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Home My WebLink About2023 Greater Point McIntyre Area 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Phone: 907/777-8300 hilcorp.com Hilcorp North Slope, LLC June 14, 2024 Brett Huber, Sr., Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Prudhoe Bay Unit, Greater Point McIntyre (GPMA) Oil Pools Annual Reservoir Surveillance Reports Annual Reservoir Properties Reports April 1, 2023 – March 31, 2024 Chairman Huber, Hilcorp North Slope, LLC, as operator of the Prudhoe Bay Unit, submits the enclosed Annual Reservoir Surveillance Reports for the Greater Point McIntyre (GPMA) Oil Pools in accordance with the latest Conservation Orders for each pool. In addition, Hilcorp North Slope will simultaneously file the Annual Reservoir Properties Reports (ARPs, form 10-428) for the GPMA Oil Pools under this cover and to aogcc.reporting@alaska.gov. The Operators of the Prudhoe Bay Field reserve the right to alter the content of the analyses contained in this report at any time based upon the most recent surveillance information obtained. If you have any questions regarding the reports, please contact Abbie.Barker@hilcorp.com. Thank you, Jeff Allen Reservoir Engineer, Prudhoe Bay East Hilcorp North Slope, LLC Cc: Stephanie Erickson, ConocoPhillips Alaska, Inc. Greg Keith, ConocoPhillips Alaska, Inc. Becky Steen, ConocoPhillips Alaska, Inc. Todd Griffith, ExxonMobil Alaska, Production Inc. Jeff Farr, ExxonMobil Alaska, Production Inc. Bo Gao, ExxonMobil Alaska, Production Inc. Gary Selisker, Chevron USA Dave Roby, AOGCC Allan Eddy, DNR, Division of Oil & Gas Kenneth Diemer, DNR, Division of Oil & Gas Heather Beat, DNR, Division of Oil & Gas Digitally signed by Jeff Allen (969) DN: cn=Jeff Allen (969) Date: 2024.06.13 17:03:32 - 08'00' Jeff Allen (969) GPMA Page 1 ASR for Apr ’23 – Mar ‘24 Prudhoe Bay Unit Lisburne Oil Pool 2024 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2024 is submitted to the Alaska Oil and Gas Conservation Commission for the Lisburne Oil Pool in accordance with commission regulations and Conservation Order 207D. This report covers the period from April 1, 2023 through March 31, 2024. A.Reservoir Management 1.Summary Oil production and reservoir management activity in the Lisburne Oil Pool continues under gas cap expansion supported by gas injection at LGI pad and water injection at L5-29. In the Central area, pressure support is supplemented by weak aquifer influx. Pilot seawater injection projects have been on-going in the central Alapah (NK-25) and the mid-field Wahoo (L5-15) area. Production and injection volumes for the 12-month period ending March 31, 2024 are summarized in Table 1. Cumulative oil production volumes include allocated crude oil, condensate and NGL production. 2.Reservoir Pressure Surveys Within the Pool A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. The proposed number of Lisburne reservoir pressure surveys to be obtained in the coming plan year April 1, 2024 to March 31, 2025 is six total. One apiece at each of the major Lisburne pads (L1, L2, L3, L4 & L5) and one in the Lisburne West Alapah accumulation (well NK-25 or NK-26A). 3.Results and Analysis of Production Logging Surveys There were no production logs obtained from Lisburne wells during the reporting period. B.Development and Production Activity 1.Enhanced Recovery Projects a.L5 Gas Cap Water Injection Surveillance (C.O. 207C) The L5 GCWI pilot project commenced injection in July of 2008. The initial injection rate was 2 mbd, and over time has been gradually increased to approximately 18 mbd. As of March 31, 2024, the cumulative volume of seawater injected in L5-29 was 28,357 mbbls. The L5-29 pilot injection GPMA Page 2 ASR for Apr ’23 – Mar ‘24 demonstrated positive results with likely injection water breakthrough occurring in four offset producer wells (L5-28A, L5-32, L5-33 & L5-36). Pressure response has also been observed in offset wells. The GCWI Pilot was approved for permanent injection under AOGCC Conservation Order 207B.16. The L5-29 injector was repaired and returned to service during the reporting period. Three pressure fall-off (PFO) tests have been conducted in the L5-29 gas cap water injection well. The PFO analyses show a constant pressure boundary, and skin values of between -3.6 and -3.8. Based on these results, it is inferred that no fracture extension is occurring. Offset well annuli pressures are reported monthly to the Commission by the Hilcorp Well Integrity Engineer via the Monthly Injection Report sent to the AOGCC. b.Waterflooding Pilot Projects A review of the Lisburne development plan identified water injection as a mechanism to provide additional pressure support in the Lisburne reservoirs. A grass roots injection well, 04-350, was completed on the southern periphery of the Wahoo Formation in November 2011 and has injected 9,535 mbbls of seawater as of March 31, 2024. Due to water breakthrough in the L3-22A producer, the 04-350 injector was shut in in August of 2021 to improve oil rate and recovery in the offset producers. Another pilot water injection project has been undertaken in the mid-field area. Wahoo production wells L5-15 and L5-13 were converted to seawater injection service in March 2013. As of March 31, 2024 the cumulative volume of seawater injected in both these wells was 12,414 mbbls. Confirmed seawater production has occurred in offset L5-16A and L5-17A. L5-13 developed mechanical integrity issues and was plugged and abandoned in November 2017. Due to water breakthrough in offset producers, L5-15 was shut in in August of 2021 to improve oil rate and recovery in the offset producers. In addition, a pilot water injection project into the Alapah Formation has been initiated from the Niakuk Heald Point pad. Alapah producer NK-25 was converted to seawater injection service in March 2013 and has injected 15,377 mbbls of seawater as of March 31, 2024. Offset producer well pressure response and seawater production have been observed. GPMA Page 3 ASR for Apr ’23 – Mar ‘24 2.Well Activity: Drilling Rig No drilling activity was completed in the Lisburne Formation during the reporting period. 3.Well Activity: Workover Rig Three workovers were completed during the reporting period to restore mechanical integrity and return the wells to service. The L4-32 and L3-24 were both returned to production in addition to the L5-29 injector that was noted above. 4.Well Activity: Non-Rig The L4 Drill Site was reinstated in late March 2021, bringing online production that had been shut in since 2014. Rate-sustaining, non-rig interventions were also performed during this reporting period, including hydrate mitigation, perforating, and gas-lift work. 5.Other Activity a.Plant and Pipelines Various scheduled minor plant and pipeline repairs and modifications were completed to protect or enhance production from the Lisburne during the reporting period. b.Support Facilities Lisburne shares North Slope infrastructure with the Point McIntyre and Niakuk Fields. Nine wells from the IPA can produce to the LPC as part of the L2 Re-route Project: L2-03A, L2-07A, L2-08A, L2-11, L2-13A, L2-14C, L2-18A, L2-21B and L2-29A. c.Production Allocation The production of oil and gas, including those hydrocarbon liquids reported as NGLs, is allocated to the Lisburne Participating Area in accordance with conditions approved by the Alaska Department of Natural Resources, Alaska Department of Revenue, and Alaska Oil and Gas Conservation Commission. There is a test separator at each Lisburne Drill Site. 6.Future Development Plans (C.O. 207) Lisburne Pool oil is predominantly processed at the Lisburne Production Center, which began permanent operation in December 1986. There are currently 88 development wells in the Lisburne Oil Pool. Future development plans are discussed in the 2023 Lisburne Plan of Development filed with the Division of Oil and Gas of the Alaska Department of Natural Resources. The Commission will be copied when the 2024 update of the Lisburne Plan of Development is filed with the Division. GPMA Page 4 ASR for Apr ’23 – Mar ‘24 Tables & Figures Table 2 – Lisburne Pressure Data April 1, 2023 to March 31, 2024 Well Name Survey Date Pressure (psi) Datum = 8900’ SS K-317B 10/30/2023 3,566 L1-10 11/26/2023 3,205 L1-13 10/6/2023 2,321 L1-28 11/24/2023 3,370 L3-11 3/23/2024 1,898 L4-36 12/5/2023 3,784 L5-15 8/26/2023 3,099 L5-21 11/14/2023 3,377 L5-29 2/12/2024 3,595 L5-32 11/13/2023 2,635 L5-36 11/13/2023 3,634 LGI-04 12/24/2023 3,163 Date Oil Production [MBO]Gas Production [MMCF] Water Production [MBW]Gas Injection [MMCF] Water Injection [MBW]MI Injection [MMCF] Cumulative Oil [MBO] Cumulative Gas [MMCF] Cumulative Water Injection [MBW] Cumulative Gas Injection [MMCF] Apr-23 334 7,582 769 2,505 500 0 214,141 2,518,056 70,467 2,340,647 May-23 313 7,015 598 2,019 555 0 214,454 2,525,071 71,022 2,342,666 Jun-23 247 5,777 365 1,507 249 0 214,701 2,530,848 71,271 2,344,173 Jul-23 326 7,601 483 1,829 157 0 215,027 2,538,449 71,428 2,346,001 Aug-23 315 7,191 458 2,229 130 0 215,342 2,545,640 71,558 2,348,231 Sep-23 285 7,665 454 2,158 395 0 215,627 2,553,305 71,953 2,350,389 Oct-23 301 7,122 499 2,067 626 0 215,928 2,560,428 72,579 2,352,456 Nov-23 292 7,089 472 2,514 658 0 216,220 2,567,517 73,236 2,354,971 Dec-23 309 7,843 372 2,422 727 0 216,529 2,575,359 73,963 2,357,392 Jan-24 320 7,470 349 2,016 393 0 216,849 2,582,830 74,356 2,359,408 Feb-24 300 8,381 419 1,895 381 0 217,149 2,591,211 74,737 2,361,303 Mar-24 320 7,810 387 2,072 636 0 217,470 2,599,021 75,373 2,363,375 Table 1 - Lisburne Monthly Production & Injection Volumes GPMA Page 5 ASR for Apr ’23 – Mar ‘24 Prudhoe Bay Unit Niakuk Oil Pool 2024 Annual Reservoir Surveillance Report This Annual Reservoir Surveillance Report is submitted to the Alaska Oil and Gas Conservation Commission for the Niakuk Oil Pool in accordance with commission regulations and Conservation Order No. 329A. This report covers the period from April 1, 2023 through March 31, 2024. A.Reservoir Management 1.Summary Oil production and reservoir management activity in the Niakuk Oil Pool continues under waterflood. Reservoir management activity in the Niakuk Oil Pool includes: 1) selective perforating and profile modifications to manage conformance of the waterflood, 2) production and injection profile logging to determine current production and injection zones for potential profile modifications, material balance calculations, and effective full field modeling, 3) pressure surveys to monitor flood performance and 4) analysis of production, Gas Oil Ratio, and Water Oil Ratio trends to highlight poorer performing wells for possible intervention activity. Production and injection volumes and resultant voidage data by month for the 12-month period ending March 31, 2024 are summarized in Tables 1 and 2. 2.Reservoir Pressure Surveys Within the Pool A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. The proposed number of Niakuk reservoir pressure surveys to be obtained in the coming plan year April 1, 2023 to March 31, 2024 is three total: one survey apiece in each of the major Niakuk reservoir sector delineations (Segments 1, 2/4 and 3/5) 3.Results of Production Logging, Tracer and Well Surveys (C.O. 329A Rule 9d) No production logs were run during the reporting period. No tracer surveys were performed during this reporting period. GPMA Page 6 ASR for Apr ’23 – Mar ‘24 B.Development and Production Activity 1.Enhanced Recovery Projects a.Progress of Niakuk Waterflood Project Implementation and Reservoir Management Summary (C.O. 329A Rule 9a) The Niakuk waterflood was started in April 1995, in conjunction with the commissioning of permanent facilities at Heald Point, using water from the Initial Participating Area Seawater Treatment Plant. Produced water from the Lisburne Production Center was used between August of 2000 and May 2004. Conversion to seawater injection was completed in September 2004, and seawater injection continues throughout this reporting period. All producing segments (1, 2/4 and 3/5) are receiving pressure support from water injection. There are 3 active injectors in the Niakuk Pool with an average total injection rate of approximately 18,400 bwpd for the reporting period. The current injection strategy is to maintain roughly balanced voidage replacement in each segment. b.Voidage Balance of Produced and Injected Fluids (C.O. 329A Rule 9b) Tables 1 and 2 detail hydrocarbon production, water injection and resultant voidage data by month for the reporting period. c.Analysis of Reservoir Pressure Surveys Within the Pool (C.O. 329A Rule 9c) Table 3 shows results from the reservoir pressure surveys taken during the reporting period. The pressures in Segments 2/4, 1, and 3/5 are generally managed with the original reservoir pressure of approximately 4500 psi as a target/maximum, and the bubble point pressure of 4200 psi as a minimum. GPMA Page 7 ASR for Apr ’23 – Mar ‘24 2.Special Monitoring: NK-43 Well (C.O. 329A Rule 9e) NK-43 is a commingled producer which produces from both the Kuparuk and Sag River reservoirs. The AOGCC approved co-mingled production in NK-43 with production allocated to each reservoir via geochemical analysis in Conservation Order 329B on December 7, 2006. Samples were taken from NK-43 during the prior reporting period for geochemical analysis to confirm production allocation splits between the Sag River and Kuparuk reservoirs. The analyses showed that ~100% of oil production in NK-43 is from the Kuparuk during the prior reporting period. NK-43 is currently shut in and future geochemical analysis for production allocation will be performed when the well is returned to production. 3.Well Activity: Permanent production facilities at Niakuk were commissioned in March 1995. There have been 29 development wells drilled into the Niakuk Oil Pool through the end of the reporting period. During the reporting period, the Niakuk field focused on optimization of producers and scale management to which inhibition treatments were performed. Rate-adding non-rig interventions were performed during the reporting period. These rate-adding interventions included perforations, hot oil treatment (HOT) jobs, gas-lift work, SSSV replacements and surface component repairs. 4.Future Development Plans (C.O. 329A Rule 9f) Future development plans are discussed in the 2023 Niakuk Plan of Development filed with the Division of Oil and Gas of the Alaska Department of Natural Resources, which the commission received. The commission will be copied when the 2024 update of the Niakuk Plan of Development is filed with the Division. GPMA Page 8 ASR for Apr ’23 – Mar ‘24 5.Review of Pool Production Allocation Factors (per Administrative Approval Docket Number: CO-15- 013 Done January 7, 2016) LPC monthly average oil allocation factors are supplied below. The Niakuk Oil Pool and Raven Oil Pool will have the same allocation factors as LPC. Allocation factors range from 0.95-1.11. Daily allocation data and daily test data are being retained. Date Monthly LPC Allocation Factor Apr-23 1.01 May-23 1.04 Jun-23 0.95 Jul-23 1.10 Aug-23 1.11 Sep-23 1.06 Oct-23 1.06 Nov-23 1.03 Dec-23 1.06 Jan-24 1.05 Feb-24 1.03 Mar-24 1.05 GPMA Page 9 ASR for Apr ’23 – Mar ‘24 Tables and Figures Note: Monthly Production/Injection/Voidage/Pressure data (Tables 1 & 2) do not include the injection/production results from NK-08B, NK-14B, NK-15A, NK-38B, or NK-65A wells (Raven). They are subject to a separate Raven Oil Pool Annual Reservoir Report. Date Oil Production [MBO] Gas Production [MMCF] Water Production [MBW] Gas Injection [MMCF] Water Injection [MBW] MI Injection [MMCF] Cumulative Oil [MBO] Cumulative Gas [MMCF] Apr-23 57 48 754 0 890 0 97,216 88,906 May-23 38 49 627 0 970 0 97,254 88,955 Jun-23 21 28 377 0 633 0 97,275 88,983 Jul-23 22 32 482 0 666 0 97,296 89,015 Aug-23 21 26 457 0 588 0 97,317 89,040 Sep-23 19 29 433 0 647 0 97,336 89,069 Oct-23 19 29 474 0 653 0 97,355 89,098 Nov-23 16 25 478 0 656 0 97,371 89,123 Dec-23 18 35 343 0 657 0 97,389 89,158 Jan-24 20 40 346 0 609 0 97,409 89,198 Feb-24 19 27 382 0 552 0 97,428 89,225 Mar-24 18 13 336 0 481 0 97,446 89,238 Table 1 - Niakuk Monthly Production & Injection Volumes Date Oil Production [MRBBLS] Gas Production [MRBBLS] Water Production [MRBBLS] Gas Injection [MRBBLS] Water Injection [MRBBLS] MI Injection [MRBBLS] Net Voidage [MRBBLS] Apr-23 74 6 765 0 877 0 31 May-23 49 17 637 0 956 0 253 Jun-23 27 10 383 0 624 0 204 Jul-23 28 12 490 0 656 0 126 Aug-23 27 8 464 0 579 0 80 Sep-23 25 12 440 0 638 0 162 Oct-23 25 12 481 0 643 0 125 Nov-23 21 10 485 0 646 0 130 Dec-23 24 17 348 0 647 0 258 Jan-24 26 19 351 0 600 0 203 Feb-24 25 10 388 0 544 0 121 Mar-24 24 0 341 0 474 0 109 Table 2 - Niakuk Monthly Voidage GPMA Page 10 ASR for Apr ’23 – Mar ‘24 Table 3 – 2023-2024 Pressure Survey Data Table 3 - Niakuk Pressure data April 1, 2023 to March 31, 2024 Well Name Survey Date Pressure (psi) (Datum = 9200' SS) NK-23 2/4/2024 4,064 GPMA Page 11 ASR for Apr ’23 – Mar ‘24 Prudhoe Bay Unit Pt. McIntyre Oil Pool 2024 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2024 is submitted to the Alaska Oil and Gas Conservation Commission for the Pt. McIntyre Oil Pool in accordance with Commission regulations and Conservation Order 317B. This report covers the period between April 1, 2023 and March 31, 2024. A.Reservoir Management 1.Summary Production and injection volumes for the 12-month period ending March 31, 2024 are summarized in Table 1. Current well locations are shown in Figure 1. The dominant oil recovery mechanisms in the Pt. McIntyre Oil Pool are waterflooding and miscible gas injection in the down-structure area north of the Terrace Fault and gravity drainage in the up- structure area referred to as the Gravity Drainage (GD) Area. Gas injection commenced in the gas cap with field startup to replace voidage and promote gravity drainage. The waterflood was in continuous operation during the reporting period with 16 wells on water injection and/or miscible gas injection, supporting 14 patterns (two patterns have two injectors). The P1-16 injector was offline for the period for integrity and the repair is pending availability of the workover rig. 2.Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 15 a) During the 12 month period from April 2023 – March 2024, a total of 23.7 BCF of MI (miscible injectant) was injected into Point McIntyre patterns. 3.Voidage Balance by Month of Produced and Injected Fluids (Rule 15 b) Monthly production and injection surface volumes are summarized in Table 1. A voidage balance of produced fluids and injected fluids for the report period is shown in Table 2. As summarized in these analyses, monthly voidage is targeted to be balanced with injection. Negative net reservoir voidage values in Table 2 indicate Injection Withdrawal Ratios greater than 1. 4.Analysis of Reservoir Pressure Surveys within the Pool (Rule 15 c) Reservoir pressure monitoring is performed in accordance with Rule 12 of Conservation Order 317B. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. GPMA Page 12 ASR for Apr ’23 – Mar ‘24 The proposed number of Pt McIntyre reservoir pressure surveys to be obtained in the coming plan year April 1, 2024 to March 31, 2025 is three total. Two reservoir pressure surveys are proposed for the waterflood/MI pattern dominated parts of the field and one pressure survey is proposed for the Gravity Drainage / Gravity Drainage Water Flood Interaction (GD/GDWFI) dominated part of the field. 5.Results and Analysis of Production & Injection Logging Surveys (Rule 15 d) No production profiles were obtained in the Point McIntyre Oil Pool in the reporting period. 6.Results of Any Special Monitoring (Rule 15 e) No special monitoring was performed during the reporting period. B.Development and Production Activity 1.Well Activity There are a total of 26 well penetrations drilled from DS-PM1 including sidetracked, P&A and suspended wells. There are a total of 76 well penetrations drilled from DS-PM2. An additional water/MI injector (P1-25) is located at the West Dock staging area. There was no drilling activity during the reporting period. Rate-adding non-rig interventions were performed during the reporting period. These rate-adding interventions included perforations, hot oil treatment (HOT) jobs, gas-lift work, SSSV replacements and surface component repairs. During the reporting period, the scale management program continued for Pt Mac wells and included regular scale inhibition treatments. No new Pt Mac wells were put on MI for the first time. 2.Other Activities d.Pipelines i.The P-15004 produced water injection booster pump was reinstated in February of 2021 to improve water injection rates at Point McIntyre. ii.Figure 2 shows the existing pipeline configuration together with the miscible injectant distribution pipelines from LPC and CGF to the Pt. McIntyre drill sites. iii.Pt. McIntyre production is processed at LPC and GC-1. PM1 wells can only flow to the LPC. Between March of 2004 and November 2011 all wells at drill site PM2 could be flowed to either the LPC (high pressure system) or to GC-1 (low pressure system) via a 36” three phase line from PM2 to GC-1. As a result of this connection, wellhead pressures were GPMA Page 13 ASR for Apr ’23 – Mar ‘24 lowered for the PM2 wells flowing to GC-1 by approximately 400 psi and utilized approximately 80 MB/D of available water handling capacity at GC-1. On November 12th 2011, the 36” line from PM2 to GC-1 was shut-in due to the integrity status of the line. Repair of the pipeline was completed October 2016, and all PM2 production now flows to GC-1, no production from PM2 flows to LPC. With reduced backpressure, increased water and gas handling capacity at GC1, and optimization of the well sorts, production from PM2 has been increased. iv.In May of 2021, the production common line was successfully upsized at PM2 to improve offtake rates from the Point McIntyre field. e.Produced Water During the 12-month reporting period, the LPC continued to provide produced water for injection at Point McIntyre. Additional produced water is provided from FS1 to LPC for injection at Pt. McIntyre. f.Support Facilities Pt. McIntyre will continue to share North Slope infrastructure with the Lisburne Participating Area ("LPA") and the Initial Participating Areas to minimize duplication of facilities. 3.Future Development Plans (rule 15 f) Permanent production facilities at Pt. McIntyre were commissioned in 1993. There have been 98 development wells including sidetracks drilled into the Pt. McIntyre Oil Pool through the end of the reporting period. Future development plans are discussed in the 2023 Pt. McIntyre Plan of Development filed with the Division of Oil and Gas of the Alaska Department of Natural Resources. The Commission will be copied when the 2024 update of the Pt. McIntyre Plan of Development is filed with the division. GPMA Page 14 ASR for Apr ’23 – Mar ‘24 Tables and Figures Table 3 – Point McInytre Pressure data April 1, 2023 to March 31, 2024 Well Name Survey Date Pressure (psi) (Datum = 8,800' SS) P-13 5/22/2023 3,596 Date Oil Production [MBO]Gas Production [MMCF] Water Production [MBW]Gas Injection [MMCF] Water Injection [MBW]MI Injection [MMCF] Cumulative Oil [MBO] Cumulative Gas [MMCF] Apr-23 441 6,357 4,557 3,762 4,397 1,878 496,380 1,773,933 May-23 453 6,944 4,872 3,678 4,678 2,191 496,833 1,780,877 Jun-23 347 5,200 4,378 2,909 4,077 1,594 497,180 1,786,077 Jul-23 342 4,678 3,883 3,921 5,419 1,226 497,521 1,790,755 Aug-23 325 4,223 3,461 3,850 4,908 1,192 497,846 1,794,978 Sep-23 413 6,072 5,099 4,136 4,812 1,982 498,259 1,801,051 Oct-23 429 5,961 5,122 3,736 5,805 2,165 498,688 1,807,011 Nov-23 431 7,412 5,089 3,871 5,510 2,066 499,119 1,814,424 Dec-23 442 7,432 5,237 4,048 5,769 2,309 499,561 1,821,856 Jan-24 426 7,427 5,258 3,908 5,209 2,429 499,987 1,829,283 Feb-24 378 6,537 4,511 3,482 4,935 2,526 500,365 1,835,820 Mar-24 419 7,654 5,046 3,736 5,070 2,188 500,784 1,843,474 Table 1 - Pt McIntyre Monthly Production & Injection Volumes Date Oil Production [MRBBLS] Gas Production [MRBBLS] Water Production [MRBBLS] Gas Injection [MRBBLS] Water Injection [MRBBLS] MI Injection [MRBBLS] Net Voidage [MRBBLS] Apr-23 574 4,564 4,626 2,839 4,331 1,417 -1,177 May-23 589 5,001 4,945 2,776 4,608 1,653 -1,497 Jun-23 451 3,741 4,444 2,195 4,016 1,203 -1,222 Jul-23 444 3,350 3,941 2,959 5,338 925 1,487 Aug-23 423 3,015 3,513 2,905 4,835 899 1,689 Sep-23 537 4,364 5,175 3,121 4,740 1,495 -719 Oct-23 558 4,271 5,199 2,819 5,718 1,634 142 Nov-23 560 5,366 5,165 2,921 5,427 1,559 -1,184 Dec-23 574 5,375 5,315 3,055 5,682 1,742 -785 Jan-24 554 5,380 5,337 2,949 5,131 1,833 -1,358 Feb-24 492 4,733 4,579 2,628 4,861 1,906 -409 Mar-24 544 5,555 5,122 2,819 4,994 1,651 -1,756 Table 2 - Pt McIntyre Monthly Voidage GPMA Page 15 ASR for Apr ’23 – Mar ‘24 Figure 1 Pt. McIntyre Well Location Map Unit Boundary GPMA Page 16 ASR for Apr ’23 – Mar ‘24 PM2 Approximate Scale 0 1Miles Prudhoe Bay Existing Pipelines Pipelines for EOR PM1 LG1 L1 CCP CGF L2 L3 L5 NK L4 LPC Figure 2. Drill Site and Pipeline Configuration GC1* * GC1 location not to scale Figure 3 GPMA Page 17 ASR for Apr ’23 – Mar ‘24 Prudhoe Bay Unit Raven Oil Pool and Sag River Undefined Oil Pool 2024 Annual Reservoir Surveillance Report This Annual Reservoir Report for the period ending March 31, 2024 is submitted to the Alaska Oil and Gas Conservation Commission for the Raven Oil Pool in accordance with Commission regulations and Conservation Order 570. Data for the Sag River Undefined Oil Pool is included here as the Raven Oil Pool will eventually be expanded to encompass the Sag River Undefined Oil Pool once pool limits are defined. This report covers the period between April 1, 2023 and March 31, 2024. A.Reservoir Management 1.Summary Raven is a small oil and gas field in the Permo-Triassic interval (Ivishak and Sag River) located beneath the Niakuk Field (Kuparuk reservoir). Production from the Raven Field started in March 2001 with the completion of the Sag River in NK- 43. The Sag River in NK-43 was subsequently isolated with a cast iron bridge plug (CIBP), and the well was perforated in the Kuparuk reservoir and produced until 1/2/06 when the CIBP was removed and the Sag River commingled with the Kuparuk. Production from NK-38A began in March 2005 from the Ivishak reservoir. NK-38A was sidetracked and NK-38B began production September 2016 from the optimized location. NK-14B was spudded in March 2017 and is an extension well delineating the outer boundaries of the Raven Oil Pool. The well came on production from the Sag River formation in late June 2017 and by the middle of August had what later was determined to be a production casing leak. The well was shut-in from September 2017 – March 2018 to determine failure and repair options. NK-14B has since been restored to production. NK-15A was drilled and completed in March 2018 in a position on the structure that was believed to be better situated to support and waterflood the structure for the NK-38B offtake. However, the Ivishak reservoir encountered by NK-15A was found to be wet and low permeability. In December of 2020, the Sag River formation was perforated in the NK-15A well as rich gas potential was identified and it was determined that no further utility in the Ivishak existed. After perforating, NK-15A came online at over 1,500 BOPD. NK-08B was drilled and completed in April 2019 into an un-swept part of the Sag River formation within the Raven reservoir. The well came on production in May 2019 and has been a full-time producer since that time. GPMA Page 18 ASR for Apr ’23 – Mar ‘24 As NK-38B seems to exhibit aquifer support based on pressure and water analysis, NK-65A injection had been decreased to a VRR less than 1, and in May of 2020 the well was shut in for a well line repair. During this shut-in period it was determined that the support from NK-65A was not needed as the NK- 15A confirmed that the Ivishak had already been swept in the fault block that NK-38B produced from. An evaluation was completed to assess the potential for NK-65A to be converted to a rich gas producer, similar to NK-15A, to maximize rate and recovery from the North and Central Raven fault blocks. Upon completion of the evaluation, it was determined additional recoverable hydrocarbons could be captured from both Sag and Ivishak rich gas. In December of 2021, the NK-65A was converted to production service and has produced a cumulative 290 MSTBO to-date from the Ivishak and Sag rich gas. The long-term depletion plan is to optimize hydrocarbon production in the Raven reservoir through voidage replacement from water injection as a supplement to aquifer influx in order to keep reservoir pressure at levels that will optimize oil recovery as well as develop up the rich gas potential that has been proven with the NK-15A. The Raven Pool voidage replacement ratio for the reporting period is deliberately less than 1.0 due the known aquifer influx influence. NK-14B production is included in voidage calculations, however as there is no connectivity with NK-65A injection rates are not managed to support NK-14B offtake. NK-14B will continue to be monitored and continued information analysis will allow for optimization of long-term depletion plans for the Sag River. 2.Analysis of Reservoir Pressure Surveys Within the Pool Static pressure surveys have been conducted on the wells in the field. Table 3 shows results of static reservoir pressure surveys conducted on the wells since March 2005. The most recent static reservoir pressure in the Ivishak in NK-38B was taken in February 2021 and reservoir pressure was 4,252 psi (datum). The proposed number of Raven reservoir pressure surveys to be obtained in the coming plan year April 1, 2024 to March 31, 2025 is two total. Hilcorp requests flexibility with specifying the two separate wells that will be surveyed while noting that Raven has a low well count. 3.Results of Production Logging, Tracer and Well Surveys No production logs were run during the reporting period. No tracer surveys were performed during the reporting period. GPMA Page 19 ASR for Apr ’23 – Mar ‘24 B. Development and Production Activity 1.Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary Waterflood at Raven began in October 2005, using water from the Initial Participating Area Seawater Treatment facilities. Future development drilling to provide injection support to NK-08B and NK-14B is also currently being evaluated. An effort to convert the NK-38B to a rich gas producer is expected to occur within the upcoming reporting period. 2. Voidage Balance of Produced and Injected Fluids Tables 1 and 2 detail the production, injection and calculated voidage by month for the reporting period. 3. Special Monitoring: NK-43 Well (C.O. 329A Rule 9e) NK-43 is a commingled producer which produces from both the Kuparuk and Sag River reservoirs. The AOGCC approved co-mingled production in NK-43 with production allocated to each reservoir via geochemical analysis in Conservation Order 329B on December 7, 2006. Samples were taken from NK-43 on November 10th, 2022, for geochemical analysis to confirm production allocation splits between the Sag River and Kuparuk reservoirs. This analysis showed that ~100% of oil production in NK-43 is from the Kuparuk during the reporting period. The well is currently shut in. 4. Future Development Plans (C.O. 570) Permanent production facilities that Raven utilizes were commissioned in March 1995. There have been 5 development wells drilled into the Raven Oil Pool through the end of the reporting period. Future development plans are discussed in the 2023 Raven Plan of Development filed with the Division of Oil and Gas of the Alaska Department of Natural Resources, which the Commission received. The Commission will be copied when the 2024 update of the Raven Plan of Development is filed with the division. GPMA Page 20 ASR for Apr ’23 – Mar ‘24 5. Review of Pool Production Allocation Factors (per Administrative Approval Docket Number: CO-15-013 Done January 7, 2016) LPC monthly average oil allocation factors are supplied below. The Niakuk Oil Pool and Raven Oil Pool will have the same allocation factors as LPC. Allocation factors range from 0.95-1.11. Daily allocation data and daily test data are being retained. Date Monthly LPC Allocation Factor Apr-23 1.01 May-23 1.04 Jun-23 0.95 Jul-23 1.10 Aug-23 1.11 Sep-23 1.06 Oct-23 1.06 Nov-23 1.03 Dec-23 1.06 Jan-24 1.05 Feb-24 1.03 Mar-24 1.05 GPMA Page 21 ASR for Apr ’23 – Mar ‘24 Tables and Figures Note: Monthly Production/Injection/Voidage for the Ivishak and Sag River. Date Oil Production [MBO]Gas Production [MMCF] Water Production [MBW]Gas Injection [MMCF] Water Injection [MBW]MI Injection [MMCF] Cumulative Oil [MBO] Cumulative Gas [MMCF] Apr-23 25 542 41 0 0 0 6,269 44,572 May-23 29 592 77 0 0 0 6,297 45,164 Jun-23 18 375 82 0 0 0 6,315 45,539 Jul-23 19 437 83 0 0 0 6,334 45,976 Aug-23 15 293 102 0 0 0 6,349 46,268 Sep-23 13 179 113 0 0 0 6,362 46,447 Oct-23 5 54 17 0 0 0 6,367 46,501 Nov-23 8 66 36 0 0 0 6,375 46,567 Dec-23 8 186 181 0 0 0 6,384 46,753 Jan-24 13 99 66 0 0 0 6,396 46,853 Feb-24 7 75 23 0 0 0 6,403 46,928 Mar-24 13 44 3 0 0 0 6,416 46,972 Table 1 - Raven Monthly Production & Injection Volumes Date Oil Production [MRBBLS] Gas Production [MRBBLS] Water Production [MRBBLS] Gas Injection [MRBBLS] Water Injection [MRBBLS] MI Injection [MRBBLS] Net Voidage [MRBBLS] Apr-23 32 396 42 0 0 0 -470 May-23 37 432 78 0 0 0 -547 Jun-23 23 273 84 0 0 0 -381 Jul-23 24 320 84 0 0 0 -428 Aug-23 19 213 104 0 0 0 -336 Sep-23 17 128 115 0 0 0 -260 Oct-23 7 38 18 0 0 0 -62 Nov-23 11 45 37 0 0 0 -93 Dec-23 11 136 184 0 0 0 -331 Jan-24 16 68 67 0 0 0 -152 Feb-24 9 53 23 0 0 0 -85 Mar-24 17 26 3 0 0 0 -46 Table 2 - Raven Monthly Voidage GPMA Page 22 ASR for Apr ’23 – Mar ‘24 Table 3 – Raven & Sag River Undefined Ivishak & Sag Pressure Survey Data Since March 2005 Sw Name Test Date Pres Surv Type Datum Ss Pres Datum NK-38A 3/29/2005 SBHP 9850 4973 NK-38A 8/1/2005 SBHP 9850 4237 NK-38A 8/7/2005 SBHP 9850 4273 NK-65A 8/9/2005 SBHP 9850 4463 NK-65A 8/15/2005 SBHP 9850 4295 NK-38A 12/24/2005 SBHP 9850 4210 NK-65A 5/24/2006 SBHP 9850 4414 NK-38A 7/26/2006 SBHP 9850 4155 NK-65A 7/26/2006 SBHP 9850 4400 NK-38A 1/23/2007 SBHP 9850 4104 NK-38A 7/6/2007 SBHP 9850 3758 NK-65A 8/16/2007 SBHP 9850 4827 NK-38A 8/24/2007 SBHP 9850 4370 NK-38A 10/30/2007 SBHP 9850 4379 NK-38A 6/9/2008 SBHP 9850 3543 NK-65A 8/17/2008 SBHP 9850 4379 NK-38A 9/2/2008 SBHP 9850 3507 NK-38A 4/29/2009 SBHP 9850 3537 NK-38A 5/18/2009 SBHP 9850 3928 NK-65A 8/8/2009 SFO 9850 4525 NK-38A 8/31/2009 SBHP 9850 4165 NK-65A 6/5/2010 SFO 9850 4534 NK-38A 7/6/2010 SBHP 9850 4090 NK-65A 6/4/2011 SBHP 9850 4468 NK-38A 6/6/2011 SBHP 9850 4402 NK-65A 6/27/2012 SFO 9850 4497 NK-38A 7/14/2012 SBHP 9850 3976 NK-65A 7/13/2013 SFO 9850 4429 NK-38A 12/26/2013 SBHP 9850 3549 NK-38A 6/26/2014 SBHP 9850 3564 GPMA Page 23 ASR for Apr ’23 – Mar ‘24 NK-65A 7/13/2014 SFO 9850 4674 NK-43 3/12/2015 SBHP 9850 4057 NK-38A 7/31/2015 SBHP 9850 3386 NK-38A 6/3/2016 SBHP 9850 3061 NK-38B 8/21/2016 SBHP 9850 4412 NK-14B 4/27/2017 MDT -Sag 9850 4608 NK-14B 7/28/2017 SBHP - Sag 9850 3801 NK-14B 11/24/2017 SBHP- Sag 9850 4090 NK-38B 7/21/2017 SBHP 9850 4053 NK-15A 7/2/2018 SBHP 9850 4346 NK-38B 7/17/2018 SBHP 9850 4210 NK-14B 3/31/2019 PBU – Sag 9850 2454 NK-65A 10/19/2018 PBU 9850 4491 NK-08B 4/30/2019 SBHP 9850 4815 NK-38B 9/13/2019 SBHP 9850 4257 NK-38B 2/24/2021 SBHP 9850 4252 NK-08B 10/27/22 SBHP - Sag 9850 1856 NK-14B 12/24/22 SBHP – Sag 9850 1883 GP M A Pa g e 2 4 AS R f o r A p r ’ 2 3 – M a r ‘ 2 4 GP M A Pa g e 2 5 AS R f o r A p r ’ 2 3 – M a r ‘ 2 4 GP M A Pa g e 2 6 AS R f o r A p r ’ 2 3 – M a r ‘ 2 4 GP M A Pa g e 2 7 AS R f o r A p r ’ 2 3 – M a r ‘ 2 4 GP M A Pa g e 2 8 AS R f o r A p r ’ 2 3 – M a r ‘ 2 4 3. Field and Pool Code: 4. Pool Name 5. Reference Datum (ft TVDSS) 6. Temperature (°F) 7. Porosity (%) 8. Permeability (md) 9. Swi (%)10. Oil Viscosity @ Original Pressure (cp) 11. Oil Viscosity @ Saturation Pressure (cp) 12. Original Pressure (psi) 13. Bubble Point or Dew Point Pressure (psi) 14. Current Reservoir Pressure (psi) 15. Oil Gravity (°API) 16. Gas Specific Gravity (Air = 1.0) 17. Gross Pay (ft) 18. Net Pay (ft) 19. Original Formation Volume Factor (RB/STB) 20. Bubble Point Formation Volume Factor (RB/STB) 21. Gas Compressibility Factor (Z) 22. Original GOR (SCF/STB) 23. Current GOR (SCF/STB) 640180 Prudhoe Bay, Pt McIntyre Oil Pool 8800 180 22.00 200.00 15.00 0.9 0.9 4377 4308 3596 27 0.7 225 156 1.39 1.39 0.83 805 18,280 640148 Prudhoe Bay, Niakuk Oil Pool 9200 187 20.00 500.00 28.00 0.94 1.04 4446 3800 4064 25 0.72 350 105 1.35 1.33 0.94 660 1,390 640186 Prudhoe Bay, W Beach Oil Pool 8800 175 11.00 37.00 58.00 1.08 1.08 4250 4068 3609 25.7 0.7 191 92 1.36 1.36 0.85 741 23,032 640152 Prudhoe Bay, N Prudhoe Bay Oil Pool 9245 206 20.00 265.00 40.00 0.425 0.425 3925 3870 3610 32.5 0.88 250 220 1.54 1.54 0.95 982 32,902 640147 Prudhoe Bay, Raven Oil Pool 9850 207 20.00 265.00 30.00 0.4 0.36 4973 4973 4252 32 0.88 250 220 1.87 1.87 0.95 1621 24,500 640144 Prudhoe Bay, Lisburne Oil Pool 8900 183 10 1 30 0.9 0.9 4490 4300 3137 27 0.72 1000 125 1.385 1.385 0.855 830 24,116 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT 1. Operator:2. Address: Hilcorp North Slope, LLC 3800 Centerpoint Drive #1400; Anchorage, AK 99503 Printed Name Title Date 6/11/2024 Reservoir Engineer Jeff Allen I hereby certify that the foregoing is true and correct to the best of my knowledge. Jeff AllenSignature Digitally signed by Jeff Allen (969) DN: cn=Jeff Allen (969) Date: 2024.06.11 15:32:35 - 08'00' Jeff Allen (969) 6. Oil Gravity: 27 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) K-317B 50029225370200 O 640144 Lisburne 8770-8867 10/30/2023 8568 SBHP 178 8522 3404 8900 0.43 3566 L1-10 50029213400000 O 640144 Lisburne 8729-8747, 8772-8792, 8798-8825, 8838- 8864, 8879-8895, 8901-8912, 8917-8931 11/26/2023 1560 SBHP 183 8800 3162 8900 0.43 3205 L1-13 50029235630000 O 640144 Lisburne 8798-8839, 8846-8957, 8967-9012 10/6/2023 2472 SBHP 183 8900 2321 8900 0.43 2321 L1-28 50029217920000 O 640144 Lisburne 8686-8687, 8694-8695, 8699-8700, 8701- 8702, 8704-8705, 8707-8708, 8718-8719, 8733-8734, 8748-8749, 8750-8753, 8764- 8766, 8767-8768, 8769-8770, 8771-8772, 8798-8800, 8802-8804, 8853-8854, 8857- 8859, 8862-8863, 8871-8873 11/24/2023 271176 SBHP 180 8900 3370 8900 0.43 3370 L3-11 50029214520000 O 640144 Lisburne 8732-8806, 8814-8921, 8947-9020, 9032- 9109 3/23/2024 264 SBHP 173 8700 1842 8900 0.28 1898 L4-36 50029221890000 O 640144 Lisburne 8974-8975, 8976-9014, 9018-9022, 9024- 9025, 9031-9032 12/5/2023 3768 SBHP 183 8899 3784 8900 0.31 3784 L5-15 50029218680000 WI 640144 Lisburne 8661-8714, 8739-8831, 8839-8919, 8922- 8950, 8971-8976, 8990-8994, 9041-9061 8/26/2023 18000 SBHP 167 8900 3099 8900 0.42 3099 L5-21 50029217320000 O 640144 Lisburne 8663-8671, 8676-8688, 8697-8788, 8795- 8880, 8883-8886, 8910-8911, 8913-8944, 8972-8975, 8984-8987, 9001-9004 11/14/2023 7824 SBHP 173 8800 3334 8900 0.43 3377 L5-29 50029217240000 WI 640144 Lisburne 8494-8527, 8646-8649, 8653-8654, 8659- 8660. 8663-8664, 8671-8672, 8678-8679, 8696-8699, 8703-8704, 8707-8708, 8711- 8712, 8714-8715, 8725-8728, 8733-8734, 8742-8743, 8750-8751, 8755-8756, 8761- 8762, 8766-8767, 8773-8774, 8778-8780, 8794-8795, 8798-8801 2/12/2024 216 SBHP 92 8500 3423 8900 0.43 3595 L5-32 50029218610000 O 640144 Lisburne 8597-8636, 8647-8685, 8699-8700, 8703- 8704, 8711-8712, 8715-8716, 8719-8735, 8740-8741, 8744-8745, 8746-8747, 8749- 8783, 8799-8800, 8804-8805, 8810-8811, 8815-8828, 8838-8839, 8844-8845, 8851- 8874, 8882-8883, 8885-8886, 8891-8892 11/13/2023 960 SBHP 166 8800 2628 8900 0.07 2635 L5-36 50029219330000 O 640144 Lisburne 8582-8616, 8644-8691, 8699-8709, 8717- 8721, 8733-8746, 8750-8757, 8777-8784, 8789-8801, 8810-8823 11/13/2023 40560 SBHP 178 8800 3591 8900 0.43 3634 LGI-04 50029217830000 O 640144 Lisburne 8705-8706, 8716-8717, 8724-8725, 8733- 8734, 8744-8745, 8749-8750, 8753-8754, 8771-8773, 8775-8779, 8782-8783, 8804- 8805, 8817-8818, 8820-8823, 8827-8828, 8829-8837, 8840-8842, 8846-8848, 8857- 8881, 8890-8891, 8895-8909, 8926-8927, 8935-8947, 8955-8956, 8963-8964, 8967- 8968, 8980-8986, 8987-8991, 9000-9003 12/24/2023 237288 SBHP 178 8900 3163 8900 0.30 3163 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: Printed Name Title Date Reservoir Engineer June 11, 2024Jeff Allen Jeff AllenCertified Digital Signature 23. All tests reported herein were made in accordance with the applicable rules, regulations, and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. 7. Gas Gravity: Prudhoe Bay Unit Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 Lisburne Field, Lisburne Oil Pool 8900 TVDss 0.76 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Form 10-412 Revised 10/2022 Submit PDF and Excel to aogcc.reporting@alaska.gov Digitally signed by Jeff Allen (969) DN: cn=Jeff Allen (969) Date: 2024.06.11 13:43:01 - 08'00' Jeff Allen (969) 6. Oil Gravity: 27 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) NK-23 50029224550000 WI 640148 9465-9468, 9477-9501, 9507-9535, 9574-9577, 9616-9650 2/4/2024 6 SBHP 128 9200 4064 9200 0.44 4064 Hilcorp North Slope 3800 Centerpoint Dr, #1400, Anchorage, AK STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Niakuk Oil Pool 9200 TVDss 0.76 Printed Name Jeff Allen Date June 11, 2024 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Jeff Allen Title Reservoir Engineer Form 10-412 Rev. 04/2009 INSTRUCTIONS ON REVERSE SIDE Digitally signed by Jeff Allen (969) DN: cn=Jeff Allen (969) Date: 2024.06.11 13:44:33 - 08'00' Jeff Allen (969) 6. Oil Gravity: 27 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) P1-13 50029223720000 O 640180 Kuparuk 8199-8376 5/22/2023 1398 SBHP 161 8600 3574 8800 0.11 3596 Printed Name Jeff Allen Date June 11, 2024 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Jeff Allen Title Reservoir Engineer 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Pt McIntyre Oil Pool 8800 TVDss 0.77 Hilcorp North Slope 3800 Centerpoint Dr, #1400, Anchorage, AK STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: Form 10-412 Rev. 04/2009 INSTRUCTIONS ON REVERSE SIDE Digitally signed by Jeff Allen (969) DN: cn=Jeff Allen (969) Date: 2024.06.11 13:45:17 - 08'00' Jeff Allen (969) 6. Oil Gravity: 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) 23. All tests reported herein were made in accordance with the applicable rules, regulations, and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. 7. Gas Gravity: Prudhoe Bay Unit Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 Prudhoe Bay Field, Raven Oil Pool 9850 TVDss 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Printed Name Title Date Reservoir Engineer June 11, 2024Jeff Allen Jeff AllenCertified Digital Signature STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: Form 10-412 Revised 10/2022 Submit PDF and Excel to aogcc.reporting@alaska.gov Digitally signed by Jeff Allen (969) DN: cn=Jeff Allen (969) Date: 2024.06.11 13:45:54 - 08'00' Jeff Allen (969)