SENATE FINANCE COMMITTEE January 17, 2024 9:02 a.m. 9:02:02 AM CALL TO ORDER Co-Chair Stedman called the Senate Finance Committee meeting to order at 9:02 a.m. MEMBERS PRESENT Senator Lyman Hoffman, Co-Chair Senator Donny Olson, Co-Chair Senator Bert Stedman, Co-Chair Senator Click Bishop Senator Jesse Kiehl Senator Kelly Merrick Senator David Wilson MEMBERS ABSENT None ALSO PRESENT John Boyle, Commissioner, Department of Natural Resources; Travis Peltier, Petroleum Reservoir Engineer, Division of Oil and Gas Alaska Department of Natural Resources, In room; Derek Nottingham, Director, Division of Oil and Gas, In Department of Natural Resources SUMMARY ^PRODUCTION FORECAST - DEPARTMENT OF NATURAL RESOURCES 9:12:32 AM JOHN BOYLE, COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES, introduced himself. He remarked that the forecast was done annually to help inform the people of Alaska, and to inform the decisions of the legislature. He felt that Alaska was on an exciting trajectory with more development, activity, and production on the North Slope. He noted the significant investment in the North Slope, and remarked on the type of operators in the North Slope. He stressed that there were multiple projects and commitments that had been years in the making. He pointed out that the projects were organized and initiated over the course of years and decades. He felt that the policies set out by the legislature created a stable and predictable economic climate for the producers. 9:16:01 AM Commissioner Boyle stressed that the legacy fields were considered the solid foundation for oil development, and ensure the reduction in the production decline. He noted that the presentation would point to some new projects and developments. He remarked that there was enthusiasm about the new entrants on the North Slope. He noted the projects under development on state land, which would enhance the state's economic standing. He remarked that there was effort toward developing alternative energy resources, but there was still reliability on petroleum resources. 9:22:08 AM TRAVIS PELTIER, PETROLEUM RESERVOIR ENGINEER, DIVISION OF OIL AND GAS ALASKA DEPARTMENT OF NATURAL RESOURCES, IN ROOM, (DNR) Alaska Department of Natural Resources discussed the presentation, "Fall 2023 Oil Production Forecast, Senate Finance Committee" (copy on file). He spoke slide 2, "Agenda": • Introduction and Forecast Preview • FY 2023 in Review • DNR Fall 2023 Production Forecasting Approach Fall 2023 Forecast Results and Summary • Appendix 9:25:01 AM Co-Chair Stedman urged that the presentation should be directed at people who might be learning about production forecasts for the first time. Mr. Peltier looked at slide 3, "Fall 2023: North Slope Annualized Forecast." He stated that the axis would be consistent with the remaining slides in the presentation. He remarked that the years listed were considered "fiscal years." He noted the number of line charts, official forecast, the high forecast, and the low forecast. He remarked that the forecast was intended to be bracketed to give an accurate expectation. He stated that there was also an aggregate summary based on North Slope worker personal evaluation. He stressed that the forecast was only for existing fields. Co-Chair Stedman requested a delineation of barrels that would be impacted by the evaluation. He noted that "all oil is not equal." He asked that there be a consideration of royalty differences, because of the significant impact to the state treasury. Mr. Peltier agreed to provide that information. 9:29:06 AM Mr. Peltier addressed slide 5, "FY 2023 As Forecasted by DNR in Fall 2022: How Did We Do?" • Actual FY 2023 production was within DNR's forecasted range • DNR's mean forecast was 3 percent higher than actual FY2023 production • Factors currently shaping the forecast horizon: • Industry interest is expanding in Brookian age plays (i.e., Nanushuk) across the North Slope • Evolving ESG influences continue to challenge capital allocation decisions in Alaska, but companies and investors are also adapting • Federal regulatory changes and leasing restrictions present challenges Mr. Peltier recalled the reasons for the shortfalls. He pointed out that some fields had some production challenges due to the reduced efforts of the drills in the fields. Mr. Peltier pointed to slide 6, "FY 2023 Summary: North Slope": Highlights (FY2023 vs FY2022) • All fields are generally expected to see a year-on- year decline • Compared to FY2022, in FY2023 North Slope production increased by 1 percent (2,890 bopd) • Decreases • Badami: Best producing well offline for much of FY2023, back online in May 2023 • Colville River and Kuparuk River: Natural decline offset with development drilling • Endicott and Northstar: Natural reservoir decline • Point Thomson: Single production well suffering technical challenges which continue into FY2024 • Increases • Greater Mooses Tooth: GMT2 pad continued development drilling • Milne Point, Nikaitchuq and Oooguruk: Production growth due to infill drilling and rig workover efforts • Prudhoe Bay: Growth from improved facility reliability and increased gas throughput in the winter 9:38:19 AM Senator Bishop requested more information about bullet three, specifically about the technicalities related to the point. Mr. Peltier believed that the gas throughput had to do with the compressors. He stressed that the more the operator could do with the gas, the higher the oil production. Co-Chair Stedman queried the number related to FY 24. Mr. Peltier stated that it would be addressed in the presentation. Co-Chair Stedman requested the capacities and restraints of the processing facilities, and queried the reason for differentiating between federal and state lands. Mr. Peltier deferred to Mr. Nottingham. 9:41:54 AM DEREK NOTTINGHAM, DIRECTOR, DIVISION OF OIL AND GAS, IN DEPARTMENT OF NATURAL RESOURCES, replied that the revenue on state lands saw royalties of approximately 12.5 percent. He stated there may not be direct royalties from federal lands. 9:43:43 AM Mr. Peltier displayed slide 7, "Status Update of Key Future Projects: North Slope": Pikka Project Final Investment Decision (FID) approved in August 2022 for Pikka Phase 1. Project first oil anticipated in 2026. Project construction and drilling activities ongoing, and project first oil anticipated in Q2 of 2026. Peak design capacity rate, Phase 1: 80,000 bopd Willow Awaiting BLM Record of Decision (ROD) on SEIS. FID cannot be made before the ROD is made. First oil expected 6 years after FID, if approved. BLM ROD on SEIS issued in 2023 and Conoco started construction activities in April 2023. FID announced December 2023. First oil expected in 2029. Peak rate: 180,000 bopd CRU Narwhal CD8 Sustained production from CD8 could commence as early as 2028, pending stakeholder alignment, permitting, internal studies and alignment. This conceptual first oil date remains consistent with the 23rd POD submitted in 2021. The conceptual first oil date changed to 2030 in the 25thCRU POD submitted in 2023, pending stakeholder alignment, permitting, and internal studies and alignment. Peak DNR estimates >32,000 bopd MPU Raven Pad November 2022 Hilcorp applied for approval to construct a new drilling and production pad (R Pad) within the Milne Point Unit. DNR approval granted for R Pad construction in February 2023 within the Milne Point Unit. Construction activities ongoing. Peak DNR estimates 10,000 bopd. Analogous to the 2018 M Pad development at MPU. KRU Nuna-Torok 2022 KRU POD states rotary drilling is planned in Q3 of 2022 with an additional injector/producer pair for additional Torok reservoir appraisal to inform future developments. Conoco project funding approved in 2023, and subsequently DNR approved drill site 3T expansion activities. Construction activities are ongoing, and first oil is anticipated in 2025. Peak rate up to 20,000 bopd 9:48:09 AM Mr. Peltier spoke to slide 8, "FY 2023 Summary: Cook Inlet": Highlights (FY 2023 vs FY 2022) • All fields are generally expected to see a year-on- year decline • Compared to FY2022, in FY2023 Cook Inlet production decreased by 4 percent (370 bopd) • Oil from the Cook Inlet basin critical to the supply of in-state refineries • Decreases • Beaver Creek, Granite Point, Hansen, McArthur River and Swanson River experiencing natural decline • Redoubt Shoal natural decline and well attrition partially offset by rate-adding well work • Increases • Trading Bay and West McArthur River offsetting natural decline with rate-adding well work Mr. Peltier stated that they had recently changed their forecasting methodology in 2022, and had used the same methodology for the current forecast. 9:50:58 AM Mr. Peltier. pointed to slide 10, "DNR Forecast Process: Projects/Pools Included in Forecast": DOG performed bottoms-up decline curve forecasts for all producing pools Forecast of current production uses AOGCC publicly available data 39 pools (ANS and CI), producing as of 6/30/2023 DOG engaged with operators through DOR-arranged in- person and in-writing interviews 15 projects under development/under evaluation were researched/reviewed Forecasts for these projects use confidential information from operators Future production from these projects was adjusted and risked for scope of contribution, chance of occurrence and start date Mr. Peltier looked at slide 11, "Categories of Production: Ongoing/Current vs. Future Production": Current Production (CP): • Ongoing production from existing fields • Features and considerations: • Well and facility uptime Operator spending to maintain base production • Reservoir management Projects Under Development (UD) and Under Evaluation (UE): • Future production requiring new investments • Rate contribution: • Uncertainty in future well performance • Uncertainty in project scope • Project occurrence and timing: • Uncertainty in timing (including outright project cancellation/deferral) • Commerciality risk (economic, regulatory, etc.) 9:55:14 AM Mr. Peltier looked at slide 12, "Major Projects Under Evaluation (UE) Considered in Fall 2023 Forecast": General Characteristics: ? Projects that were not online by end of FY2023 (data cut-off date of 6/2023) ? Higher risk factors than currently producing fields ? Known discoveries with identifiable operators ? Require major investments North Slope Major Projects: ? Willow ? CRU Narwhal CD8 ? Horseshoe Stirrup ? Pikka Unit Dev. ? Pikka Phase 2 ? Quokka/Mitquq ? Mustang ? Nuna-Torok ? MPU Raven Pad ? Theta West ? Talitha ? Alkaid ? Liberty Unit ? PTU Expansion ? Sourdough Project 9:59:29 AM Mr. Peltier discussed slide 14, "Fall 2023: North Slope Annualized Forecast": ? Short Term: ? DNR forecasts FY2024 annualized average daily statewide production at 478 MBOPD, and North Slope production at 470 MBOPD, with a range of 422 MBOPD and 519 MBOPD ? Long term: ? Long-term forecast reliability is gauged by general comparison between DNR and operators' aggregate forecasts. Operators' long-term outlook falls within DNR's long term forecast range ? Specific differences are expected and do highlight DNR's ground-up uncertainty analysis on all included projects ? Outlook on production assumes that operators' plans, and other project drivers remain unchanged Mr. Peltier observed that the graph showed close alignment between the operator forecast and DRN's official forecast in 2024. He explained that the department expected some differences over time, as new production from major projects came online. He explained that the DNR forecast relied on the assumptions of operator behavior. Co-Chair Stedman asked if production was up or down for FY 24. Mr. Peltier relayed that the forecast was down. Co-Chair Stedman queried the exact amount that it was down. Mr. Peltier needed more information about the two comparisons. He stated that the forecast values used actual data through November. He stressed that December values were not available until the following January. He agreed to provide further information. 10:04:28 AM Mr. Peltier displayed slide 15, "Fall 2023: AK Statewide Annualized Forecast (Expected Case with Production Categories)": ? Current Production (CP) remains the backbone of state production in near and medium term ? Under Development (UD) segment represents production expected from wells drilled in FY2023 ? Near term (i.e. 3 to 4 years out), the new forecast is lower than the Spring 2023 Forecast due to greater than expected decline rates in key fields and less than expected production results from recent development projects ? Under Evaluation (UE) begins to play a more significant role in production in the next 5 to10 years as Pikka, Willow, and other major projects materialize 10:08:43 AM Co-Chair Stedman referenced published data from DNR about the price and volume per day. He thought the reduction seemed to be fairly linear. He asked Mr. Peltier to break the data down into separate fields. He mentioned sensitivity models from the Legislative Finance Department (LFD), which were helpful in considering revenue. Commissioner Boyle agreed to work with the committee to provide the data and the format. Co-Chair Stedman remarked that there would be a condensed examination of the upcoming three years to ensure that the state does not run out of money. Co-Chair Hoffman requested the leases that exist for gas on the North Slope and any gas development. He queried any changes in the approaches to bring gas to tidewaters. Mr. Peltier addressed slide 16, "Fall 2023: Production Forecast Summary": ? DNR forecast continues to use the best information available to DNR/DOR to generate production outlooks for oil fields within the state, with a focus on generating accurate near-term and realistic long-term forecasts ? Fall 2023 forecast is a static view on production; DNR's outlook is updated annually (Fall and Spring) to incorporate latest operator plans and the State's official updated price outlook at the time of the forecast ? DNR's Fall 2023 outlook shows mean annual production of approximately 480 - 500 MBOPD in the first few years of the outlook period, while increasing towards the middle and end towards 630 MBOPD based on the current snapshot of operators' plans ? Production estimates from projects under evaluation account for several considerations such as technical factors, commercial factors, and project execution risks Co-Chair Stedman requested final comments. 10:14:37 AM Commissioner Boyle appreciated the counsel on the narrower timeframe to assist in the budget modeling. He felt there was reason for optimism, because of the new operators on the North Slope. He felt that competition should enhance production and revenue. He pointed out that there was an evaluation of risk from federal policy positions. Co-Chair Hoffman requested the Hillcorp ten-year production. He queried the potential calculation if the field had not been sold by BP to Hillcorp. Commissioner Boyle agreed to provide that information. Co-Chair Stedman felt that the dominant subject would be related to Prudhoe Bay, and their presentation. Co-Chair Stedman discussed the following day's agenda. ADJOURNMENT 10:20:41 AM The meeting was adjourned at 10:20 a.m.