Charles Meade • Johnson Rice & Company L.L.C.

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CEO Rusty Hutson confirmed the JV program will add material production in 2026, which will impact the corporate decline rate, but said more specific details would be provided toward year-end. He noted that even a 1-2% reduction is substantial. Hutson also confirmed significant interest in various formations across the Western Anadarko, which the company is actively monetizing or developing.

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CEO Tom Ward explained that the production strength was due to solid, normal operations and minor bolt-on acquisitions, not a single major event. He confirmed the Brocklin 3MH is a deep Anadarko well and stated that its two-well pad would undergo a zipper frac completion starting in late August or early September.

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Executive Tom Ward explained that while the acquisition adds only 1,600 BOE/day, it includes 990,000 net acres, fitting their strategy of buying cash-flowing assets with 'free' land. He detailed the acreage locations and stated the team's expertise will lower operating expenses and increase production. Regarding operations, Ward confirmed the rig count will drop from four to two in June, with a potential third rig added in Q4 for deep gas drilling, all contingent on maintaining the annual reinvestment rate below 50%.

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CEO Tom Ward explained that the third rig is arriving imminently for a short Oswego program before a larger rig is brought in for a Deep Mississippian project. He expressed a long-term bullish view on natural gas, citing growing demand, and suggested prices could see a significant move up during the summer refill season.

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Executive Kevin White noted the acquisitions added about 5,000 Boe/day, which was not enough to move production outside the existing Q4 guidance range. Executive Tom Ward added that the new Custer County drilling targets are competitive on a rate-of-return basis and that the shift to pad drilling there could create a lumpier production profile in 2025.

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EVP Kirk Johnson detailed that after completing their largest winter season, they have transitioned to year-round construction. Current work involves building out the operations center on the slope and fabricating modules on the Gulf Coast. The next winter season will focus on gravel work for new pads, pipelines, and civil work. Johnson expressed confidence in hitting milestones for a 2029 first oil target and noted they expect to have 90-95% of project contracts secured by year-end.

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Kirk Johnson, SVP of Global Operations, confirmed that the Nuna project, which saw first oil in December, is a prime example of new investment opportunities in the Alaska base business. With two wells online and eight more planned for 2025, he stated that Nuna's production is expected to more than offset the base decline in Alaska for the next year. He also highlighted other targets like Coyote and Narwhal that position the business for sustained production and modest growth.

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Kirk Johnson, SVP of Global Operations, confirmed the once-in-five-year Surmont turnaround went 'really quite well,' with the post-turnaround production ramp-up occurring faster than predicted. He also noted that they are now at full run rates on Pad 267 and plan to add a new pad every 12-18 months, with the next one expected to achieve first oil in 2026.

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CFO Scott McNeely explained the solar project's marketing was intentionally delayed until after the adjacent data center deal was finalized, and the current timeline shift reflects the final negotiations and a focus on long-term value over accelerated cash flow. Regarding the Devon deal, McNeely described it as a significant contract where an operator is directly securing long-term pore space from a landowner, highlighting its strategic importance. CEO Jason Long added that the agreement covers pore space on both the Speed Ranch and East State Landbridge properties.

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Executive Scott McNeely detailed the data center timeline, starting with a 2-year site selection period, after which lease payments are expected to ramp to $8 million annually during construction, with further upside from power and water sales as phases come online. He added that the Wolf Bone Ranch integration was seamless and has already validated the acquisition thesis by attracting significant commercial interest due to its strategic location and infrastructure access.

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Scott McNeely (executive) stated the two acquisitions cost approximately $47 million for about $9 million in current EBITDA, representing a 5x multiple. He highlighted synergies with existing operations and the WaterBridge platform. McNeely also addressed the 2025 guidance, explaining that growth is driven not just by oil and gas activity but also by diversified projects like the solar facility and the data center, which are less correlated with E&P capital discipline.

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President, CEO & Director Eric Hambly acknowledged a large discovery would create material development CapEx pressure. While appraisal costs are manageable, they would evaluate farming down their high working interest to fund a large-scale development but are not pre-committed to it. As operator, Murphy retains flexibility on the project's pace. He estimated a major find would require at least two appraisal wells.

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President and CEO Eric Hambly clarified that the Khaleesi-2 workover is a simple safety valve replacement, while Marmalard-3 is a more involved sidetrack. On Vietnam, he explained the new Lac Da Hong discovery, while smaller, is significant because it found oil in the same reservoir as the larger Hai Su Vang discovery but at a deeper depth, which de-risks the overall system and is encouraging for the upcoming appraisal.

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President and CEO Eric Hambly expressed overall satisfaction with King's Quay's performance, noting they continue to find more pay to develop and are conducting a new seismic survey to identify further opportunities. He characterized the current issues as temporary mechanical problems. Regarding the Vietnam flow test, Hambly described the 10,000 barrel-a-day constrained rate as indicative of a high-quality reservoir. He stated that all preliminary test results are positive and are being evaluated to determine the total resource and plan the Q3 2025 appraisal well.

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CEO & Director David Rockecharlie explained that 'dislocation' refers to the high number of asset sale processes, particularly in the Eagle Ford, that were pulled from the market due to commodity price volatility. He attributed the strong Uinta results to 'good old fashioned performance of strong reservoirs' rather than a specific new technique, noting the industry's continued evolution in the basin.

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Executive John Rynd explained that market volatility typically causes a pause in decision-making rather than a defined bid-ask spread. He noted Crescent's advantage is its consistent, investment-driven strategy, which allows it to act with conviction. Regarding the Uinta wells, he stated they are in the core development window on the western side of the asset, with early results consistent with historical performance.

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CEO Kaes Van't Hof stated that the biggest signal for a 'green light' would be a reaction in the forward curve of oil prices. He noted that as OPEC unwinds cuts and U.S. production begins to struggle, the market will have to react. He remains 'cautiously optimistic' on 2026 but is focused on maintaining flexibility for the remainder of 2025.

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Chairman and CEO Travis Stice stated the letter is primarily for stockholders but acknowledged its public nature means a wider readership. President Kaes Van’t Hof elaborated that geologic headwinds are accelerating as the basin matures and is well-defined, making large, 10-20% efficiency-driven cost reductions much harder to achieve than in past cycles.

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President and CFO Kaes Van't Hof explained that while they are being conservative with guidance after only 20 days of combined operations, a key structural difference is Endeavor's internalized water business, which lowers its reported LOE by an estimated $0.50-$0.60 per BOE. He expects G&A per BOE to also decline. For 2025, he reiterated that key cost drivers are trending favorably.

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Chairman & CEO Andrew Inglis acknowledged the Jubilee decline, attributing it to a challenged shutdown, riser instability, and underperformance of eastern wells. He detailed a recovery plan centered on new 4D seismic data and a consistent drilling program, aiming to restore production to around 90,000 bbl/d. For GTA, Inglis outlined a multi-step cost reduction strategy: achieving steady-state production, eliminating startup costs, refinancing the FPSO lease, and exploring more competitive operating models.

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Chairman and CEO Andrew Inglis described Phase 1+ as a capital-efficient brownfield expansion to fully utilize existing infrastructure, with a target of 2030. For Jubilee, he outlined key guidance assumptions: achieving 100% voidage replacement, a planned Q1 shutdown, and the delivery of two new wells in H2. Regarding the GTA wells, Inglis clarified that positive early data on flowing pressures provides greater confidence in the size of the reservoir connected to each well.

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CEO Andrew Inglis explained that the 2025 CapEx reduction to ~$400 million prioritizes free cash flow, with the primary change being the deferral of the Tiberius project by about a year. For Jubilee, he stated that modern processing will allow the new 4D seismic data to inform the 2025 drilling program, enabling them to balance an early start with incorporating the new insights for well selection.

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CEO Nicholas O’Grady clarified that the capital budget reduction effectively removes the previously allocated growth capital. President Adam Dirlam and O'Grady added that the spending decrease is driven by operators rationally deferring activity to preserve inventory for better pricing, not by NOG non-consenting wells, as election rates remain very high.

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CEO Nicholas O'Grady confirmed the conservative guidance implies a relatively flat profile before a year-end ramp, but noted pull-forwards are possible. He explained the 2026 outlook was provided because a significant build in the wells-in-process list required clarification on where capital was being deployed to drive long-term growth.

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CFO Chad Allen clarified the Q4 TIL forecast is '25 plus,' with timing being variable. Regarding the Uinta, CEO Nicholas O'Grady stated that while it's early in the operator transition, SM Energy's plans affirm NOG's underwriting thesis. President Adam Dirlam added that initiatives like a new sand mine and longer laterals are expected to enhance returns in the basin.

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CEO Christopher Stavros confirmed that the strong well performance was indeed a key part of the company's "appraise, acquire, grow" strategy. He cited a recent example where outperforming appraisal wells in an area led to an opportunity to acquire more acreage, expanding the development footprint. He implied this successful pattern is what led to the recent acreage additions but declined to provide specific GPS locations.

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COO Daniel Harrison confirmed the tweaked completion design on the Elijah well (tighter 100-foot stages) has been used on the Mann and Bell Meyer wells and is showing very encouraging early results. President/CFO Roland Burns and CEO M. Jay Allison confirmed that the Angelina River trend is a 'reasonable inference' for the non-core divestiture program.

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COO Daniel Harrison confirmed that having vertical well control was key for the first step-out to manage risk, but future wells will spread out and may require pilot holes where control is lacking. CEO Miles Allison elaborated that the location was chosen based on a combination of well control and 3D seismic, similar to their initial Circle M well. Allison emphasized the strategy is to prudently derisk the entire 520,000-acre footprint, focusing first on drilling to hold leased acreage before exploring HBP acreage further west.

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CEO Miles Allison emphasized the company's patient, data-driven approach, noting they drilled the deepest, hardest wells first to prove the concept. He stated the goal is to materially derisk the entire footprint in 2025. COO Daniel Harrison added that rock thickness doesn't always correlate to well performance. Regarding older wells, Harrison said they have been conservative with drawdowns and are now tweaking their approach to optimize cleanup and flow rates.

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COO Daniel Harrison stated the Sebastian well's strong performance was not luck and is considered "very, very repeatable." For cost replication, he highlighted drilling consistency and the inherent 5-7% cost savings from pad drilling versus single wells as key factors. He added that longer laterals also contribute to lower per-foot costs and expects future pad-drilled wells to achieve even better metrics.

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COO Jeff Leitzel stated it was early but confirmed the discovery was 125 feet of consistent oil-bearing sands and that initial economics justify a platform, with the next step being partner alignment for FID. SVP Keith Trasko characterized the Eagle Ford deal as a unique opportunity, noting that while EOG is always looking for bolt-ons, he wouldn't expect another of this size and undeveloped nature.

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Chairman and CEO Ezra Yacob indicated that EOG expects moderated U.S. supply growth in 2025, following a slowdown in 2024, based on persistently low rig counts and DUC inventories. COO Jeff Leitzell confirmed that the permit for the Beehive prospect has been secured, and the company plans to drill the well in 2025, leveraging its shallow-water expertise from Trinidad.

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CEO John Christmann reported that Alaska operations are proceeding smoothly but they have not yet reached the target pay zones. Regarding the Permian, he confirmed 'fantastic' results in Northern Howard County, which will enable tighter well spacing and increased resource capture on future pads, though he refrained from providing more specific details.

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CEO John Christmann explained that the slide's purpose is to 'bring the project to life' now that it has reached a final investment decision. He stated it provides visibility into a real project with a 2028 production start, showing the FPSO placement and the development fairway, which includes future tie-back potential.

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Chief Operating Officer Clay Gaspar confirmed the simple math: a 14% efficiency gain on 16 rigs equates to the output of roughly 14 rigs. Chief Financial Officer Jeff Ritenour addressed the gas question, stating that pricing should improve after current pipeline maintenance in the basin concludes, but he declined to give a specific timeline. He also noted that Devon has not changed its own production plans as a result of Matterhorn coming online.

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Blake Sirgo, SVP of Operations, outlined a three-step response to a gas market recovery: lifting curtailments, boosting compression, and then restarting D&C activity. He clarified that large-scale 'row' developments are unique to Culberson County due to contiguous acreage. In New Mexico, efficiency is gained through 'vertical rows' by developing stacked pay zones from a single pad.

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