure 24.0 Wellhead Schematic Page 49 Milne Point Unit R-106 SB Producer Drilling Procedure 25.0 Days vs Depth Page 50 Milne Point Unit R-106 SB Producer Drilling Procedure 26.0 Formation Tops & Information TOP NAME TVD (FT) TVDSS (FT) MD (FT) Formation Pressure (psi) EMW (ppg) SV5 1,394 1,330 1,509 613 8.46 Base Permafrost 1,882 1,818 2,721 828 8.46 SV1 2,070 2,006 3,438 910 8.46 UG4A 2,400 2,336 4,695 1056 8.46 LA3 3,362 3,298 8,361 1479 8.46 UG_MB 3,548 3,484 9,070 1561 8.46 UG_MF 3,810 3,746 10,069 1676 8.46 SB_Na 3,850 3,786 10,221 1694 8.46 SB_Oa 3,960 3,896 10,890 1742 8.46 Page 51 Milne Point Unit R-106 SB Producer Drilling Procedure L-Pad and F-Pad Data Sheets Formation Descriptions (Closest & Most Analogous MPU Pads to Moose Pad) Page 52 Milne Point Unit R-106 SB Producer Drilling Procedure Page 53 Milne Point Unit R-106 SB Producer Drilling Procedure 27.0 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 behaves 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 54 Milne Point Unit R-106 SB Producer 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 55 Milne Point Unit R-106 SB Producer 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 behaves 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. Ugnu Coal Seams: Ugnu Coals from the UG4A down to the UG1 have been problematic on these high-angle, long stepout Raven Pad wells. MPD and black product additions have not shown to be beneficial. Maintain mud properties throughout the 12-1/4” hole section. Utilize a ghost reamer ~2,000’ behind the bit to wipe the coals ~1 day after initially cutting with the bit. Confirm the depths of all coals with the geologist and note for backreaming at TD. Slow pulling speed when approaching and crossing the coal zones to avoid packing off and pulling the BHA stuck. 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 Page 56 Milne Point Unit R-106 SB Producer Drilling Procedure 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. 4. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 5. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 6. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 57 Milne Point Unit R-106 SB Producer 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 58 Milne Point Unit R-106 SB Producer Drilling Procedure 28.0 Parker 273 Layout Page 59 Milne Point Unit R-106 SB Producer Drilling Procedure 29.0 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 60 Milne Point Unit R-106 SB Producer Drilling Procedure 30.0 Parker 273 Choke Manifold Schematic Page 61 Milne Point Unit R-106 SB Producer Drilling Procedure 31.0 Casing Design Page 62 Milne Point Unit R-106 SB Producer Drilling Procedure 32.0 12-1/4” Hole Section MASP Page 63 Milne Point Unit R-106 SB Producer Drilling Procedure 33.0 8-1/2” Hole Section MASP Page 64 Milne Point Unit R-106 SB Producer Drilling Procedure 34.0 Spider Plot (NAD 27) (Governmental Sections) Page 65 Milne Point Unit R-106 SB Producer Drilling Procedure 35.0 Surface Plat (As-Built) (NAD 27) Standard Proposal Report 06 March, 2025 Plan: MPU R-106 wp02 Hilcorp Alaska, LLC Milne Point M Pt Raven Pad Plan: MPU R-106 MPU R-106 -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 304.92° (2500 usft/in)MPR-106 wp02 tgt20MPR-106 wp02 tgt02MPR-106 wp02 tgt01MPR-106 wp02 tgt14MPR-106 wp02 tgt17MPR-106 wp02 tgt09MPR-106 wp02 tgt10MPR-106 wp02 tgt15MPR-106 wp02 tgt08MPR-106 wp02 tgt16MPR-106 wp02 tgt12MPR-106 wp02 tgt05MPR-106 wp02 tgt18MPR-106 wp02 tgt11MPR-106 wp02 tgt13MPR-106 wp02 tgt04MPR-106 wp02 tgt03MPR-106 wp02 tgt07MPR-106 wp02 tgt19MPR-106 wp02 tgt0613 3/8" x 16"9 5/8" x 12 1/4"4 1/2" x 8 1/2"50010001500200025003000350040004500500055006000650070007500800085009000950010000105001100011500120001250013000135001400014500150001550016000165001700017500180001850019000195002000020500210002150022000225002300023365MPU R-106 wp02Start Dir 3º/100' : 300' MD, 300'TVDStart Dir 4º/100' : 600' MD, 598.77'TVDEnd Dir : 2248.09' MD, 1757.82' TVDStart Dir 4º/100' : 10507.6' MD, 3906.5'TVDEnd Dir : 10790.29' MD, 3953.29' TVDBegin GeosteeringTotal Depth : 23365.06' MD, 3983.75' TVDSV5Base PermafrostSV1UG4ALA3UG_MBUG_MFSB_NaSB_OaHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU R-10616.80+N/-S +E/-WNorthingEastingLatittudeLongitude0.000.006033301.20540367.95 70° 30' 6.9073 N 149° 40' 11.3330 WSURVEY PROGRAMDate: 2024-03-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool46.95 4256.00 MPU R-106 wp02 (MPU R-106) GYD_Quest GWD4256.00 11100.00 MPU R-106 wp02 (MPU R-106) GYD_Quest GWD11100.00 23365.06 MPU R-106 wp02 (MPU R-106) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1393.75 1330.00 1508.78 SV51881.75 1818.00 2724.48 Base Permafrost2069.75 2006.00 3447.15 SV12399.75 2336.00 4715.66 UG4A3361.75 3298.00 8413.57 LA33547.75 3484.00 9128.56 UG_MB3809.75 3746.00 10135.68 UG_MF3849.75 3786.00 10289.44 SB_Na3959.75 3896.00 10882.95 SB_OaREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-106, True NorthVertical (TVD) Reference:R-106 as built RKB @ 63.75usftMeasured Depth Reference:R-106 as built RKB @ 63.75usftCalculation Method: Minimum CurvatureProject:Milne PointSite:M Pt Raven PadWell:Plan: MPU R-106Wellbore:MPU R-106Design:MPU R-106 wp02CASING DETAILSTVD TVDSS MD SizeName2280.00 2216.25 4255.34 13-3/8 13 3/8" x 16"3969.33 3905.58 11100.00 9-5/8 9 5/8" x 12 1/4"3983.75 3920.00 23365.06 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 0.002 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD3 600.00 9.00 305.00 598.77 13.49 -19.26 3.00 305.00 23.51 Start Dir 4º/100' : 600' MD, 598.77'TVD4 2248.09 74.92 306.27 1757.82 627.41 -861.38 4.00 1.34 1065.44 End Dir : 2248.09' MD, 1757.82' TVD5 10507.60 74.92 306.27 3906.50 5345.39 -7291.25 0.00 0.00 9038.36 Start Dir 4º/100' : 10507.6' MD, 3906.5'TVD6 10790.29 86.00 303.97 3953.29 5505.44 -7518.97 4.00 -11.78 9316.69 End Dir : 10790.29' MD, 3953.29' TVD7 10940.29 86.00 303.97 3963.75 5589.05 -7643.06 0.00 0.00 9466.30 MPR-106 wp02 tgt01 Begin Geosteering8 11111.52 90.28 303.99 3969.31 5684.67 -7784.94 2.50 0.26 9637.379 12246.04 90.28 303.99 3963.75 6318.91 -8725.61 0.00 0.00 10771.74 MPR-106 wp02 tgt0210 12355.42 87.56 303.72 3965.81 6379.83 -8816.41 2.50 -174.41 10881.0611 12582.58 87.56 303.72 3975.49 6505.83 -9005.18 0.00 0.00 11107.9712 12692.37 90.29 304.00 3977.55 6566.99 -9096.33 2.50 5.79 11217.7113 13442.37 90.29 304.00 3973.75 6986.38 -9718.10 0.00 0.00 11967.61 MPR-106 wp02 tgt0414 13495.86 88.95 303.99 3974.10 7016.28 -9762.44 2.50 -179.73 12021.0915 13733.16 88.95 303.99 3978.44 7148.93 -9959.15 0.00 0.00 12258.3116 13812.65 90.94 303.97 3978.51 7193.36 -10025.06 2.50 -0.68 12337.7917 14712.65 90.94 303.97 3963.75 7696.18 -10771.36 0.00 0.00 13237.54 MPR-106 wp02 tgt0618 14883.89 86.66 303.90 3967.34 7791.73 -10913.37 2.50 -179.09 13408.6819 15012.92 86.66 303.90 3974.85 7863.57 -11020.28 0.00 0.00 13537.4720 15146.59 90.00 304.00 3978.75 7938.19 -11131.10 2.50 1.69 13671.0521 15896.59 90.00 304.00 3978.75 8357.58 -11752.88 0.00 0.00 14420.95 MPR-106 wp02 tgt0822 16026.87 93.25 303.80 3975.06 8430.21 -11860.95 2.50 -3.51 14551.1423 16135.22 93.25 303.80 3968.91 8490.38 -11950.84 0.00 0.00 14659.2924 16287.80 89.44 303.97 3965.33 8575.41 -12077.45 2.50 177.45 14811.7825 16637.80 89.44 303.97 3968.75 8770.97 -12367.70 0.00 0.00 15161.71 MPR-106 wp02 tgt1026 16761.36 86.35 304.11 3973.28 8840.08 -12470.01 2.50 177.48 15285.1627 17049.12 86.35 304.11 3991.58 9001.10 -12707.80 0.00 0.00 15572.3128 17232.30 90.93 303.93 3995.92 9103.53 -12859.54 2.50 -2.20 15755.3629 17982.30 90.93 303.93 3983.75 9522.11 -13481.75 0.00 0.00 16505.15 MPR-106 wp02 tgt1230 18029.94 89.74 303.98 3983.47 9548.72 -13521.27 2.50 177.37 16552.7931 19581.60 89.74 303.98 3990.51 10416.04 -14807.87 0.00 0.00 18104.2232 19593.25 89.45 303.96 3990.59 10422.55 -14817.53 2.50 -175.16 18115.8733 20443.25 89.45 303.96 3998.75 10897.35 -15522.51 0.00 0.00 18965.71 MPR-106 wp02 tgt1634 20588.87 85.81 303.88 4004.77 10978.52 -15643.23 2.50 -178.72 19111.1635 20696.36 85.81 303.88 4012.62 11038.28 -15732.23 0.00 0.00 19218.3536 20864.00 90.00 303.99 4018.75 11131.79 -15871.20 2.50 1.53 19385.8137 21864.00 90.00 303.99 4018.75 11690.83 -16700.33 0.00 0.00 20385.68 MPR-106 wp02 tgt1838 22022.32 93.96 303.90 4013.29 11779.16 -16831.57 2.50 -1.37 20543.8539 22185.16 93.96 303.90 4002.05 11869.76 -16966.41 0.00 0.00 20706.2840 22315.06 90.71 303.96 3996.76 11942.19 -17074.09 2.50 178.86 20836.0341 23365.06 90.71 303.96 3983.75 12528.69 -17944.92 0.00 0.00 21885.80 MPR-106 wp02 tgt20 Total Depth : 23365.06' MD, 3983.75' TVD -1000010002000300040005000600070008000900010000110001200013000South(-)/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-106 wp02 tgt06MPR-106 wp02 tgt19MPR-106 wp02 tgt07MPR-106 wp02 tgt03MPR-106 wp02 tgt04MPR-106 wp02 tgt13MPR-106 wp02 tgt11MPR-106 wp02 tgt18MPR-106 wp02 tgt05MPR-106 wp02 tgt12MPR-106 wp02 tgt16MPR-106 wp02 tgt08MPR-106 wp02 tgt15MPR-106 wp02 tgt10MPR-106 wp02 tgt09MPR-106 wp02 tgt17MPR-106 wp02 tgt14MPR-106 wp02 tgt01MPR-106 wp02 tgt02MPR-106 wp02 tgt2013 3/8" x 16"9 5/8" x 12 1/4"4 1/2" x 8 1/2"25050075010001250150017502000225025002750300032503500375040003984MPU R-106 wp02Start Dir 3º/100' : 300' MD, 300'TVDStart Dir 4º/100' : 600' MD, 598.77'TVDEnd Dir : 2248.09' MD, 1757.82' TVDStart Dir 4º/100' : 10507.6' MD, 3906.5'TVDEnd Dir : 10790.29' MD, 3953.29' TVDBegin GeosteeringTotal Depth : 23365.06' MD, 3983.75' TVDCASING DETAILSTVDTVDSS MDSize Name2280.00 2216.25 4255.34 13-3/8 13 3/8" x 16"3969.33 3905.58 11100.00 9-5/8 9 5/8" x 12 1/4"3983.75 3920.00 23365.06 4-1/2 4 1/2" x 8 1/2"Project: Milne PointSite: M Pt Raven PadWell: Plan: MPU R-106Wellbore: MPU R-106Plan: MPU R-106 wp02WELL DETAILS: Plan: MPU R-10616.80+N/-S +E/-W Northing EastingLatittudeLongitude0.00 0.006033301.20540367.95 70° 30' 6.9073 N149° 40' 11.3330 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-106, True NorthVertical (TVD) Reference:R-106 as built RKB @ 63.75usftMeasured Depth Reference:R-106 as built RKB @ 63.75usftCalculation 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-106 MPU R-106 Survey Calculation Method:Minimum Curvature R-106 as built RKB @ 63.75usft Design:MPU R-106 wp02 Database:Alaska MD Reference:R-106 as built RKB @ 63.75usft North Reference: Well Plan: MPU R-106 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-106 usft usft 0.00 0.00 6,033,301.20 540,367.95 16.80Wellhead Elevation:usft0.00 70° 30' 6.9073 N 149° 40' 11.3330 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) MPU R-106 Model NameMagnetics BGGM2024 3/26/2024 14.32 80.78 57,253.84189509 Phase:Version: Audit Notes: Design MPU R-106 wp02 PLAN Vertical Section: Depth From (TVD) (usft) +N/-S (usft) Direction (°) +E/-W (usft) Tie On Depth:46.95 304.920.000.0046.95 3/6/2025 5:24:42PM 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-106 MPU R-106 Survey Calculation Method:Minimum Curvature R-106 as built RKB @ 63.75usft Design:MPU R-106 wp02 Database:Alaska MD Reference:R-106 as built RKB @ 63.75usft North Reference: Well Plan: MPU R-106 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 -16.80 0.000.000.000.000.000.00300.000.000.00300.00 236.25 305.000.003.003.00-19.2613.49598.77305.009.00600.00 535.02 1.340.084.004.00-861.38627.411,757.82306.2774.922,248.09 1,694.07 0.000.000.000.00-7,291.255,345.393,906.50306.2774.9210,507.60 3,842.75 -11.78-0.813.924.00-7,518.975,505.443,953.29303.9786.0010,790.29 3,889.54 0.000.000.000.00-7,643.065,589.053,963.75303.9786.0010,940.29 3,900.00 0.260.012.502.50-7,784.945,684.673,969.31303.9990.2811,111.52 3,905.56 0.000.000.000.00-8,725.616,318.913,963.75303.9990.2812,246.04 3,900.00 -174.41-0.24-2.492.50-8,816.416,379.833,965.81303.7287.5612,355.42 3,902.06 0.000.000.000.00-9,005.186,505.833,975.49303.7287.5612,582.58 3,911.74 5.790.252.492.50-9,096.336,566.993,977.55304.0090.2912,692.37 3,913.80 0.000.000.000.00-9,718.106,986.383,973.75304.0090.2913,442.37 3,910.00 -179.73-0.01-2.502.50-9,762.447,016.283,974.10303.9988.9513,495.86 3,910.35 0.000.000.000.00-9,959.157,148.933,978.44303.9988.9513,733.16 3,914.69 -0.68-0.032.502.50-10,025.067,193.363,978.51303.9790.9413,812.65 3,914.76 0.000.000.000.00-10,771.367,696.183,963.75303.9790.9414,712.65 3,900.00 -179.09-0.04-2.502.50-10,913.377,791.733,967.34303.9086.6614,883.89 3,903.59 0.000.000.000.00-11,020.287,863.573,974.85303.9086.6615,012.92 3,911.10 1.690.072.502.50-11,131.107,938.193,978.75304.0090.0015,146.59 3,915.00 0.000.000.000.00-11,752.888,357.583,978.75304.0090.0015,896.59 3,915.00 -3.51-0.152.502.50-11,860.958,430.213,975.06303.8093.2516,026.87 3,911.31 0.000.000.000.00-11,950.848,490.383,968.91303.8093.2516,135.22 3,905.16 177.450.11-2.502.50-12,077.458,575.413,965.33303.9789.4416,287.80 3,901.58 0.000.000.000.00-12,367.708,770.973,968.75303.9789.4416,637.80 3,905.00 177.480.11-2.502.50-12,470.018,840.083,973.28304.1186.3516,761.36 3,909.53 0.000.000.000.00-12,707.809,001.103,991.58304.1186.3517,049.12 3,927.83 -2.20-0.102.502.50-12,859.549,103.533,995.92303.9390.9317,232.30 3,932.17 0.000.000.000.00-13,481.759,522.113,983.75303.9390.9317,982.30 3,920.00 177.370.11-2.502.50-13,521.279,548.723,983.47303.9889.7418,029.94 3,919.72 0.000.000.000.00-14,807.8710,416.043,990.51303.9889.7419,581.60 3,926.76 -175.16-0.21-2.492.50-14,817.5310,422.553,990.59303.9689.4519,593.25 3,926.84 0.000.000.000.00-15,522.5110,897.353,998.75303.9689.4520,443.25 3,935.00 -178.72-0.06-2.502.50-15,643.2310,978.524,004.77303.8885.8120,588.87 3,941.02 0.000.000.000.00-15,732.2311,038.284,012.62303.8885.8120,696.36 3,948.87 1.530.072.502.50-15,871.2011,131.794,018.75303.9990.0020,864.00 3,955.00 0.000.000.000.00-16,700.3311,690.834,018.75303.9990.0021,864.00 3,955.00 -1.37-0.062.502.50-16,831.5711,779.164,013.29303.9093.9622,022.32 3,949.54 0.000.000.000.00-16,966.4111,869.764,002.05303.9093.9622,185.16 3,938.30 178.860.05-2.502.50-17,074.0911,942.193,996.76303.9690.7122,315.06 3,933.01 0.000.000.000.00-17,944.9212,528.693,983.75303.9690.7123,365.06 3,920.00 3/6/2025 5:24:42PM 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-106 MPU R-106 Survey Calculation Method:Minimum Curvature R-106 as built RKB @ 63.75usft Design:MPU R-106 wp02 Database:Alaska MD Reference:R-106 as built RKB @ 63.75usft North Reference: Well Plan: MPU R-106 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 16.80 Vert Section 46.95 0.00 46.95 0.00 0.000.00 540,367.956,033,301.2016.80 0.00 0.00 100.00 0.00 100.00 0.00 0.000.00 540,367.956,033,301.20-36.25 0.00 0.00 200.00 0.00 200.00 0.00 0.000.00 540,367.956,033,301.20-136.25 0.00 0.00 300.00 0.00 300.00 0.00 0.000.00 540,367.956,033,301.20-236.25 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 400.00 3.00 399.95 1.50 -2.14305.00 540,365.806,033,302.69-336.20 3.00 2.62 500.00 6.00 499.63 6.00 -8.57305.00 540,359.356,033,307.15-435.88 3.00 10.46 600.00 9.00 598.77 13.49 -19.26305.00 540,348.626,033,314.58-535.02 3.00 23.51 Start Dir 4º/100' : 600' MD, 598.77'TVD 700.00 13.00 696.91 24.50 -34.84305.42 540,332.986,033,325.50-633.16 4.00 42.59 800.00 17.00 793.48 39.54 -55.89305.64 540,311.856,033,340.43-729.73 4.00 68.46 900.00 21.00 888.02 58.54 -82.32305.78 540,285.326,033,359.28-824.27 4.00 101.01 1,000.00 25.00 980.05 81.40 -113.99305.88 540,253.536,033,381.98-916.30 4.00 140.07 1,100.00 29.00 1,069.13 108.03 -150.75305.95 540,216.636,033,408.40-1,005.38 4.00 185.45 1,200.00 33.00 1,154.84 138.28 -192.42306.00 540,174.806,033,438.42-1,091.09 4.00 236.93 1,300.00 37.00 1,236.74 172.00 -238.80306.05 540,128.256,033,471.89-1,172.99 4.00 294.26 1,400.00 41.00 1,314.44 209.04 -289.65306.08 540,077.196,033,508.65-1,250.69 4.00 357.16 1,500.00 45.00 1,387.56 249.22 -344.74306.12 540,021.896,033,548.52-1,323.81 4.00 425.33 1,508.78 45.35 1,393.75 252.89 -349.77306.12 540,016.846,033,552.16-1,330.00 4.00 431.56 SV5 1,600.00 49.00 1,455.75 292.33 -403.80306.14 539,962.616,033,591.30-1,392.00 4.00 498.44 1,700.00 53.00 1,518.67 338.17 -466.53306.17 539,899.636,033,636.80-1,454.92 4.00 576.11 1,800.00 57.00 1,576.02 386.52 -532.64306.19 539,833.276,033,684.78-1,512.27 4.00 657.99 1,900.00 61.00 1,627.52 437.13 -601.79306.21 539,763.856,033,735.01-1,563.77 4.00 743.67 2,000.00 65.00 1,672.91 489.76 -673.66306.23 539,691.716,033,787.25-1,609.16 4.00 832.72 2,100.00 69.00 1,711.98 544.17 -747.89306.25 539,617.196,033,841.24-1,648.23 4.00 924.73 2,200.00 73.00 1,744.53 600.07 -824.12306.26 539,540.676,033,896.72-1,680.78 4.00 1,019.24 2,248.09 74.92 1,757.82 627.41 -861.38306.27 539,503.266,033,923.86-1,694.07 4.00 1,065.44 End Dir : 2248.09' MD, 1757.82' TVD 2,300.00 74.92 1,771.32 657.06 -901.79306.27 539,462.696,033,953.29-1,707.57 0.00 1,115.55 2,400.00 74.92 1,797.34 714.18 -979.64306.27 539,384.546,034,009.98-1,733.59 0.00 1,212.08 2,500.00 74.92 1,823.35 771.30 -1,057.49306.27 539,306.396,034,066.67-1,759.60 0.00 1,308.61 2,600.00 74.92 1,849.37 828.42 -1,135.34306.27 539,228.246,034,123.36-1,785.62 0.00 1,405.14 2,700.00 74.92 1,875.38 885.55 -1,213.18306.27 539,150.096,034,180.06-1,811.63 0.00 1,501.67 2,724.48 74.92 1,881.75 899.53 -1,232.24306.27 539,130.966,034,193.93-1,818.00 0.00 1,525.30 Base Permafrost 2,800.00 74.92 1,901.40 942.67 -1,291.03306.27 539,071.946,034,236.75-1,837.65 0.00 1,598.20 2,900.00 74.92 1,927.41 999.79 -1,368.88306.27 538,993.796,034,293.44-1,863.66 0.00 1,694.73 3,000.00 74.92 1,953.43 1,056.91 -1,446.73306.27 538,915.646,034,350.13-1,889.68 0.00 1,791.26 3,100.00 74.92 1,979.44 1,114.03 -1,524.58306.27 538,837.496,034,406.83-1,915.69 0.00 1,887.79 3,200.00 74.92 2,005.46 1,171.16 -1,602.42306.27 538,759.346,034,463.52-1,941.71 0.00 1,984.32 3,300.00 74.92 2,031.47 1,228.28 -1,680.27306.27 538,681.206,034,520.21-1,967.72 0.00 2,080.85 3,400.00 74.92 2,057.49 1,285.40 -1,758.12306.27 538,603.056,034,576.90-1,993.74 0.00 2,177.38 3,447.15 74.92 2,069.75 1,312.33 -1,794.82306.27 538,566.206,034,603.63-2,006.00 0.00 2,222.89 SV1 3/6/2025 5:24:42PM 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-106 MPU R-106 Survey Calculation Method:Minimum Curvature R-106 as built RKB @ 63.75usft Design:MPU R-106 wp02 Database:Alaska MD Reference:R-106 as built RKB @ 63.75usft North Reference: Well Plan: MPU R-106 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 -2,019.75 Vert Section 3,500.00 74.92 2,083.50 1,342.52 -1,835.97306.27 538,524.906,034,633.60-2,019.75 0.00 2,273.91 3,600.00 74.92 2,109.51 1,399.64 -1,913.82306.27 538,446.756,034,690.29-2,045.76 0.00 2,370.44 3,700.00 74.92 2,135.53 1,456.76 -1,991.67306.27 538,368.606,034,746.98-2,071.78 0.00 2,466.97 3,800.00 74.92 2,161.54 1,513.89 -2,069.51306.27 538,290.456,034,803.67-2,097.79 0.00 2,563.50 3,900.00 74.92 2,187.56 1,571.01 -2,147.36306.27 538,212.306,034,860.37-2,123.81 0.00 2,660.03 4,000.00 74.92 2,213.57 1,628.13 -2,225.21306.27 538,134.156,034,917.06-2,149.82 0.00 2,756.56 4,100.00 74.92 2,239.59 1,685.25 -2,303.06306.27 538,056.006,034,973.75-2,175.84 0.00 2,853.09 4,200.00 74.92 2,265.60 1,742.37 -2,380.91306.27 537,977.856,035,030.44-2,201.85 0.00 2,949.62 4,255.34 74.92 2,280.00 1,773.99 -2,423.99306.27 537,934.606,035,061.82-2,216.25 0.00 3,003.04 13 3/8" x 16" 4,300.00 74.92 2,291.62 1,799.50 -2,458.75306.27 537,899.706,035,087.14-2,227.87 0.00 3,046.15 4,400.00 74.92 2,317.63 1,856.62 -2,536.60306.27 537,821.556,035,143.83-2,253.88 0.00 3,142.68 4,500.00 74.92 2,343.65 1,913.74 -2,614.45306.27 537,743.406,035,200.52-2,279.90 0.00 3,239.21 4,600.00 74.92 2,369.66 1,970.86 -2,692.30306.27 537,665.256,035,257.21-2,305.91 0.00 3,335.74 4,700.00 74.92 2,395.68 2,027.98 -2,770.15306.27 537,587.106,035,313.91-2,331.93 0.00 3,432.27 4,715.66 74.92 2,399.75 2,036.93 -2,782.34306.27 537,574.866,035,322.79-2,336.00 0.00 3,447.39 UG4A 4,800.00 74.92 2,421.69 2,085.10 -2,847.99306.27 537,508.956,035,370.60-2,357.94 0.00 3,528.80 4,900.00 74.92 2,447.71 2,142.23 -2,925.84306.27 537,430.806,035,427.29-2,383.96 0.00 3,625.33 5,000.00 74.92 2,473.72 2,199.35 -3,003.69306.27 537,352.656,035,483.98-2,409.97 0.00 3,721.86 5,100.00 74.92 2,499.73 2,256.47 -3,081.54306.27 537,274.506,035,540.68-2,435.98 0.00 3,818.39 5,200.00 74.92 2,525.75 2,313.59 -3,159.39306.27 537,196.356,035,597.37-2,462.00 0.00 3,914.92 5,300.00 74.92 2,551.76 2,370.71 -3,237.24306.27 537,118.206,035,654.06-2,488.01 0.00 4,011.45 5,400.00 74.92 2,577.78 2,427.84 -3,315.08306.27 537,040.056,035,710.75-2,514.03 0.00 4,107.98 5,500.00 74.92 2,603.79 2,484.96 -3,392.93306.27 536,961.906,035,767.45-2,540.04 0.00 4,204.51 5,600.00 74.92 2,629.81 2,542.08 -3,470.78306.27 536,883.756,035,824.14-2,566.06 0.00 4,301.04 5,700.00 74.92 2,655.82 2,599.20 -3,548.63306.27 536,805.606,035,880.83-2,592.07 0.00 4,397.57 5,800.00 74.92 2,681.84 2,656.32 -3,626.48306.27 536,727.456,035,937.52-2,618.09 0.00 4,494.10 5,900.00 74.92 2,707.85 2,713.45 -3,704.32306.27 536,649.316,035,994.22-2,644.10 0.00 4,590.63 6,000.00 74.92 2,733.87 2,770.57 -3,782.17306.27 536,571.166,036,050.91-2,670.12 0.00 4,687.16 6,100.00 74.92 2,759.88 2,827.69 -3,860.02306.27 536,493.016,036,107.60-2,696.13 0.00 4,783.70 6,200.00 74.92 2,785.90 2,884.81 -3,937.87306.27 536,414.866,036,164.30-2,722.15 0.00 4,880.23 6,300.00 74.92 2,811.91 2,941.93 -4,015.72306.27 536,336.716,036,220.99-2,748.16 0.00 4,976.76 6,400.00 74.92 2,837.93 2,999.05 -4,093.56306.27 536,258.566,036,277.68-2,774.18 0.00 5,073.29 6,500.00 74.92 2,863.94 3,056.18 -4,171.41306.27 536,180.416,036,334.37-2,800.19 0.00 5,169.82 6,600.00 74.92 2,889.95 3,113.30 -4,249.26306.27 536,102.266,036,391.07-2,826.20 0.00 5,266.35 6,700.00 74.92 2,915.97 3,170.42 -4,327.11306.27 536,024.116,036,447.76-2,852.22 0.00 5,362.88 6,800.00 74.92 2,941.98 3,227.54 -4,404.96306.27 535,945.966,036,504.45-2,878.23 0.00 5,459.41 6,900.00 74.92 2,968.00 3,284.66 -4,482.81306.27 535,867.816,036,561.14-2,904.25 0.00 5,555.94 7,000.00 74.92 2,994.01 3,341.79 -4,560.65306.27 535,789.666,036,617.84-2,930.26 0.00 5,652.47 7,100.00 74.92 3,020.03 3,398.91 -4,638.50306.27 535,711.516,036,674.53-2,956.28 0.00 5,749.00 7,200.00 74.92 3,046.04 3,456.03 -4,716.35306.27 535,633.366,036,731.22-2,982.29 0.00 5,845.53 7,300.00 74.92 3,072.06 3,513.15 -4,794.20306.27 535,555.216,036,787.91-3,008.31 0.00 5,942.06 7,400.00 74.92 3,098.07 3,570.27 -4,872.05306.27 535,477.066,036,844.61-3,034.32 0.00 6,038.59 7,500.00 74.92 3,124.09 3,627.39 -4,949.89306.27 535,398.916,036,901.30-3,060.34 0.00 6,135.12 3/6/2025 5:24:42PM 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-106 MPU R-106 Survey Calculation Method:Minimum Curvature R-106 as built RKB @ 63.75usft Design:MPU R-106 wp02 Database:Alaska MD Reference:R-106 as built RKB @ 63.75usft North Reference: Well Plan: MPU R-106 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 -3,086.35 Vert Section 7,600.00 74.92 3,150.10 3,684.52 -5,027.74306.27 535,320.766,036,957.99-3,086.35 0.00 6,231.65 7,700.00 74.92 3,176.12 3,741.64 -5,105.59306.27 535,242.616,037,014.68-3,112.37 0.00 6,328.18 7,800.00 74.92 3,202.13 3,798.76 -5,183.44306.27 535,164.466,037,071.38-3,138.38 0.00 6,424.71 7,900.00 74.92 3,228.15 3,855.88 -5,261.29306.27 535,086.316,037,128.07-3,164.40 0.00 6,521.24 8,000.00 74.92 3,254.16 3,913.00 -5,339.13306.27 535,008.166,037,184.76-3,190.41 0.00 6,617.77 8,100.00 74.92 3,280.17 3,970.13 -5,416.98306.27 534,930.016,037,241.45-3,216.42 0.00 6,714.30 8,200.00 74.92 3,306.19 4,027.25 -5,494.83306.27 534,851.866,037,298.15-3,242.44 0.00 6,810.83 8,300.00 74.92 3,332.20 4,084.37 -5,572.68306.27 534,773.716,037,354.84-3,268.45 0.00 6,907.36 8,400.00 74.92 3,358.22 4,141.49 -5,650.53306.27 534,695.566,037,411.53-3,294.47 0.00 7,003.89 8,413.57 74.92 3,361.75 4,149.25 -5,661.09306.27 534,684.966,037,419.23-3,298.00 0.00 7,016.99 LA3 8,500.00 74.92 3,384.23 4,198.61 -5,728.38306.27 534,617.416,037,468.22-3,320.48 0.00 7,100.42 8,600.00 74.92 3,410.25 4,255.74 -5,806.22306.27 534,539.276,037,524.92-3,346.50 0.00 7,196.95 8,700.00 74.92 3,436.26 4,312.86 -5,884.07306.27 534,461.126,037,581.61-3,372.51 0.00 7,293.48 8,800.00 74.92 3,462.28 4,369.98 -5,961.92306.27 534,382.976,037,638.30-3,398.53 0.00 7,390.01 8,900.00 74.92 3,488.29 4,427.10 -6,039.77306.27 534,304.826,037,694.99-3,424.54 0.00 7,486.54 9,000.00 74.92 3,514.31 4,484.22 -6,117.62306.27 534,226.676,037,751.69-3,450.56 0.00 7,583.07 9,100.00 74.92 3,540.32 4,541.34 -6,195.46306.27 534,148.526,037,808.38-3,476.57 0.00 7,679.60 9,128.56 74.92 3,547.75 4,557.66 -6,217.69306.27 534,126.206,037,824.57-3,484.00 0.00 7,707.17 UG_MB 9,200.00 74.92 3,566.34 4,598.47 -6,273.31306.27 534,070.376,037,865.07-3,502.59 0.00 7,776.13 9,300.00 74.92 3,592.35 4,655.59 -6,351.16306.27 533,992.226,037,921.76-3,528.60 0.00 7,872.66 9,400.00 74.92 3,618.37 4,712.71 -6,429.01306.27 533,914.076,037,978.46-3,554.62 0.00 7,969.19 9,500.00 74.92 3,644.38 4,769.83 -6,506.86306.27 533,835.926,038,035.15-3,580.63 0.00 8,065.72 9,600.00 74.92 3,670.39 4,826.95 -6,584.70306.27 533,757.776,038,091.84-3,606.64 0.00 8,162.25 9,700.00 74.92 3,696.41 4,884.08 -6,662.55306.27 533,679.626,038,148.53-3,632.66 0.00 8,258.78 9,800.00 74.92 3,722.42 4,941.20 -6,740.40306.27 533,601.476,038,205.23-3,658.67 0.00 8,355.31 9,900.00 74.92 3,748.44 4,998.32 -6,818.25306.27 533,523.326,038,261.92-3,684.69 0.00 8,451.84 10,000.00 74.92 3,774.45 5,055.44 -6,896.10306.27 533,445.176,038,318.61-3,710.70 0.00 8,548.37 10,100.00 74.92 3,800.47 5,112.56 -6,973.95306.27 533,367.026,038,375.30-3,736.72 0.00 8,644.90 10,135.68 74.92 3,809.75 5,132.94 -7,001.72306.27 533,339.146,038,395.53-3,746.00 0.00 8,679.34 UG_MF 10,200.00 74.92 3,826.48 5,169.68 -7,051.79306.27 533,288.876,038,432.00-3,762.73 0.00 8,741.43 10,289.44 74.92 3,849.75 5,220.77 -7,121.42306.27 533,218.986,038,482.70-3,786.00 0.00 8,827.77 SB_Na 10,300.00 74.92 3,852.50 5,226.81 -7,129.64306.27 533,210.726,038,488.69-3,788.75 0.00 8,837.96 10,400.00 74.92 3,878.51 5,283.93 -7,207.49306.27 533,132.576,038,545.38-3,814.76 0.00 8,934.49 10,507.60 74.92 3,906.50 5,345.39 -7,291.25306.27 533,048.486,038,606.38-3,842.75 0.00 9,038.36 Start Dir 4º/100' : 10507.6' MD, 3906.5'TVD 10,600.00 78.54 3,927.71 5,398.09 -7,364.11305.50 532,975.356,038,658.68-3,863.96 4.00 9,128.26 10,700.00 82.46 3,944.21 5,454.78 -7,444.79304.69 532,894.376,038,714.93-3,880.46 4.00 9,226.87 10,790.29 86.00 3,953.29 5,505.44 -7,518.96303.97 532,819.936,038,765.17-3,889.54 4.00 9,316.69 End Dir : 10790.29' MD, 3953.29' TVD 10,800.00 86.00 3,953.96 5,510.85 -7,527.00303.97 532,811.876,038,770.54-3,890.21 0.00 9,326.37 3/6/2025 5:24:42PM 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-106 MPU R-106 Survey Calculation Method:Minimum Curvature R-106 as built RKB @ 63.75usft Design:MPU R-106 wp02 Database:Alaska MD Reference:R-106 as built RKB @ 63.75usft North Reference: Well Plan: MPU R-106 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 -3,896.00 Vert Section 10,882.95 86.00 3,959.75 5,557.08 -7,595.62303.97 532,743.006,038,816.40-3,896.00 0.00 9,409.11 SB_Oa 10,900.00 86.00 3,960.94 5,566.59 -7,609.73303.97 532,728.846,038,825.82-3,897.19 0.00 9,426.11 10,940.29 86.00 3,963.75 5,589.05 -7,643.06303.97 532,695.396,038,848.10-3,900.00 0.00 9,466.30 10,941.00 86.02 3,963.80 5,589.44 -7,643.65303.97 532,694.806,038,848.49-3,900.05 2.50 9,467.01 Begin Geosteering 11,000.00 87.49 3,967.14 5,622.36 -7,692.50303.98 532,645.786,038,881.14-3,903.39 2.50 9,525.90 11,100.00 89.99 3,969.33 5,678.23 -7,775.39303.99 532,562.596,038,936.56-3,905.58 2.50 9,625.86 9 5/8" x 12 1/4" 11,111.52 90.28 3,969.31 5,684.67 -7,784.94303.99 532,553.016,038,942.94-3,905.56 2.50 9,637.37 11,200.00 90.28 3,968.87 5,734.14 -7,858.30303.99 532,479.396,038,992.00-3,905.12 0.00 9,725.84 11,300.00 90.28 3,968.38 5,790.04 -7,941.22303.99 532,396.186,039,047.45-3,904.63 0.00 9,825.83 11,400.00 90.28 3,967.89 5,845.94 -8,024.13303.99 532,312.976,039,102.90-3,904.14 0.00 9,925.81 11,500.00 90.28 3,967.40 5,901.85 -8,107.04303.99 532,229.766,039,158.34-3,903.65 0.00 10,025.80 11,600.00 90.28 3,966.91 5,957.75 -8,189.96303.99 532,146.566,039,213.79-3,903.16 0.00 10,125.79 11,700.00 90.28 3,966.42 6,013.65 -8,272.87303.99 532,063.356,039,269.24-3,902.67 0.00 10,225.77 11,800.00 90.28 3,965.93 6,069.56 -8,355.78303.99 531,980.146,039,324.68-3,902.18 0.00 10,325.76 11,900.00 90.28 3,965.44 6,125.46 -8,438.70303.99 531,896.936,039,380.13-3,901.69 0.00 10,425.74 12,000.00 90.28 3,964.95 6,181.36 -8,521.61303.99 531,813.736,039,435.58-3,901.20 0.00 10,525.73 12,100.00 90.28 3,964.47 6,237.27 -8,604.52303.99 531,730.526,039,491.02-3,900.72 0.00 10,625.71 12,200.00 90.28 3,963.98 6,293.17 -8,687.44303.99 531,647.316,039,546.47-3,900.23 0.00 10,725.70 12,246.04 90.28 3,963.75 6,318.91 -8,725.61303.99 531,609.006,039,572.00-3,900.00 0.00 10,771.74 12,300.00 88.94 3,964.12 6,349.02 -8,770.38303.86 531,564.076,039,601.86-3,900.37 2.50 10,825.68 12,355.42 87.56 3,965.81 6,379.83 -8,816.41303.72 531,517.886,039,632.42-3,902.06 2.50 10,881.06 12,400.00 87.56 3,967.71 6,404.56 -8,853.46303.72 531,480.706,039,656.94-3,903.96 0.00 10,925.59 12,500.00 87.56 3,971.97 6,460.02 -8,936.56303.72 531,397.316,039,711.95-3,908.22 0.00 11,025.48 12,582.58 87.56 3,975.49 6,505.83 -9,005.18303.72 531,328.446,039,757.38-3,911.74 0.00 11,107.97 12,600.00 87.99 3,976.16 6,515.50 -9,019.66303.77 531,313.926,039,766.97-3,912.41 2.50 11,125.37 12,692.37 90.29 3,977.55 6,566.99 -9,096.33304.00 531,236.986,039,818.04-3,913.80 2.50 11,217.71 12,700.00 90.29 3,977.51 6,571.25 -9,102.65304.00 531,230.636,039,822.27-3,913.76 0.00 11,225.34 12,800.00 90.29 3,977.00 6,627.17 -9,185.55304.00 531,147.446,039,877.73-3,913.25 0.00 11,325.32 12,900.00 90.29 3,976.50 6,683.09 -9,268.46304.00 531,064.246,039,933.19-3,912.75 0.00 11,425.31 13,000.00 90.29 3,975.99 6,739.01 -9,351.36304.00 530,981.046,039,988.65-3,912.24 0.00 11,525.30 13,100.00 90.29 3,975.48 6,794.93 -9,434.26304.00 530,897.846,040,044.11-3,911.73 0.00 11,625.28 13,200.00 90.29 3,974.98 6,850.84 -9,517.16304.00 530,814.656,040,099.57-3,911.23 0.00 11,725.27 13,300.00 90.29 3,974.47 6,906.76 -9,600.07304.00 530,731.456,040,155.04-3,910.72 0.00 11,825.25 13,400.00 90.29 3,973.96 6,962.68 -9,682.97304.00 530,648.256,040,210.50-3,910.21 0.00 11,925.24 13,442.37 90.29 3,973.75 6,986.38 -9,718.10304.00 530,613.006,040,234.00-3,910.00 0.00 11,967.61 13,495.86 88.95 3,974.10 7,016.28 -9,762.44303.99 530,568.506,040,263.66-3,910.35 2.50 12,021.09 13,500.00 88.95 3,974.18 7,018.60 -9,765.87303.99 530,565.066,040,265.96-3,910.43 0.00 12,025.22 13,600.00 88.95 3,976.01 7,074.50 -9,848.77303.99 530,481.876,040,321.40-3,912.26 0.00 12,125.19 13,700.00 88.95 3,977.83 7,130.40 -9,931.66303.99 530,398.686,040,376.85-3,914.08 0.00 12,225.16 13,733.16 88.95 3,978.44 7,148.93 -9,959.15303.99 530,371.096,040,395.23-3,914.69 0.00 12,258.31 13,800.00 90.62 3,978.69 7,186.29 -10,014.57303.97 530,315.476,040,432.28-3,914.94 2.50 12,325.14 13,812.65 90.94 3,978.51 7,193.36 -10,025.06303.97 530,304.946,040,439.30-3,914.76 2.50 12,337.79 3/6/2025 5:24:42PM 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-106 MPU R-106 Survey Calculation Method:Minimum Curvature R-106 as built RKB @ 63.75usft Design:MPU R-106 wp02 Database:Alaska MD Reference:R-106 as built RKB @ 63.75usft North Reference: Well Plan: MPU R-106 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 -3,913.33 Vert Section 13,900.00 90.94 3,977.08 7,242.16 -10,097.50303.97 530,232.266,040,487.70-3,913.33 0.00 12,425.11 14,000.00 90.94 3,975.44 7,298.03 -10,180.42303.97 530,149.046,040,543.11-3,911.69 0.00 12,525.09 14,100.00 90.94 3,973.80 7,353.90 -10,263.34303.97 530,065.826,040,598.52-3,910.05 0.00 12,625.06 14,200.00 90.94 3,972.16 7,409.77 -10,346.26303.97 529,982.616,040,653.93-3,908.41 0.00 12,725.03 14,300.00 90.94 3,970.52 7,465.64 -10,429.18303.97 529,899.396,040,709.34-3,906.77 0.00 12,825.01 14,400.00 90.94 3,968.88 7,521.50 -10,512.10303.97 529,816.186,040,764.75-3,905.13 0.00 12,924.98 14,500.00 90.94 3,967.24 7,577.37 -10,595.03303.97 529,732.966,040,820.17-3,903.49 0.00 13,024.95 14,600.00 90.94 3,965.60 7,633.24 -10,677.95303.97 529,649.746,040,875.58-3,901.85 0.00 13,124.92 14,700.00 90.94 3,963.96 7,689.11 -10,760.87303.97 529,566.536,040,930.99-3,900.21 0.00 13,224.90 14,712.65 90.94 3,963.75 7,696.18 -10,771.36303.97 529,556.006,040,938.00-3,900.00 0.00 13,237.54 14,800.00 88.76 3,963.98 7,744.96 -10,843.81303.94 529,483.296,040,986.38-3,900.23 2.50 13,324.87 14,883.89 86.66 3,967.34 7,791.73 -10,913.37303.90 529,413.496,041,032.77-3,903.59 2.50 13,408.68 14,900.00 86.66 3,968.27 7,800.70 -10,926.72303.90 529,400.106,041,041.67-3,904.52 0.00 13,424.76 15,000.00 86.66 3,974.10 7,856.38 -11,009.57303.90 529,316.946,041,096.89-3,910.35 0.00 13,524.57 15,012.92 86.66 3,974.85 7,863.57 -11,020.28303.90 529,306.206,041,104.03-3,911.10 0.00 13,537.47 15,100.00 88.84 3,978.28 7,912.15 -11,092.47303.97 529,233.766,041,152.20-3,914.53 2.50 13,624.46 15,146.59 90.00 3,978.75 7,938.19 -11,131.10304.00 529,194.996,041,178.03-3,915.00 2.50 13,671.05 15,200.00 90.00 3,978.75 7,968.05 -11,175.38304.00 529,150.556,041,207.65-3,915.00 0.00 13,724.45 15,300.00 90.00 3,978.75 8,023.97 -11,258.28304.00 529,067.356,041,263.11-3,915.00 0.00 13,824.44 15,400.00 90.00 3,978.75 8,079.89 -11,341.18304.00 528,984.166,041,318.58-3,915.00 0.00 13,924.42 15,500.00 90.00 3,978.75 8,135.81 -11,424.09304.00 528,900.966,041,374.04-3,915.00 0.00 14,024.41 15,600.00 90.00 3,978.75 8,191.73 -11,506.99304.00 528,817.766,041,429.50-3,915.00 0.00 14,124.40 15,700.00 90.00 3,978.75 8,247.65 -11,589.90304.00 528,734.566,041,484.96-3,915.00 0.00 14,224.38 15,800.00 90.00 3,978.75 8,303.57 -11,672.80304.00 528,651.366,041,540.43-3,915.00 0.00 14,324.37 15,896.59 90.00 3,978.75 8,357.58 -11,752.88304.00 528,571.006,041,594.00-3,915.00 0.00 14,420.95 15,900.00 90.09 3,978.75 8,359.49 -11,755.70303.99 528,568.176,041,595.89-3,915.00 2.50 14,424.36 16,000.00 92.58 3,976.42 8,415.27 -11,838.66303.84 528,484.926,041,651.21-3,912.67 2.50 14,524.31 16,026.87 93.25 3,975.06 8,430.21 -11,860.95303.80 528,462.546,041,666.03-3,911.31 2.50 14,551.14 16,100.00 93.25 3,970.91 8,470.82 -11,921.62303.80 528,401.666,041,706.31-3,907.16 0.00 14,624.14 16,135.22 93.25 3,968.91 8,490.38 -11,950.84303.80 528,372.346,041,725.71-3,905.16 0.00 14,659.29 16,200.00 91.63 3,966.15 8,526.42 -12,004.60303.87 528,318.396,041,761.45-3,902.40 2.50 14,724.00 16,287.80 89.44 3,965.33 8,575.41 -12,077.45303.97 528,245.286,041,810.04-3,901.58 2.50 14,811.78 16,300.00 89.44 3,965.45 8,582.23 -12,087.57303.97 528,235.136,041,816.80-3,901.70 0.00 14,823.98 16,400.00 89.44 3,966.43 8,638.10 -12,170.50303.97 528,151.916,041,872.22-3,902.68 0.00 14,923.96 16,500.00 89.44 3,967.40 8,693.98 -12,253.43303.97 528,068.686,041,927.64-3,903.65 0.00 15,023.94 16,600.00 89.44 3,968.38 8,749.85 -12,336.36303.97 527,985.466,041,983.05-3,904.63 0.00 15,123.92 16,637.80 89.44 3,968.75 8,770.97 -12,367.70303.97 527,954.006,042,004.00-3,905.00 0.00 15,161.71 16,700.00 87.89 3,970.20 8,805.74 -12,419.25304.04 527,902.276,042,038.49-3,906.45 2.50 15,223.89 16,761.36 86.35 3,973.28 8,840.08 -12,470.01304.11 527,851.336,042,072.54-3,909.53 2.50 15,285.16 16,800.00 86.35 3,975.74 8,861.70 -12,501.94304.11 527,819.286,042,093.99-3,911.99 0.00 15,323.72 16,900.00 86.35 3,982.10 8,917.66 -12,584.57304.11 527,736.366,042,149.49-3,918.35 0.00 15,423.50 17,000.00 86.35 3,988.46 8,973.62 -12,667.21304.11 527,653.436,042,205.00-3,924.71 0.00 15,523.29 17,049.12 86.35 3,991.58 9,001.10 -12,707.80304.11 527,612.706,042,232.26-3,927.83 0.00 15,572.31 17,100.00 87.63 3,994.26 9,029.58 -12,749.88304.06 527,570.466,042,260.50-3,930.51 2.50 15,623.11 17,200.00 90.12 3,996.22 9,085.49 -12,832.75303.96 527,487.306,042,315.96-3,932.47 2.50 15,723.07 3/6/2025 5:24:42PM 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-106 MPU R-106 Survey Calculation Method:Minimum Curvature R-106 as built RKB @ 63.75usft Design:MPU R-106 wp02 Database:Alaska MD Reference:R-106 as built RKB @ 63.75usft North Reference: Well Plan: MPU R-106 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 -3,932.17 Vert Section 17,232.30 90.93 3,995.92 9,103.53 -12,859.54303.93 527,460.416,042,333.85-3,932.17 2.50 15,755.36 17,300.00 90.93 3,994.82 9,141.31 -12,915.71303.93 527,404.056,042,371.32-3,931.07 0.00 15,823.05 17,400.00 90.93 3,993.20 9,197.12 -12,998.67303.93 527,320.796,042,426.68-3,929.45 0.00 15,923.02 17,500.00 90.93 3,991.58 9,252.93 -13,081.63303.93 527,237.546,042,482.03-3,927.83 0.00 16,022.99 17,600.00 90.93 3,989.96 9,308.74 -13,164.59303.93 527,154.286,042,537.38-3,926.21 0.00 16,122.96 17,700.00 90.93 3,988.33 9,364.55 -13,247.55303.93 527,071.036,042,592.74-3,924.58 0.00 16,222.93 17,800.00 90.93 3,986.71 9,420.37 -13,330.51303.93 526,987.776,042,648.09-3,922.96 0.00 16,322.90 17,900.00 90.93 3,985.09 9,476.18 -13,413.47303.93 526,904.526,042,703.45-3,921.34 0.00 16,422.88 17,982.30 90.93 3,983.75 9,522.11 -13,481.75303.93 526,836.006,042,749.00-3,920.00 0.00 16,505.15 18,000.00 90.49 3,983.53 9,531.99 -13,496.43303.95 526,821.266,042,758.80-3,919.78 2.50 16,522.85 18,029.94 89.74 3,983.47 9,548.72 -13,521.27303.98 526,796.346,042,775.39-3,919.72 2.50 16,552.79 18,100.00 89.74 3,983.79 9,587.88 -13,579.36303.98 526,738.056,042,814.23-3,920.04 0.00 16,622.84 18,200.00 89.74 3,984.24 9,643.77 -13,662.28303.98 526,654.836,042,869.67-3,920.49 0.00 16,722.82 18,300.00 89.74 3,984.70 9,699.67 -13,745.19303.98 526,571.626,042,925.11-3,920.95 0.00 16,822.81 18,400.00 89.74 3,985.15 9,755.57 -13,828.11303.98 526,488.416,042,980.55-3,921.40 0.00 16,922.79 18,500.00 89.74 3,985.60 9,811.46 -13,911.03303.98 526,405.206,043,035.99-3,921.85 0.00 17,022.78 18,600.00 89.74 3,986.06 9,867.36 -13,993.95303.98 526,321.986,043,091.43-3,922.31 0.00 17,122.76 18,700.00 89.74 3,986.51 9,923.26 -14,076.87303.98 526,238.776,043,146.87-3,922.76 0.00 17,222.75 18,800.00 89.74 3,986.96 9,979.15 -14,159.78303.98 526,155.566,043,202.31-3,923.21 0.00 17,322.73 18,900.00 89.74 3,987.42 10,035.05 -14,242.70303.98 526,072.356,043,257.75-3,923.67 0.00 17,422.72 19,000.00 89.74 3,987.87 10,090.95 -14,325.62303.98 525,989.146,043,313.19-3,924.12 0.00 17,522.71 19,100.00 89.74 3,988.32 10,146.84 -14,408.54303.98 525,905.926,043,368.63-3,924.57 0.00 17,622.69 19,200.00 89.74 3,988.78 10,202.74 -14,491.46303.98 525,822.716,043,424.07-3,925.03 0.00 17,722.68 19,300.00 89.74 3,989.23 10,258.63 -14,574.37303.98 525,739.506,043,479.51-3,925.48 0.00 17,822.66 19,400.00 89.74 3,989.68 10,314.53 -14,657.29303.98 525,656.296,043,534.95-3,925.93 0.00 17,922.65 19,500.00 89.74 3,990.14 10,370.43 -14,740.21303.98 525,573.076,043,590.39-3,926.39 0.00 18,022.63 19,581.60 89.74 3,990.51 10,416.04 -14,807.87303.98 525,505.176,043,635.63-3,926.76 0.00 18,104.22 19,593.25 89.45 3,990.59 10,422.55 -14,817.53303.96 525,495.486,043,642.08-3,926.84 2.50 18,115.87 19,600.00 89.45 3,990.66 10,426.32 -14,823.13303.96 525,489.866,043,645.82-3,926.91 0.00 18,122.62 19,700.00 89.45 3,991.62 10,482.18 -14,906.07303.96 525,406.636,043,701.23-3,927.87 0.00 18,222.60 19,800.00 89.45 3,992.58 10,538.04 -14,989.01303.96 525,323.396,043,756.63-3,928.83 0.00 18,322.58 19,900.00 89.45 3,993.54 10,593.90 -15,071.95303.96 525,240.166,043,812.03-3,929.79 0.00 18,422.56 20,000.00 89.45 3,994.50 10,649.75 -15,154.89303.96 525,156.936,043,867.43-3,930.75 0.00 18,522.54 20,100.00 89.45 3,995.46 10,705.61 -15,237.82303.96 525,073.696,043,922.83-3,931.71 0.00 18,622.53 20,200.00 89.45 3,996.42 10,761.47 -15,320.76303.96 524,990.466,043,978.24-3,932.67 0.00 18,722.51 20,300.00 89.45 3,997.37 10,817.33 -15,403.70303.96 524,907.236,044,033.64-3,933.62 0.00 18,822.49 20,400.00 89.45 3,998.33 10,873.19 -15,486.64303.96 524,824.006,044,089.04-3,934.58 0.00 18,922.47 20,443.25 89.45 3,998.75 10,897.35 -15,522.51303.96 524,788.006,044,113.00-3,935.00 0.00 18,965.71 20,500.00 88.03 4,000.00 10,929.03 -15,569.58303.93 524,740.766,044,144.42-3,936.25 2.50 19,022.44 20,588.87 85.81 4,004.77 10,978.52 -15,643.23303.88 524,666.866,044,193.51-3,941.02 2.50 19,111.16 20,600.00 85.81 4,005.58 10,984.71 -15,652.44303.88 524,657.616,044,199.65-3,941.83 0.00 19,122.26 20,696.36 85.81 4,012.62 11,038.28 -15,732.23303.88 524,577.546,044,252.78-3,948.87 0.00 19,218.35 20,700.00 85.90 4,012.89 11,040.31 -15,735.24303.88 524,574.516,044,254.79-3,949.14 2.50 19,221.97 20,800.00 88.40 4,017.86 11,096.03 -15,818.12303.95 524,491.346,044,310.05-3,954.11 2.50 19,321.83 20,864.00 90.00 4,018.75 11,131.79 -15,871.20303.99 524,438.086,044,345.52-3,955.00 2.50 19,385.81 3/6/2025 5:24:42PM 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-106 MPU R-106 Survey Calculation Method:Minimum Curvature R-106 as built RKB @ 63.75usft Design:MPU R-106 wp02 Database:Alaska MD Reference:R-106 as built RKB @ 63.75usft North Reference: Well Plan: MPU R-106 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 -3,955.00 Vert Section 20,900.00 90.00 4,018.75 11,151.91 -15,901.04303.99 524,408.136,044,365.48-3,955.00 0.00 19,421.81 21,000.00 90.00 4,018.75 11,207.81 -15,983.96303.99 524,324.926,044,420.93-3,955.00 0.00 19,521.79 21,100.00 90.00 4,018.75 11,263.72 -16,066.87303.99 524,241.716,044,476.37-3,955.00 0.00 19,621.78 21,200.00 90.00 4,018.75 11,319.62 -16,149.78303.99 524,158.506,044,531.82-3,955.00 0.00 19,721.77 21,300.00 90.00 4,018.75 11,375.53 -16,232.70303.99 524,075.306,044,587.27-3,955.00 0.00 19,821.75 21,400.00 90.00 4,018.75 11,431.43 -16,315.61303.99 523,992.096,044,642.72-3,955.00 0.00 19,921.74 21,500.00 90.00 4,018.75 11,487.34 -16,398.52303.99 523,908.886,044,698.17-3,955.00 0.00 20,021.73 21,600.00 90.00 4,018.75 11,543.24 -16,481.44303.99 523,825.676,044,753.61-3,955.00 0.00 20,121.71 21,700.00 90.00 4,018.75 11,599.15 -16,564.35303.99 523,742.466,044,809.06-3,955.00 0.00 20,221.70 21,800.00 90.00 4,018.75 11,655.05 -16,647.26303.99 523,659.266,044,864.51-3,955.00 0.00 20,321.69 21,864.00 90.00 4,018.75 11,690.83 -16,700.33303.99 523,606.006,044,900.00-3,955.00 0.00 20,385.68 21,900.00 90.90 4,018.47 11,710.95 -16,730.18303.97 523,576.056,044,919.95-3,954.72 2.50 20,421.67 22,000.00 93.40 4,014.72 11,766.74 -16,813.08303.91 523,492.856,044,975.28-3,950.97 2.50 20,521.58 22,022.32 93.96 4,013.29 11,779.16 -16,831.57303.90 523,474.306,044,987.60-3,949.54 2.50 20,543.85 22,100.00 93.96 4,007.93 11,822.38 -16,895.89303.90 523,409.756,045,030.47-3,944.18 0.00 20,621.33 22,185.16 93.96 4,002.05 11,869.76 -16,966.41303.90 523,338.986,045,077.46-3,938.30 0.00 20,706.28 22,200.00 93.59 4,001.07 11,878.02 -16,978.70303.90 523,326.656,045,085.65-3,937.32 2.50 20,721.08 22,300.00 91.09 3,997.00 11,933.78 -17,061.60303.95 523,243.456,045,140.96-3,933.25 2.50 20,820.97 22,315.06 90.71 3,996.76 11,942.19 -17,074.09303.96 523,230.926,045,149.30-3,933.01 2.50 20,836.03 22,400.00 90.71 3,995.71 11,989.64 -17,144.54303.96 523,160.226,045,196.35-3,931.96 0.00 20,920.95 22,500.00 90.71 3,994.47 12,045.49 -17,227.47303.96 523,076.996,045,251.75-3,930.72 0.00 21,020.93 22,600.00 90.71 3,993.23 12,101.35 -17,310.41303.96 522,993.766,045,307.16-3,929.48 0.00 21,120.91 22,700.00 90.71 3,991.99 12,157.21 -17,393.35303.96 522,910.536,045,362.56-3,928.24 0.00 21,220.89 22,800.00 90.71 3,990.75 12,213.06 -17,476.28303.96 522,827.306,045,417.96-3,927.00 0.00 21,320.86 22,900.00 90.71 3,989.51 12,268.92 -17,559.22303.96 522,744.076,045,473.36-3,925.76 0.00 21,420.84 23,000.00 90.71 3,988.27 12,324.78 -17,642.15303.96 522,660.846,045,528.76-3,924.52 0.00 21,520.82 23,100.00 90.71 3,987.03 12,380.63 -17,725.09303.96 522,577.616,045,584.16-3,923.28 0.00 21,620.80 23,200.00 90.71 3,985.80 12,436.49 -17,808.03303.96 522,494.386,045,639.56-3,922.05 0.00 21,720.78 23,300.00 90.71 3,984.56 12,492.35 -17,890.96303.96 522,411.156,045,694.96-3,920.81 0.00 21,820.76 23,365.06 90.71 3,983.75 12,528.69 -17,944.92303.96 522,357.006,045,731.00-3,920.00 0.00 21,885.80 Total Depth : 23365.06' MD, 3983.75' TVD 3/6/2025 5:24:42PM 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-106 MPU R-106 Survey Calculation Method:Minimum Curvature R-106 as built RKB @ 63.75usft Design:MPU R-106 wp02 Database:Alaska MD Reference:R-106 as built RKB @ 63.75usft North Reference: Well Plan: MPU R-106 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-106 wp02 tgt20 3,983.75 6,045,731.00 522,357.0012,528.69 -17,944.920.00 0.00 - plan hits target center - Point MPR-106 wp02 tgt02 3,963.75 6,039,572.00 531,609.006,318.91 -8,725.610.00 0.00 - plan hits target center - Point MPR-106 wp02 tgt01 3,963.75 6,038,848.10 532,695.395,589.05 -7,643.060.00 0.00 - plan hits target center - Point MPR-106 wp02 tgt14 4,003.75 6,043,418.00 525,830.0010,196.63 -14,484.200.00 0.00 - plan misses target center by 15.05usft at 19190.64usft MD (3988.74 TVD, 10197.50 N, -14483.69 E) - Point MPR-106 wp02 tgt17 4,018.75 6,044,233.00 524,607.0011,018.34 -15,702.870.00 0.00 - plan misses target center by 8.71usft at 20661.41usft MD (4010.07 TVD, 11018.85 N, -15703.29 E) - Point MPR-106 wp02 tgt09 3,963.75 6,041,723.00 528,376.008,487.65 -11,947.190.00 0.00 - plan misses target center by 5.42usft at 16130.97usft MD (3969.15 TVD, 8488.02 N, -11947.32 E) - Point MPR-106 wp02 tgt10 3,968.75 6,042,004.00 527,954.008,770.97 -12,367.700.00 0.00 - plan hits target center - Point MPR-106 wp02 tgt15 3,988.75 6,043,534.00 525,658.0010,313.57 -14,655.580.00 0.00 - plan misses target center by 0.94usft at 19398.04usft MD (3989.68 TVD, 10313.44 N, -14655.67 E) - Point MPR-106 wp02 tgt08 3,978.75 6,041,594.00 528,571.008,357.58 -11,752.880.00 0.00 - plan hits target center - Point MPR-106 wp02 tgt16 3,998.75 6,044,113.00 524,788.0010,897.35 -15,522.510.00 0.00 - plan hits target center - Point MPR-106 wp02 tgt12 3,983.75 6,042,749.00 526,836.009,522.11 -13,481.750.00 0.00 - plan hits target center - Point MPR-106 wp02 tgt05 3,978.75 6,040,430.00 530,319.007,183.99 -10,011.060.00 0.00 - plan misses target center by 0.06usft at 13795.80usft MD (3978.73 TVD, 7183.95 N, -10011.09 E) - Point MPR-106 wp02 tgt18 4,018.75 6,044,900.00 523,606.0011,690.83 -16,700.330.00 0.00 - plan hits target center - Point MPR-106 wp02 tgt11 3,998.75 6,042,237.00 527,606.009,005.88 -12,714.470.00 0.00 - plan misses target center by 6.65usft at 17057.69usft MD (3992.11 TVD, 9005.90 N, -12714.88 E) - Point MPR-106 wp02 tgt13 3,998.75 6,042,861.00 526,668.009,635.03 -13,649.150.00 0.00 - plan misses target center by 14.58usft at 18184.30usft MD (3984.17 TVD, 9635.00 N, -13649.26 E) - Point MPR-106 wp02 tgt04 3,973.75 6,040,234.00 530,613.006,986.38 -9,718.100.00 0.00 - plan hits target center - Point MPR-106 wp02 tgt03 3,978.75 6,039,680.00 531,444.006,427.82 -8,890.040.00 0.00 - plan misses target center by 9.23usft at 12443.77usft MD (3969.57 TVD, 6428.83 N, -8889.83 E) 3/6/2025 5:24:42PM 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-106 MPU R-106 Survey Calculation Method:Minimum Curvature R-106 as built RKB @ 63.75usft Design:MPU R-106 wp02 Database:Alaska MD Reference:R-106 as built RKB @ 63.75usft North Reference: Well Plan: MPU R-106 True - Point MPR-106 wp02 tgt07 3,978.75 6,041,040.00 529,402.007,799.02 -10,924.820.00 0.00 - plan misses target center by 10.61usft at 14898.11usft MD (3968.16 TVD, 7799.65 N, -10925.15 E) - Point MPR-106 wp02 tgt19 3,998.75 6,045,058.00 523,368.0011,850.14 -16,937.490.00 0.00 - plan misses target center by 5.70usft at 22150.53usft MD (4004.44 TVD, 11850.49 N, -16937.73 E) - Point MPR-106 wp02 tgt06 3,963.75 6,040,938.00 529,556.007,696.18 -10,771.360.00 0.00 - plan hits target center - Point Vertical Depth (usft) Measured Depth (usft) Casing Diameter (") Hole Diameter (")Name Casing Points 13 3/8" x 16"2,280.004,255.34 13-3/8 16 4 1/2" x 8 1/2"3,983.7523,365.06 4-1/2 8-1/2 9 5/8" x 12 1/4"3,969.3311,100.00 9-5/8 12-1/4 Measured Depth (usft) Vertical Depth (usft) Dip Direction (°)Name Lithology Dip (°) Formations Vertical Depth SS 1,508.78 1,393.75 SV5 3,447.15 2,069.75 SV1 4,715.66 2,399.75 UG4A 10,289.44 3,849.75 SB_Na 2,724.48 1,881.75 Base Permafrost 10,135.68 3,809.75 UG_MF 8,413.57 3,361.75 LA3 9,128.56 3,547.75 UG_MB 10,882.95 3,959.75 SB_Oa Measured Depth (usft) Vertical Depth (usft) +E/-W (usft) +N/-S (usft) Local Coordinates Comment Plan Annotations 300.00 300.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD 600.00 598.77 13.49 -19.26 Start Dir 4º/100' : 600' MD, 598.77'TVD 2,248.09 1,757.82 627.41 -861.38 End Dir : 2248.09' MD, 1757.82' TVD 10,507.60 3,906.50 5,345.39 -7,291.25 Start Dir 4º/100' : 10507.6' MD, 3906.5'TVD 10,790.29 3,953.29 5,505.44 -7,518.96 End Dir : 10790.29' MD, 3953.29' TVD 10,941.00 3,963.80 5,589.44 -7,643.65 Begin Geosteering 23,365.06 3,983.75 12,528.69 -17,944.92 Total Depth : 23365.06' MD, 3983.75' TVD 3/6/2025 5:24:42PM COMPASS 5000.17 Build 04 Page 12 Clearance SummaryAnticollision Report06 March, 2025Hilcorp Alaska, LLCMilne PointM Pt Raven PadPlan: MPU R-106MPU R-106MPU R-106 wp02Reference Design: M Pt Raven Pad - Plan: MPU R-106 - MPU R-106 - MPU R-106 wp02Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Well Coordinates: 6,033,301.20 N, 540,367.95 E (70° 30' 06.91" N, 149° 40' 11.33" W)Datum Height: R-106 as built RKB @ 63.75usftScan Range: 0.00 to 23,365.06 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-106 - MPU R-106 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 23,365.06 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Raven Pad - Plan: MPU R-106 - MPU R-106 - MPU R-106 wp02MeasuredDepth(usft)Summary Based on MinimumSeparation WarningM Pt Moose PadMPU M-30 - MPU M-30 - MPU M-30 670.87 10,125.00 459.32 17,035.00 3.17110,125.00Clearance Factor Pass - MPU M-30 - MPU M-30 - MPU M-30 668.64 10,150.00 458.21 17,035.00 3.17710,150.00Ellipse Separation Pass - MPU M-30 - MPU M-30 - MPU M-30 666.99 10,197.06 459.53 17,035.00 3.21510,197.06Centre Distance Pass - MPU M-31 - MPU M-31 - MPU M-31 302.35 10,250.00 187.29 18,561.00 2.62810,250.00Clearance Factor Pass - MPU M-31 - MPU M-31 - MPU M-31 301.94 10,265.73 187.12 18,561.00 2.63010,265.73Ellipse Separation Pass - MPU M-32 - MPU M-32 - MPU M-32 392.47 9,959.70 275.82 18,751.89 3.3659,959.70Centre Distance Pass - MPU M-32 - MPU M-32 - MPU M-32 406.47 10,225.00 236.99 19,000.00 2.39810,225.00Ellipse Separation Pass - MPU M-32 - MPU M-32 - MPU M-32 410.02 10,250.00 238.89 19,000.00 2.39610,250.00Clearance Factor Pass - MPU M-33 - MPU M-33 - MPU M-33 577.56 9,182.99 477.92 17,271.83 5.7979,182.99Centre Distance Pass - MPU M-33 - MPU M-33 - MPU M-33 586.61 9,350.00 471.46 17,396.25 5.0949,350.00Ellipse Separation Pass - MPU M-33 - MPU M-33 - MPU M-33 799.97 10,300.00 578.77 18,282.00 3.61610,300.00Clearance Factor Pass - MPU M-62 - MPU M-62 - MPU M-62 776.88 8,468.14 673.42 17,558.45 7.5098,468.14Centre Distance Pass - MPU M-62 - MPU M-62 - MPU M-62 806.42 8,950.00 659.29 18,021.74 5.4818,950.00Ellipse Separation Pass - MPU M-62 - MPU M-62 - MPU M-62 903.91 9,475.00 721.63 18,413.24 4.9599,475.00Clearance Factor Pass - MPU M-63 - MPU M-63 - MPU M-63 973.55 7,859.02 881.41 16,139.84 10.5657,859.02Centre Distance Pass - MPU M-63 - MPU M-63 - MPU M-63 980.24 8,075.00 874.62 16,324.50 9.2818,075.00Ellipse Separation Pass - MPU M-63 - MPU M-63 - MPU M-63 1,244.95 9,275.00 1,066.44 17,406.59 6.9749,275.00Clearance Factor Pass - M Pt Raven PadMPU R-101 - MPU R-101 - MPU R-101 74.74 674.49 69.16 666.74 13.389674.49Centre Distance Pass - MPU R-101 - MPU R-101 - MPU R-101 74.74 675.00 69.15 667.22 13.380675.00Ellipse Separation Pass - MPU R-101 - MPU R-101 - MPU R-101 2,018.69 20,575.00 1,664.03 20,560.00 5.69220,575.00Clearance Factor Pass - MPU R-101 - MPU R-101 PB1 - MPU R-101 PB1 74.74 674.49 69.16 666.74 13.389674.49Centre Distance Pass - MPU R-101 - MPU R-101 PB1 - MPU R-101 PB1 74.74 675.00 69.15 667.22 13.380675.00Ellipse Separation Pass - MPU R-101 - MPU R-101 PB1 - MPU R-101 PB1 701.16 4,625.00 584.86 4,541.00 6.0294,625.00Clearance Factor Pass - MPU R-102 - MPU R-102 - MPU R-102 58.55 469.69 54.53 466.28 14.568469.69Centre Distance Pass - MPU R-102 - MPU R-102 - MPU R-102 60.11 800.00 53.63 788.20 9.278800.00Ellipse Separation Pass - MPU R-102 - MPU R-102 - MPU R-102 92.45 1,800.00 70.40 1,760.37 4.1931,800.00Clearance Factor Pass - 06 March, 2025 - 17:42COMPASSPage 2 of 6 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU R-106 - MPU R-106 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 23,365.06 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Raven Pad - Plan: MPU R-106 - MPU R-106 - MPU R-106 wp02MeasuredDepth(usft)Summary Based on MinimumSeparation WarningMPU R-102 - MPU R-102PB1 - MPU R-102PB1 58.55 469.69 54.42 466.28 14.182469.69Centre Distance Pass - MPU R-102 - MPU R-102PB1 - MPU R-102PB1 60.11 800.00 53.52 788.20 9.124800.00Ellipse Separation Pass - MPU R-102 - MPU R-102PB1 - MPU R-102PB1 92.45 1,800.00 70.29 1,760.37 4.1721,800.00Clearance Factor Pass - MPU R-103 - MPU R-103 - MPU R-103 29.77 46.95 28.04 46.75 17.26446.95Centre Distance Pass - MPU R-103 - MPU R-103 - MPU R-103 29.94 225.00 27.48 224.63 12.179225.00Ellipse Separation Pass - MPU R-103 - MPU R-103 - MPU R-103 1,214.78 21,075.00 844.00 21,180.00 3.27621,075.00Clearance Factor Pass - MPU R-103 - MPU R-103PB1 - MPU R-103PB1 29.77 46.95 28.04 46.75 17.26446.95Centre Distance Pass - MPU R-103 - MPU R-103PB1 - MPU R-103PB1 29.94 225.00 27.48 224.63 12.179225.00Ellipse Separation Pass - MPU R-103 - MPU R-103PB1 - MPU R-103PB1 1,200.93 11,775.00 976.54 11,848.00 5.35211,775.00Clearance Factor Pass - MPU R-104 - MPU R-104 - MPU R-104 119.76 695.42 114.81 714.45 24.190695.42Centre Distance Pass - MPU R-104 - MPU R-104 - MPU R-104 119.77 700.00 114.79 719.07 24.063700.00Ellipse Separation Pass - MPU R-104 - MPU R-104 - MPU R-104 790.16 21,225.00 412.99 21,369.00 2.09521,225.00Clearance Factor Pass - MPU R-104 - MPU R-104PB1 - MPU R-104PB1 119.76 695.42 114.81 714.45 24.190695.42Centre Distance Pass - MPU R-104 - MPU R-104PB1 - MPU R-104PB1 119.77 700.00 114.79 719.07 24.063700.00Ellipse Separation Pass - MPU R-104 - MPU R-104PB1 - MPU R-104PB1 838.46 11,925.00 554.03 12,082.00 2.94811,925.00Clearance Factor Pass - MPU R-141 - MPU R-141 - MPU R-141 119.85 46.95 118.28 48.35 76.43646.95Centre Distance Pass - MPU R-141 - MPU R-141 - MPU R-141 120.22 275.00 117.16 275.35 39.306275.00Ellipse Separation Pass - MPU R-141 - MPU R-141 - MPU R-141 1,880.89 8,700.00 1,715.41 12,967.82 11.3668,700.00Clearance Factor Pass - MPU R-142 - MPU R-142 - MPU R-142 147.49 407.90 143.96 414.15 41.766407.90Centre Distance Pass - MPU R-142 - MPU R-142 - MPU R-142 147.55 425.00 143.89 431.51 40.372425.00Ellipse Separation Pass - MPU R-142 - MPU R-142 - MPU R-142 2,087.72 8,350.00 1,943.70 11,557.54 14.4968,350.00Clearance Factor Pass - Plan: MPU R-105 - MPU R-105 - MPU R-105 wp03 164.03 4,940.79 116.87 5,210.60 3.4784,940.79Centre Distance Pass - Plan: MPU R-105 - MPU R-105 - MPU R-105 wp03428.9223,075.0035.8923,326.551.09123,075.00Clearance FactorPass - Plan: MPU R-107 - MPU R-107 - MPU R-107 wp02 30.13 300.00 27.13 299.90 10.067300.00Centre Distance Pass - Plan: MPU R-107 - MPU R-107 - MPU R-107 wp02 30.23 325.00 27.06 324.90 9.544325.00Ellipse Separation Pass - Plan: MPU R-107 - MPU R-107 - MPU R-107 wp02 556.53 21,675.00 192.39 21,774.30 1.52821,675.00Clearance Factor Pass - Plan: MPU R-108 - MPU R-108 - MPU R-108 wp02 210.14 300.00 207.15 299.90 70.235300.00Centre Distance Pass - Plan: MPU R-108 - MPU R-108 - MPU R-108 wp02 210.25 325.00 207.08 324.90 66.381325.00Ellipse Separation Pass - Plan: MPU R-108 - MPU R-108 - MPU R-108 wp02 942.69 22,000.00 570.26 22,286.86 2.53122,000.00Clearance Factor Pass - Plan: MPU R-109 - MPU R-109 - MPU R-109 wp02 240.14 300.00 237.15 299.90 80.251300.00Centre Distance Pass - 06 March, 2025 - 17:42COMPASSPage 3 of 6 Milne PointHilcorp Alaska, LLCAnticollision Report for Plan: MPU R-106 - MPU R-106 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 23,365.06 usft. Measured Depth. Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference)Reference Design: M Pt Raven Pad - Plan: MPU R-106 - MPU R-106 - MPU R-106 wp02MeasuredDepth(usft)Summary Based on MinimumSeparation WarningPlan: MPU R-109 - MPU R-109 - MPU R-109 wp02 240.59 425.00 236.68 433.34 61.594425.00Ellipse Separation Pass - Plan: MPU R-109 - MPU R-109 - MPU R-109 wp02 1,353.76 22,300.00 981.74 22,595.72 3.63922,300.00Clearance Factor Pass - Plan: MPU R-110 - MPU R-110 - MPU R-110 wp02 60.13 300.00 57.14 299.90 20.093300.00Centre Distance Pass - Plan: MPU R-110 - MPU R-110 - MPU R-110 wp02 60.35 350.00 57.00 350.40 18.035350.00Ellipse Separation Pass - Plan: MPU R-110 - MPU R-110 - MPU R-110 wp02 1,728.21 22,575.00 1,349.42 22,811.45 4.56222,575.00Clearance Factor Pass - Plan: MPU R-111 - MPU R-111 - MPU R-111 wp02 91.10 300.00 88.11 299.90 30.443300.00Centre Distance Pass - Plan: MPU R-111 - MPU R-111 - MPU R-111 wp02 91.21 325.00 88.04 324.90 28.792325.00Ellipse Separation Pass - Plan: MPU R-111 - MPU R-111 - MPU R-111 wp02 2,145.95 22,875.00 1,766.72 23,205.18 5.65922,875.00Clearance Factor Pass - Survey tool programFrom(usft)To(usft)Survey/Plan Survey Tool46.95 4,256.00 MPU R-106 wp02 GYD_Quest GWD4,256.00 11,100.00 MPU R-106 wp02 GYD_Quest GWD11,100.00 23,365.06 MPU R-106 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.06 March, 2025 - 17:42COMPASSPage 4 of 6 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 wp03MPU R-102MPU R-102PB1MPU R-110 wp02MPU R-107 wp02MPU R-108 wp02MPU R-109 wp02MPU R-104PB1MPU R-104MPU R-103MPU M-33MPU M-31MPU M-32MPU M-30No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU R-106 NAD 1927 (NADCON CONUS)Alaska Zone 0416.80+N/-S +E/-W Northing Easting Latittude Longitude0.000.006033301.20 540367.95 70° 30' 6.9073 N 149° 40' 11.3330 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-106, True NorthVertical (TVD) Reference:R-106 as built RKB @ 63.75usftMeasured Depth Reference:R-106 as built RKB @ 63.75usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-03-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool46.95 4256.00 MPU R-106 wp02 (MPU R-106) GYD_Quest GWD4256.00 11100.00 MPU R-106 wp02 (MPU R-106) GYD_Quest GWD11100.00 23365.06 MPU R-106 wp02 (MPU R-106) 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 wp03MPU R-102MPU R-110 wp02MPU R-107 wp02MPU R-101MPU R-104MPU R-111 wp02MPU R-103MPU R-142NO GLOBAL FILTER: Using user defined selection & filtering criteria46.95 To 23365.06Project: Milne PointSite: M Pt Raven PadWell: Plan: MPU R-106Wellbore: MPU R-106Plan: MPU R-106 wp02CASING DETAILSTVD TVDSS MD Size Name2280.00 2216.25 4255.34 13-3/8 13 3/8" x 16"3969.33 3905.58 11100.00 9-5/8 9 5/8" x 12 1/4"3983.75 3920.00 23365.06 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 nogreater 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. MPU R-106 225-033 MILNE POINT SCHRADER BLFF OIL NIKAITCHUQ and WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT R-106Initial Class/TypeDEV / PENDGeoArea890Unit11328On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2250330MILNE POINT, SCHRADER BLFF OIL - 525140 NIKAITCHUQ, SCHRADER BLUNA1 Permit fee attachedYes ADL025509, ADL388235, ADL355018, and ADL3906152 Lease number appropriateYes3 Unique well name and numberYes MILNE POINT, SCHRADER BLFF OIL - CO 477.005 and NIKAITCHUQ, SCHRADER BLUFF OIL - CO 6394 Well located in a defined poolNo Proposed well crosses from MPU into Nikiaitchuq Unit. Ownership is the same.5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-56 grouted to 127'18 Conductor string providedYes 13-3/8" L-80 68#19 Surface casing protects all known USDWsYes 13-3/8" L-80 68#20 CMT vol adequate to circulate on conductor & surf csgNo21 CMT vol adequate to tie-in long string to surf csgYes 9-5/8" Intermediate Casing to be cemented with 2 stage cement job22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Parker 273 rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches with HSE risk.26 Adequate wellbore separation proposedYes 20" Diverter27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes Parker 273 has 14 x 3-1/8" manual gate valves, 1 x 3-1/8" manual choke and 1 x 3-1/16" remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo MPU R pad has no H2S history. Monitoring will be required.33 Is presence of H2S gas probableNA This is a development well.34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not anticipated; however, rig will have H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipating normally pressured reservoir. MPD to mitigate any abnormal pressures.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate4/15/2025ApprMGRDate4/18/2025ApprADDDate4/15/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 4/23/2025