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CEO Ezra Yacob stated that while the company can be counter-cyclical, the primary focus after the Encino deal is on organic execution and smaller bolt-ons rather than large M&A. He clarified that EOG's gas business is strategically ramping up to meet contracted LNG demand, which provides significant revenue uplift and allows for paced, value-driven investment through price cycles.

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CEO Ezra Yacob noted that while Dorado returns are compelling, the broader portfolio delivers over 100% ATROR at $55 oil and $3 gas, and investment decisions consider multiple metrics beyond returns. COO Jeff Leitzel explained the CapEx cut is mostly in H2 2025 in flexible basins like the Delaware and Eagle Ford, and the plan was designed to maintain flexibility for 2026 without impacting capital efficiency.

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SVP, Exploration and Production, Keith Trasko clarified that the lower Eagle Ford activity in 2025 is a normalization after elevated levels in 2023-24 and that the play remains a high-return core asset. CEO Ezra Yacob confirmed that the domestic exploration program remains active with wells planned for 2025, but the focus is on high-return opportunities, regardless of commodity type.

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SVP of Exploration and Production Keith Trasko clarified that the $6-$8/BOE finding cost is a near-term expectation for the volatile oil window, whereas the $5/BOE target reflects the entire acreage at full-field development. COO Jeff Leitzell added that the PRB program is now split between the Mowry and Niobrara formations, with encouraging early results from the Niobrara showing a productivity increase of over 10% versus 2023. Activity levels there are expected to remain consistent in 2025.

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Chairman and CEO Ryan Lance stated the Anadarko asset was mostly gas and confirmed the decision to raise the divestiture target to $5 billion by the end of 2026 was a result of their standard internal portfolio review. He stressed they are not 'fire selling' assets and will only sell when they receive good value, expressing confidence in their ability to market the identified assets successfully.

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SVP Andy O'Brien and CEO Ryan Lance characterized the savings as 'nits and gnats' spread across the entire global portfolio. O'Brien explained it was a combination of deflation, optimization, and deferrals of non-critical items with no material impact on production this year or next. Lance confirmed the cuts were distributed across both the Lower 48 and Global Operations divisions.

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Andy O'Brien, SVP of Strategy, specified that the assets being sold produced approximately 15,000 barrels of oil equivalent per day last year. He characterized the assets as non-core Southern Delaware, which implies a typical commodity mix for that region.

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Andy O'Brien, SVP of Strategy, provided details for Q4, stating turnarounds would be minimal at about 5,000 barrels per day. He reiterated that full-year OpEx guidance is unchanged and that Q4 CapEx is tracking as expected, influenced by lower non-operated activity, reduced Port Arthur LNG spend, and some service cost deflation. He highlighted that the annual production guidance was raised without increasing the operating cost guidance.

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Co-CEO Will Hickey confirmed he expects net well costs per foot to decline in the second half, driven by efficiency gains and some service cost deflation, which should offset tariff impacts on casing. Co-CEO James Walter affirmed that a flattish to low-single-digit growth profile is the right expectation in the near term, given the current market uncertainty.

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Hays Mabry, an executive, indicated that while maximizing molecule value is a key focus, specific updates on the marketing strategy would be shared on a future call. He explained that the company's return resiliency is primarily driven by significant reductions in D&C cost per foot over the last 18 months, which has largely offset the impact of lower crude prices.

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Executive Hays Mabry reiterated that the company's buyback strategy is a 'rifle shot' approach, reserved for true market dislocations to maximize value, and that current conditions don't meet that threshold. Co-CEO William Hickey explained that 2025 cost reductions are driven by realizing synergies from recent acquisitions, like the Brea Draw asset, and favorable midstream contract terms aligned with the development plan.

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Co-CEO William Hickey projected that Q4 CapEx would be slightly down from Q3, primarily due to working interest mix rather than a change in activity. He confirmed that while they could achieve their original well count with fewer rigs (e.g., 11 instead of 12), the final 2025 plan for capital and rig count has not yet been decided but will incorporate the new efficiencies.

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President, CEO & Director Eric Hambly and SVP - Operations Chris Lorino acknowledged disappointing runtime at Terra Nova, which impacted Q2 and the Q3 outlook. Regarding costs, Hambly expressed confidence in the $10-$12/bbl LOE range, noting that Q2's underlying rate was even lower without workovers. Lorino added that significant, durable cost reductions in the Eagle Ford also support the lower LOE profile.

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President and CEO Eric Hambly stated that in a $58-$60 oil price environment, the company would be comfortable maintaining its $1.1B-$1.3B capital plan and would invest through the cycle. He explained the Canada downtime was a short-lived, third-party logistical issue with a shuttle tanker, not an asset problem. He projected LOE would remain elevated in Q2 (around $14/boe) due to workover activity before dropping to the $10-$11/boe range in the second half of the year.

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President and CEO Eric Hambly confirmed that Suncor, the operator of Terra Nova, made significant operational reliability improvements late last year, boosting confidence in 2025 production. Regarding the Eagle Ford, he stated the new completion design significantly underperformed, producing at 50-60% of the expected rate, but the issue was isolated to one pad. He clarified that the higher Eagle Ford production expected in 2025 represents a return to the upper end of the guided 30,000-35,000 barrel-a-day range, consistent with prior years, due to a steadier program.

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President and COO Eric Hambly clarified that the Eagle Ford strategy aims for a more consistent drilling profile to achieve higher average annual production. He expects Eagle Ford output to grow by 3,000-4,000 bbl/d in 2025. For the Tupper Montney, the plan is to maintain production near plant capacity, consistent with prior years. Hambly acknowledged that 2024 workover expenses were an outlier and unusually high, and he does not anticipate similar significant workovers beyond the two planned for Q4.

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President & COO Clay Carrell reported encouraging results from the Wolfcamp B, noting earlier oil cuts and ongoing work to customize completion designs. Regarding inventory, he stated that while the Permian currently offers slightly better returns, the company is focused on enhancing resources across all basins through cost reductions, efficiency gains, and technical work to identify secondary objectives and elevate overall inventory quality.

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CEO M. Doyle and CFO Marianella Foschi explained the DJ Basin decline was expected due to a 4-5 month period with no new wells online, allowing base decline to take full effect. A delay in Q1 turn-in-lines pushed some production growth into Q3, resulting in flat Q2 volumes. On service costs, Mr. Doyle confirmed they are seeing market weakness and are actively negotiating with suppliers for cost reductions, expressing confidence that these savings will outweigh potential tariff pressures.

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CEO Chris Doyle reiterated that the primary goal for 2025 is hitting the $4.5 billion net debt target, and any M&A would likely be funded by asset sales. Doyle attributed the Q4 LOE increase to winterization projects and higher workover activity in the Permian. CFO Marianella Foschi added that the increase was almost entirely from the Permian, with DJ LOE remaining flat, and that full-year costs remain peer-leading.

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CEO M. Doyle confirmed the 2 DJ/4 Permian rig split was 'not far off' for a maintenance program. He explained that the Wolfcamp D became competitive due to better-than-expected capital execution and surprisingly high well productivity, which now allows it to compete for capital with the A and B zones and will likely comprise 20-30% of the future program.

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CEO Kaes Van’t Hof indicated it is reasonable to expect a board review of the base dividend in the near future and reaffirmed the commitment to return 100% of free cash flow once the $1.5 billion net debt target is hit. On M&A, he reiterated a patient stance, stating the priority is to allow investors to realize the benefits of the two recent transformative deals.

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CEO Kaes Van't Hof affirmed that at a flat commodity price, distributions are expected to grow due to the drop-down's accretion. He explained that the lower tax guidance is a direct result of lower oil prices and projected that G&A per BOE should decline following the drop-down, as Q1 is typically the peak for such expenses.

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CEO Kaes Van’t Hof illustrated the fragmentation by noting that Viper, the largest public minerals company, holds only 3.3% of the Permian's royalty barrels, whereas top E&Ps control 60-70% of gross production. He agreed the deal is accretive and stated a near-term goal is to achieve $1 per share of distributable cash flow each quarter.

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CEO Travis Stice suggested a pro forma leverage target of around 1.5x turns would be reasonable, emphasizing that Viper's strong free cash flow model allows for rapid deleveraging. Regarding future M&A, Stice confirmed that Viper's increased scale and unique structure, which allows for tax-deferred transactions via OpCo units, have attracted significant interest. He stated that while the company will remain selective, a large opportunity set for high-quality mineral consolidation exists.

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EVP of Business Units Michael Deshazer confirmed the assets are fully integrated from an operational and cultural standpoint. He stated that all wells in progress at the time of the acquisition are meeting or exceeding expectations. Going forward, he emphasized that new wells will reflect Coterra's own designs for spacing and completions, and should deliver 'Coterra results.'

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SVP of Business Units Michael Deshazer confirmed continued activity in the Dimmit box in the coming years, including overfill wells and new long-lateral developments. Chairman, CEO and President Thomas Jorden stated that at approximately $70 oil and $4 gas, the returns between the Permian and Lower Marcellus programs are 'very comparable'.

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Blake Sirgo, SVP of Operations, confirmed that current efficiencies are repeatable and would improve the three-year outlook, but the final plan depends on 2025 decisions. Tom Jorden, CEO, elaborated on M&A, stating they would only 'stretch' for a high-quality asset that could establish a new core focus area, not just for incremental bolt-ons, reflecting their disciplined approach in a competitive market.

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CEO Kaes Van't Hof stated that the primary trigger for a 'red light' would be oil prices printing in the low $50s for a month, but emphasized that Diamondback has already done its part in cutting capex. For the parent company, he reiterated the commitment to return at least 50% of free cash flow to shareholders, with the potential to go higher in periods of share price weakness, but avoided setting a specific debt target due to the need for flexibility at the E&P level.

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President Kaes Van’t Hof explained that higher gas transportation costs were due to taking more molecules in-kind, which should improve price realizations. COO Daniel Wesson attributed lower LOE to resolving a one-time issue. Van't Hof confirmed the buyback strategy is inverse to activity, with more capital allocated to repurchases in the current environment.

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President Kaes Van't Hof described Double Eagle as good operators with well costs in the $625-$650 per foot range, noting the biggest synergy is applying Diamondback's lower cost structure. He emphasized the deal was timed to acquire upside inventory rather than high-decline production. He clarified that capitalized interest, which is an accounting rule for debt-funded acquisitions, is not in the CapEx budget but is included in their internal math for shareholder return commitments.

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President and CFO Kaes Van't Hof confirmed the base case for 2025 remains hitting 480,000 barrels of oil per day, but acknowledged the total BOE guidance is conservative and likely to be closer to 840-850 MBOE/d. The final plan will be dictated by the macro environment in January. He stated that any cash tax benefit from the Endeavor acquisition would not be material and the rate should remain in the mid-to-high teens.

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EVP & COO Beth McDonald clarified the CapEx increase is primarily for high-return, non-operated projects in the Midland Basin, with Q4 CapEx expected to decrease. She attributed the Uinta's stellar well performance and lower costs to the successful integration of SM's technical expertise with XCL's operational execution and optimized completion designs. President & CEO Herbert Vogel noted the new wells will add production in 2026.

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President and CEO Herbert Vogel and COO Beth McDonald explained that the DUC count is an output, not a managed target, and the high year-end number was a result of the acquired asset's drilling pace. On Uinta performance, Mr. Vogel noted Q4 was a 'noisy' transitional quarter with limited operational control. CFO Wade Pursell emphasized that the cash production margin in Uinta was nearly identical to the Midland Basin's, meeting a key objective of the deal.

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CFO Michael Kennedy emphasized that while Antero is uniquely positioned for in-basin demand, any deal must be accretive and NYMEX-based, not tied to volatile local pricing. He declined to provide a timeline for announcements. Regarding returns, he stated the focus remains on opportunistic buybacks and debt management, and a dividend has not been a focus.

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CFO Michael Kennedy reiterated their opportunistic approach, explaining they accelerated buybacks in March when a disconnect appeared between share value and fundamentals. He confirmed that with little debt remaining, share buybacks will naturally become a larger percentage of free cash flow use. On in-basin demand, Kennedy confirmed Antero is in discussions due to its scale but is not interested in selling gas on a local basis for its maintenance program, as its current FT commitments secure premium Henry Hub pricing.

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CFO Michael Kennedy indicated that production and capital spending would be relatively even throughout 2025, with a slight potential increase in Q2 due to the timing of a completion crew. Regarding the JV, he explained that the gross program size is larger than the net maintenance capital budget, which necessitates the JV partner to keep the program efficient and Antero's net spending and production flat.

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CFO Michael Kennedy clarified that a maintenance capital level of approximately $700 million is needed to sustain production in the 3.3 to 3.4 Bcfe/d range. He noted that the Q4 2024 production is guided to approximately 3.35 Bcfe/d, which is also the expected level for 2025.

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CFO & President Alan Shepard confirmed a lull in completion activity and lower CapEx in Q3, with a pickup in Q4. COO Navneet Behl stated that the team is aggressively working to further reduce Utica well costs, which are already below target, and noted that recent Utica wells are performing slightly above expectations. Shepard added that Utica wells are now competitive with core Marcellus assets.

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Chief Financial Officer Alan Shepard clarified that CNX remains a de minimis cash taxpayer, with any perceived noise resulting from the hedge book, and that the company does not expect to be a material cash taxpayer until 2027 or 2028. He affirmed that management sees value in share repurchases when they are executed. Regarding 45Q, he stated they have no information beyond what is publicly available.

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Ravi Srivastava, President of New Technologies, clarified that Q4'24 free cash flow was boosted by timing of volume monetization and the annual run-rate is expected to be around $75 million. He also noted it's too early to gauge the new administration's stance. CFO Alan Shepard confirmed the production strategy, emphasizing the built-in optionality to accelerate activity if market conditions warrant.

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CFO Alan Shepard clarified the turn-in-line change was a minor timing shift across the year-end, not a reduction in activity. Ravi Srivastava, President of New Technologies Group, noted potential credit values ($60/tonne for 45Q, up to $3/kg for 45V) but stressed the impact is unclear until final rules are out, with 45V guidance expected in Q4.

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EVP and CFO William Lambert outlined a three-pronged approach for free cash flow after the dividend: 1) 'brick-by-brick' land acquisitions, 2) share repurchases, and 3) balance sheet management. He stated there is no set formula, and the company will remain opportunistic across all three buckets. Co-President Bryan Erman added that the brick-by-brick strategy is a continuous, core competitive advantage for Matador.

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Tom Elsener, EVP of Reservoir Engineering, clarified that the activity shift was a normal part of optimizing the completion schedule while moving from a 9-rig to an 8-rig program. Glenn Stetson, EVP of Production, confirmed strong results from the Ameredev assets and projected that Q3 production would be lower than Q2, with Q4 potentially slightly higher than Q3, subject to timing.

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Joseph Wm. Foran, Founder, Chairman, and CEO, stated the company is always open to opportunities for its midstream assets and highlighted the strategic value of flow assurance. Brian Willey, EVP and CFO, projected that 2025 midstream CapEx would be less than 2024's $225 million but still above the long-term maintenance level of $50-$75 million, which he expects to reach in 2026 once the system is fully built out.

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CEO Vicki Hollub and Richard Jackson, President, U.S. Onshore, asserted that the capital reductions were efficiency-driven and would not sacrifice production in 2026-2027. Kenneth Dillon, President, International Operations, added that supply chain deflation is creating further cost benefits. CFO Sunil Mathew addressed the chemicals outlook, acknowledging market challenges but expecting second-half improvement from rationalized supply and lower input costs, thus maintaining the current full-year guidance range.

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Vicki Hollub, President and CEO, stated that the LCV strategy remains unchanged. She acknowledged political uncertainty but stressed the critical need for CO2 in enhanced oil recovery for U.S. energy security. She expressed confidence that the business case for direct air capture and supporting policies like 45Q is compelling and that OXY can accelerate cost reductions, regardless of the political environment.

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CEO John Christmann emphasized that the recent asset sale was opportunistic, providing financial flexibility. CFO Ben Rodgers affirmed the company's commitment to its 60% shareholder return framework and stated they will remain opportunistic on both share buybacks and debt reduction. Regarding Egypt, President and CFO Steve Riney confirmed there was some unexpected Q1 downtime but that investors should expect a continued 'very slight decline' in gross oil volumes through the year.

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CEO John Christmann stated that the past-due balance in Egypt has been stable and he is optimistic about making progress on collections this year. CFO Stephen Riney detailed the $600 million trading gain outlook for 2025, attributing approximately $400 million to domestic pipeline trading and $200 million to the Cheniere LNG contract.

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CEO John Christmann cited a 'softer price environment' and the company's ability to efficiently sustain volumes with 8 rigs as the reason for the U.S. activity level. He reiterated that with the Permian and Egypt stable, Suriname will provide corporate growth starting in 2028. For Egypt, he noted the 11-rig program leads to a slight gross oil decline, which waterflood projects aim to mitigate, while the new gas program will add volumes over time.

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CEO Francisco Leon attributed the enhanced capital efficiency primarily to the mix of projects being executed. He referenced a slide in the earnings presentation showing a 9% year-over-year improvement, describing it as a result of fundamental "blocking and tackling" and applying CRC's operational expertise to the newly acquired Aera asset base.

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Francisco Leon (Executive) reported progress on drilling permits via alternative paths like field-level conditional use permits (CUPs), noting other operators have recently received permits this way. He expects a resolution for CRC in the second half of next year. On pipelines, he anticipates the legislature will address the issue in the next session, driven by market demand and the state's opportunity to attract significant capital.

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Interim Co-President and CFO Sergio Maiworm attributed the lower 2025 CapEx to significant drilling efficiencies from the West Vela rig, not a strategic shift. He stated that capital return plans will be refined with the new CEO, and confirmed the incremental Monument working interest cost approximately $12 million plus adjustments.

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EVP & CFO Sergio Maiworm explained that while specific Q3 downtime figures were not disclosed, the asset base outperformed expectations, and the company is confident in its full-year guidance. Interim President & CEO Joseph Mills confirmed that 2025 CapEx will likely be higher due to a delayed start to the 2024 drilling program shifting capital into the next year, along with commitments for the West Vela and Conquer rigs.

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CFO Geoff Trukenbrod clarified the $5 million Project Drake fee is an initial payment expected to be recognized as incremental revenue in Q4 upon finalizing agreements. CEO Jennifer Holmgren explained that current operating expenses are elevated because they include upfront development costs for major projects, which will be recouped upon transfer to partners. She also confirmed the company is forming partnerships beyond Brookfield, such as a completed JV with the Olayan Group, to accelerate project development and capture more upside.

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CFO Geoffrey Trukenbrod confirmed the back-half weighted revenue is driven by multiple projects expected to move into the construction phase. He explained that Q1 operating costs were higher due to one-time severance charges and normalized bonus accruals, following lower bonus-related costs in Q4 2023, and that these costs are expected to decrease.

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COO Daniel Harrison explained the cost premium for horseshoe wells is almost entirely on the drilling side, stemming from the extra day or two needed to execute the 180-degree turn. He noted completion costs are similar and that the initial cost estimate was conservative, with the first well already beating projections. He expects the 5-7% savings from pad drilling will further reduce the cost on future wells.

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