Charles Meade

Charles Meade, Research Analyst at Johnson Rice, asked about the evolving competitive landscape for acquiring new assets and what specific factors differentiate LandBridge's ability to enhance Surface Use Economic Efficiency (SUEE) compared to competitors.

Answer

Scott McNeely, CFO of LandBridge, acknowledged increased competition but highlighted LandBridge's "moat": unique and irreplicable land positions (especially along the Texas state line), a highly valuable partnership with WaterBridge providing competitive intelligence and granular updates, and a sophisticated operating team with in-house technical expertise (geological, electrical engineering). Jason Long, CEO, further emphasized the importance of leveraging technical expertise.

Charles Meade of Johnson Rice & Company L.L.C. asked for more details on the DBR solar project, specifically the reasons for the timeline shift and revenue recognition moving out of 2025. He also inquired about the new Devon Energy water disposal agreement and its context relative to the Speedway pipeline project.

Answer

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.

Charles Meade of Johnson Rice & Company L.L.C. inquired about the roadmap for the data center agreement, including future revenue milestones, and asked about the integration of the Wolf Bone Ranch acquisition and any new opportunities identified since the deal.

Answer

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.

Charles Meade asked about the financial multiples and potential synergies of the two recent land acquisitions. He also questioned the company's optimistic 2025 activity outlook, contrasting it with broader E&P trends of decreased activity or flat drilling.

Answer

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.

Charles Meade asked about Crescent's competitive advantages in growing its mineral royalty position, especially given the competitive market and the company's 20% year-over-year value compounding. He also inquired if there's a specific geography with the most opportunity. Additionally, Meade asked about the Barnett potential within Crescent's new Midland Basin position, referencing recent impressive rates from another operator.

Answer

CEO David Rockecharlie highlighted Crescent's core identity as investors and operators, combining technical and operational expertise with disciplined, active, and opportunistic investing as key advantages for compounding value in minerals. He noted their track record of patience and sticking to desired returns. Regarding the Midland Basin, CEO David Rockecharlie reiterated a phenomenal entry and successful integration, emphasizing the long-term inventory potential across their business, similar to their Eagle Ford strategy. EVP of Investments Clay Rynd added that they actively follow market trends for resource expansion, and COO Joey Hall considered the Barnett potential as additional upside.

Charles Meade inquired about Crescent Energy's assessment of the Barnett Shale potential within their Midland Basin position, following recent impressive well results from another operator, despite having only recently acquired the assets.

Answer

CEO David Rockecharlie expressed confidence in their Permian entry and integration, noting that while not commenting specifically on the Barnett, their strategy involves long-term inventory potential expansion, similar to their success in the Eagle Ford. EVP of Investments Clay Rynd and COO Joey Hall added that they are actively monitoring market trends and view the Barnett as potential upside.

Charles Meade from Johnson Rice & Company L.L.C. asked for elaboration on the use of the word 'dislocation' to describe the current A&D market and inquired about the leading hypotheses for the strong production response from wells in the eastern Uinta position.

Answer

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.

Charles Meade asked for insight into the 'ask' side of the M&A market amid widening bid-ask spreads and how Crescent's approach differs during volatile times. He also requested details on the four operated Uinta wells that were recently turned to sale.

Answer

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.

Charles Meade inquired about how Northern Oil and Gas and investors can track whether the company is aligning with the low or high activity scenario in its guidance, and for an update on Appalachia performance, including the joint Infinity assets.

Answer

CEO Nick O'Grady and President Adam Dirlam acknowledged the wide range of outcomes, noting the Ground Game can fill gaps and substantial shut-in volumes exist. They committed to tightening the guidance band throughout the year. For Appalachia, O'Grady highlighted strong performance from both legacy and Joint Development Agreement assets, with the Antero asset performing strongly pre-acquisition. He noted Q1 completions are mostly in April, so Q1 won't see a huge immediate impact, but expressed high hopes for future performance and cost improvements.

Charles Meade inquired about the amount of growth CapEx included in the updated 2025 budget and asked about the specific mechanisms driving the spending reduction, such as non-consenting wells versus fewer well proposals.

Answer

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.

Charles Meade sought clarification on the shape of 2025 production, asking if a flat profile implied a sequential decline from Q4 2024. He also asked why NOG provided a 2026 outlook, a departure from previous practice.

Answer

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.

Charles Meade sought clarification on the Q4 turn-in-line (TIL) forecast and its CapEx implications, and asked for insights on the Uinta Basin's Douglas Creek wells.

Answer

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.

Charles Meade asked about EOG's communication strategy for its international exploration results in UAE and Bahrain, contrasting it with the company's typically quiet domestic approach. He sought an outline of how EOG plans to share results and the decision-making process for ramping up or curtailing activity in these regions.

Answer

Chairman and CEO Ezra Yacob explained that international agreements often involve public announcements, unlike domestic exploration. He referenced EOG's transparency in Oman, where they disclosed drilling results and their exit. He stated that Bahrain and UAE would follow a similar transparent approach, with public decisions on commerciality after the exploration phase, expressing confidence in the plays and interest in additional regional gas projects.

Charles Meade asked about EOG's communication strategy for results in UAE and Bahrain, given the difference from EOG's typical 'quiet' approach in the Lower 48 and the unique nature of international concessions.

Answer

Ezra Yacob, Chairman and CEO, explained that international agreements often involve public announcements, differing from EOG's stealthier domestic exploration. He referenced EOG's transparency in Oman, where they publicly disclosed drilling results and their eventual exit. He stated that Bahrain and UAE would follow a similar transparent approach, with public announcements expected upon a 'declaration of commerciality' after the exploration phase. He expressed excitement about the unconventional oil play in UAE and the unconventional gas play in Bahrain, noting Bahrain's potential for future gas demand and EOG's interest in additional gas projects in the region with the right partners.

Charles Meade sought more detail on the Trinidad 'Barrel' discovery, asking how the 125 feet of pay compared to pre-drill expectations and what the major steps are toward a final investment decision (FID). He also asked if the unique, undeveloped nature of the Eagle Ford bolt-on acquisition is repeatable or if it was a one-off opportunity.

Answer

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.

Charles Meade asked for EOG's perspective on the range of possible outcomes for U.S. oil supply in 2025. He also requested an update on the status of the Beehive exploration well in Australia.

Answer

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.

Charles Meade asked for clarification on the nomenclature of the Barnett play, specifically how it has evolved from a Barnett Mississippian target (like the Limelight prospect) to a Woodford and Barnett target in the basin center, and if Diamondback is landing in the Woodford to frack up into the Barnett. He also asked for elaboration on the 'stoplight metaphor,' particularly if the green light scenario is now closer than before.

Answer

CFO Jere Thompson explained that Barnett and Woodford are distinct reservoirs. The initial Limelight play targeted a thick Mississippian lime section, separating the two. In more recent delineation areas, the Mississippian lime is thinner, allowing them to frack through it, generally targeting the lower Barnett to drain the Woodford. CEO Kaes Van't Hof discussed the stoplight metaphor, stating that the red light scenario (low crude prices) has receded, and while not yet a 'green light,' there's more confidence in the macro environment due to higher summer demand and less aggressive oversupply than anticipated, leading to a less bearish outlook.

Charles Meade asked about the evolution of the Barnett/Woodford play, specifically how it shifted from the initial Limelight prospect to current basin-center targets, and if they are landing in Woodford to frack up into Barnett. He also sought clarification on the 'stoplight metaphor' regarding the green light scenario.

Answer

CEO Kaes Van't Hof explained that Barnett and Woodford are distinct reservoirs. The initial Limelight play was a Barnett play with a thick Mississippian lime, while recent delineation areas have a thinner Mississippian lime, allowing them to frack through it, targeting lower Barnett to drain Woodford. Kaes Van't Hof clarified the stoplight metaphor, stating they were closer to a red light scenario in crude price over the last six months, but now feel more confident about the macro, waiting for the green light scenario.

Charles Meade of Johnson Rice & Company L.L.C. asked for an update on the conditions that would constitute a 'green light' for Diamondback to re-accelerate activity.

Answer

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.

Charles Meade inquired about the intended audience of the shareholder letter beyond stockholders and asked for more detail on the rate of change of geologic headwinds versus efficiency gains.

Answer

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.

Charles Meade sought clarification on the reduction in unit operating expense guidance, asking for the drivers behind the improvement and what it suggests for the 2025 cost basis.

Answer

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.

Charles Meade inquired about the new dividend level, specifically how the $0.315 per share was chosen and the thought process behind this significant increase.

Answer

Clay Gaspar, President and CEO, explained that the new dividend level represents a substantial bump for Devon shareholders and aligns with Coterra's previous dividend. He noted that this, along with a projected substantial share repurchase program and debt repayment, forms a robust framework for returning significant free cash flow directly to shareholders, all subject to the new pro forma board's approval.

Charles Meade asked about the thought process behind the new dividend level of $0.315 and how that specific number was chosen.

Answer

President and CEO Clay Gaspar explained that the $0.315 dividend represents a significant increase for Devon shareholders and aligns with Coterra's previous dividend. He noted that this, combined with a projected substantial share repurchase program and debt repayment, provides a robust framework for returning significant free cash flow directly to shareholders, pending new pro forma board approval.

Charles Meade asked for clarification on how the stated 14% year-to-date drilling efficiency improvement translates to the reduction in rigs from 16 to 14. He also sought an outlook on when Waha natural gas prices might see a durable recovery and whether the new Matterhorn pipeline would bring incremental oil volumes to market.

Answer

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.

Charles Meade inquired about the nature and growth trajectory of Expand Energy's 5 Bcf of owned storage assets, its competitiveness in acquiring more storage, and the potential upside of bringing Ohio Utica development concepts to West Virginia.

Answer

Dan Turco, EVP of Marketing and Commercial for Expand Energy, explained that they added 3.5 Bcf of storage in the last quarter, bringing the total to 5 Bcf, which is actively used to manage volatility and generate margin. He noted the competitive market for acquiring more capacity due to increased demand. Mike Wichterich, Chairman of the Board and Interim President and CEO, expressed excitement about the Southwest App program, seeing significant upside in West Virginia Utica development by leveraging Haynesville learnings, despite requiring some infrastructure.

Charles Meade from Johnson Rice asked about the nature of Expand Energy's 5 Bcf of owned storage assets, the trajectory of building this position, and the company's competitiveness in acquiring more storage. He also inquired about the potential of bringing Ohio Utica development concepts to West Virginia, asking for elaboration on this opportunity and its potential upside.

Answer

Dan Turco, EVP of Marketing and Commercial, explained that Expand Energy added 3.5 Bcf of storage in the last quarter, bringing the total to 5 Bcf. He highlighted its value for managing market volatility and generating margin, noting active use and plans to turn the storage more often. Turco acknowledged the competitive market for acquiring more capacity but stated they would continue to look for opportunities that create value and help manage volatility. Mike Wichterich, Chairman of the Board and Interim President and CEO, expressed excitement about the Southwest App program and the Utica potential in West Virginia, noting that geology doesn't stop at the Ohio River. He sees significant upside, leveraging learnings from Haynesville's deep gas wells, and expects it to be a highly profitable part of the business, though it will require some infrastructure.

Charles Meade asked for clarification on the company-wide breakeven of $2.75 mentioned in prepared comments, including assumptions like location costs and minimum threshold returns. He also inquired about the framework for success for the Western Hanzo horizontal well to be drilled in Q4 and the expected activity level for 2026.

Answer

COO Josh Viets clarified that the $2.75 breakeven specifically refers to the Hanzo asset's annual free cash flow breakeven, including corporate items, noting a significant improvement from earlier guidance. Regarding the Western Hanzo well, Josh Viets stated that success would involve fine-tuning drilling operations and assessing early-time productivity data, with 2026 activity dependent on these initial results.

Charles Meade followed up on the Brown True Heart BB well, asking if the water produced was completion water or formation water, and if its azimuth or toe-up/toe-down orientation could be a factor. He also asked for a preview of the 1.1 Tcf reserve additions from the 2025 drilling program, specifically the breakdown between PDP and PUDs, and the ratio of adds from Legacy versus Western Haynesville.

Answer

Chief Operating Officer Dan Harrison confirmed the water was load water from fracking, not formation water, and suggested the updip drilling orientation and gravity could contribute to higher initial water rates, though the well's EUR is expected to be similar to downdip wells. President and CFO Roland Burns explained that the 1.1 Tcf additions were true drilling-related additions, not price-driven, reflecting growth in PDP and PUDs due to increased drilling rigs and new projects, particularly offsets in the Western Haynesville. Chairman and CEO Jay Allison noted the finding cost was $1.02 per MCFE in 2025, slightly up from $1.00 in 2024, but with better adds.

Charles Meade followed up on the Brown Trueheart BB well, asking Dan Harrison if the water produced was completion water or formation water, and if its production was related to the well's azimuth (toe up versus toe down). Charles Meade then asked a broader question about the 1.1 Tcf of reserves added from the drilling program, requesting a preview of the split between PDP and PUD additions, and the ratio of additions from legacy versus Western Haynesville.

Answer

Dan Harrison, COO, reiterated that the water produced from the Brown Trueheart BB well is load water from fracking, not formation water. He attributed the higher water production to drilling up-dip and fighting gravity, noting that the down-dip well on the same pad had a higher IP rate. He added that water production typically decreases over time, leading to similar EURs. Roland Burns, President and CFO, explained that the 1.1 Tcf of reserve additions included PDP growth and more PUDs due to additional drilling rigs, as well as replacing sold inventory. He clarified that these were true drilling-related additions, not due to price changes. Jay Allison, Chairman and CEO, mentioned the finding cost was $1.02 per Mcfe.

Charles Meade of Johnson Rice & Company L.L.C. requested an update on the performance of the Elijah well's modified completion design and its subsequent use. He also asked for confirmation that the potential non-core asset sale would likely be in the Angelina River trend.

Answer

COO Daniel Harrison confirmed the Elijah well's tighter stage spacing (100 ft vs 150 ft) has since been used on the Mann and Bell Meyer wells. He noted that early performance is very encouraging, with excellent pressure data, and they expect to use the design more. President & CFO Roland Burns and Chairman & CEO M. Jay Allison both affirmed that inferring the sale would be in the Angelina River trend was a 'reasonable' and 'good guess,' as it's an area where the industry is active but Comstock is not.

Charles Meade of Johnson Rice & Company L.L.C. asked for a performance update on the Elijah well's modified completion design and whether it has been replicated. He also sought to confirm if the Angelina River trend was the likely area for the planned non-core asset divestiture.

Answer

COO Daniel Harrison confirmed the Elijah well's tighter stage spacing (100-foot stages) has been replicated on the Mann and Bell Meyer wells with very encouraging early results, noting the Elijah well's pressure drop looks 'really, really good.' Regarding the asset sale, CEO M. Jay Allison and President & CFO Roland Burns affirmed that suggesting the Angelina River trend was a 'reasonable inference' and a 'good guess.'

Charles Meade of Johnson Rice & Company L.L.C. asked for an update on the performance of the Elijah well's modified completion design and whether it has been replicated. He also sought to confirm if the Angelina River trend is the likely area for the non-core asset sale.

Answer

COO Daniel Harrison confirmed the Elijah well was the first to use a tighter 100-foot stage spacing, a design since replicated on the Mann and Bell Meyer wells with very encouraging early results. Regarding the asset sale, both CEO M. Jay Allison and President/CFO Roland Burns affirmed that inferring the Angelina River trend is the target area was a 'reasonable inference' and a 'good guess,' noting it's an active area for the industry where Comstock has not recently focused.

Charles Meade of Johnson Rice & Company L.L.C. asked for an update on the performance of the Elijah well's different completion design and whether it has been replicated. He also asked if the Angelina River trend was a reasonable inference for the location of the non-core divestiture program.

Answer

COO Daniel Harrison confirmed the Elijah well's tighter stage spacing design was replicated on the Mann and Bell Meyer wells with very encouraging early results. Regarding the divestiture, Chairman & CEO M. Jay Allison and President/CFO Roland Burns affirmed that targeting the Angelina River trend was a 'reasonable inference' and a 'good guess,' as it's an area where the company has not been recently active.

Charles Meade of Johnson Rice & Company L.L.C. requested an update on the performance of the Elijah well, which used a different completion design, and asked if that design has been replicated. He also inquired if the Angelina River trend was a reasonable inference for the location of the planned asset divestiture.

Answer

COO Daniel Harrison confirmed the Elijah well's tweaked completion (tighter 100-foot stages) has shown very encouraging early performance and has since been used on the Mann and Bell Meyer wells. Regarding the divestiture, President and CFO Roland Burns and Chairman & CEO M. Jay Allison both affirmed that inferring the Angelina River trend as the location was a 'reasonable' and 'good guess,' as it's an area where the industry is active but Comstock is not.

Charles Meade inquired if the use of deep vertical well control was a unique factor for the Olajuwon well or if it will be a dominant variable for future step-out locations. He also asked about the timing for derisking the play in the northwesterly, up-dip direction.

Answer

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.

Charles Meade from Johnson Rice asked for an estimate of what percentage of the Western Haynesville position has been derisked and what geological risks remain in the northern parts of the play. He also asked what has been learned from managing older vintage wells.

Answer

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.

Charles Meade of Johnson Rice noted that the Sebastian horseshoe well had the highest IP rate despite being the shortest lateral and asked if this result was repeatable. He also asked which elements of well construction were most critical for replicating the successful cost-per-foot metrics of the recent Hodge well.

Answer

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.

Charles Meade asked about any incremental pressure buildup data from the SS-2H well since it was shut in, specifically looking for indicators of flat decline or insights into its unique flow characteristics. He also inquired about the market appetite for expanded gas sales in the Darwin region.

Answer

CEO Todd Abbott clarified that he was referring to the SS-6H well, stating it's too early to tell about its decline from pressure buildup data, as flow-back data was in line with expectations and not indicative of long-term flow. He noted that long-term production data is needed to assess decline. Regarding market appetite, he confirmed a 40 MMcf/d contract with the NT government and mentioned specific ongoing conversations with other customers, expressing cautious optimism for expanding the SPCF to 100 MMcf/d due to compelling economics.

Charles Mead of Johnson Rice & Company L.L.C. inquired about the expected conclusion timeline for Tamboran Resources' ongoing farmout process, seeking clarification on whether the Q1 2026 target is for announcement or completion. He also asked for any new insights or explanations regarding the "strange but welcome" inclining production behavior observed in the SS2H well between days 60 and 90, specifically if a different sand source was a factor.

Answer

Dick Stoneburner, Chair & Interim CEO, indicated that Q1 2026 is a reasonable expectation for announcing a conclusion to the farmout process, acknowledging the variability in timing due to multiple parties involved. Regarding the SS2H well's unique production, Stoneburner dismissed sand source as a likely explanation. He suggested two primary factors: the unique geological fabric of the Beetaloo Basin's rocks (four times older than North American shales) and potential reservoir engineering explanations related to flowback, noting that more data from production would be needed to fully understand the decline profile.

Charles Meade of Johnson Rice sought clarification on the expected conclusion timeline for Tamboran Resources' farmout process, referencing the 1Q 2026 target. He also inquired about any new insights or explanations for the "strange but welcome" production behavior of the SS2H well, specifically its inclining rates between days 60 and 90, and whether different sand sources might be a factor.

Answer

Dick Stoneburner, Chairman and Interim CEO, indicated that 1Q 2026 is a reasonable expectation for announcing the farmout conclusion, but stressed the variability of such processes. Regarding the SS2H well's unique production, Stoneburner dismissed different sand sources as a likely explanation. He suggested two primary possibilities: the unique geological properties of the Beetaloo Basin's rocks, which are significantly older and distinct from North American shales, and potential reservoir engineering explanations related to flowback practices. He noted that more definitive data on decline profiles and explanations would become available once wells are in full production by mid-to-end 2026.

Charles Meade asked for an updated timeline on the conclusion of Tamboran Resources' farmout process, specifically if it's expected in 1Q 2026 or potentially later, and sought new insights into the unusual inclining production behavior observed in the SS2H well between days 60-90, including any potential impact from sand source.

Answer

Chairman and Interim CEO Dick Stoneburner indicated that 1Q 2026 is a reasonable expectation for announcing the farmout conclusion, acknowledging the variable pace of such processes. Regarding the SS2H well's performance, Mr. Stoneburner dismissed sand source as a likely factor, suggesting explanations point to the unique geology of the Beetaloo Basin (older, distinct rock fabric) and potential reservoir engineering factors related to flow back. He anticipates more clarity on decline profiles once wells are in production by mid-to-end 2026.

Charles Meade sought further clarification on Magnolia's acquisition strategy, particularly regarding traditional oily Eagle Ford (PDP-heavy) versus undeveloped upside (gas-heavy) opportunities. He also asked how extra cash would be allocated in higher oil price scenarios, such as $70-$75.

Answer

Chris Stavros, Chairman, President, and CEO, reiterated disinterest in PDP-heavy, scattered Eagle Ford assets, preferring undeveloped upside and leaning towards oil. In higher oil price scenarios, Mr. Stavros stated that another rig is not in the plan. Instead, extra cash from their unhedged structure would be returned to shareholders via dividends, share repurchases, and/or opportunistic acquisitions, rather than chasing growth.

Charles Meade sought further clarification on Magnolia's M&A strategy, specifically reconciling the company's disinterest in PDP-heavy Eagle Ford assets with its preference for undeveloped upside, which might be gas-heavy. He also asked where additional cash would be allocated in internal scenarios with higher oil prices ($70-$75), inquiring about priorities like dividends, buybacks, or adding another rig.

Answer

Chris Stavros, Chairman, President, and Chief Executive Officer, clarified that while undeveloped upside opportunities are challenging to find, they do exist, and he is less interested in scattered, PDP-heavy Eagle Ford assets due to a lack of synergies. In higher oil price scenarios, Mr. Stavros stated that adding another rig is not the plan. Instead, the company would capture the upside from its unhedged position and return the excess cash to shareholders through dividends and share repurchases, or opportunistically deploy it for acquisitions.

Charles Meade of Johnson Rice & Company L.L.C. asked for details on the location of recent stronger-than-expected well completions and whether they were situated on the 30,000 acres recently added to the development area through appraisal.

Answer

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.

Charles Meade asked for more detail on the recent stronger-than-expected well completions, specifically questioning their location and whether they were on the 30,000 net acres recently added to the development area through appraisal.

Answer

CEO Christopher Stavros confirmed that this was a perfect example of the company's "appraise, acquire, grow" strategy. He stated that wells drilled in an area late last year and early this year outperformed, which led to an opportunity to acquire more acreage in that same area, expanding the development footprint. He affirmed this is the same concept that will be applied going forward but declined to provide a specific GPS location.

Charles Meade asked about the royalty mechanism in the Tupper Montney asset, specifically the year-over-year delta in the Net Revenue Interest (NRI) and how the royalty rate is determined. He then inquired if the next two Hai Su Vang appraisal wells would also assess the shallower secondary reservoir, and the chances of it becoming a commercial resource.

Answer

Eric Hambly (President and CEO) explained that the Tupper Montney royalty is a sliding scale based on realized commodity prices, projecting an increase from 4.6% in 2025 to 8.4% in 2026 due to higher gas prices. He confirmed that both the Hai Su Vang 3X and 4X appraisal wells would test the shallower secondary reservoir to assess its areal extent and resource range, indicating it already appears to represent a commercial development.

Charles Meade asked for details on the Tupper Montney royalty mechanism, specifically the year-over-year delta in the Net Revenue Interest (NRI), how the rate is determined (realized vs. index price), and its reset frequency. He also inquired if the Hai Su Vang 3X and 4X appraisal wells would assess the shallower secondary reservoir in addition to the deeper primary, and the potential for this secondary reservoir to add to the overall resource and production rates.

Answer

Eric Hambly, President and CEO, and Atif Riaz, VP, Investor Relations and Treasurer, explained that the Tupper Montney royalty is a sliding scale based on realized commodity prices, with the 2025 rate at 4.6% projected to roughly double to 8.4% in 2026 due to expected price increases, though still lower than US rates. New wells have a fixed 5% royalty for a couple of years. For Hai Su Vang, both the 3X and 4X appraisal wells will test the shallower secondary reservoir to assess its areal extent. They believe this shallower reservoir represents a commercial development and will provide a resource range for both primary and secondary reservoirs after the appraisal program is complete.

Charles Meade asked for details on a success-case scenario for the Cote D'Ivoire prospects, focusing on the implications of the 90% working interest for development capital, appraisal needs, and potential farm-down strategy.

Answer

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.

Charles Meade requested more technical detail on the Gulf of Mexico workovers at Khaleesi and Marmalard and asked how the smaller-than-expected recent Vietnam discovery informs the appraisal of the earlier, larger discovery.

Answer

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.

Charles Meade from Johnson Rice sought to synthesize the issues in the Gulf of Mexico, noting that higher Q1 CapEx seemed linked to the King's Quay field. He asked if the company's view of this set of fields was changing, potentially leading to a different CapEx and volume trajectory. He also requested a narrative of the Vietnam flow test and how its results are informing the appraisal well strategy.

Answer

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.

Charles Meade asked a big-picture question about ConocoPhillips' global LNG strategy, differentiating between "resource LNG" and "commercial LNG," how they complement or compete, and if the distinction is meaningful given the Lower 48's vast gas resources.

Answer

Andy O’Brien (CFO and EVP of Strategy and Commercial) explained that "resource LNG" is the traditional model of finding stranded gas, securing buyers, and building facilities (e.g., Australia, Qatar). "Commercial LNG" leverages abundant Lower 48 gas to access international pricing (TTF, JKM) by controlling the value chain, as seen with Port Arthur Phase I, II, and Rio Grande. He clarified they don't compete but are different models, with the commercial strategy complementing their 2 BCF/day Lower 48 gas production and acting as a natural hedge. Both serve important roles, and ConocoPhillips' global scale allows them to play in both.

Charles Meade asked for a big-picture explanation of ConocoPhillips' global LNG strategy, differentiating between 'resource LNG' and 'commercial LNG,' how they complement or compete, and whether the distinction is meaningful given the company's vast Lower 48 resources.

Answer

Andy O’Brien, Chief Financial Officer and Executive Vice President of Strategy and Commercial, explained that 'resource LNG' is the traditional model of developing stranded gas assets (e.g., Australia, Qatar). 'Commercial LNG' leverages abundant Lower 48 gas to access international pricing (TTF, JKM) by controlling the value chain. He stated they don't compete but complement each other, with the commercial strategy acting as a natural hedge for the company's over 2 BCF/day (15 MTPA equivalent) Lower 48 gas production, leveraging global size and scale.

Charles Meade of Johnson Rice & Company L.L.C. requested a preview of the upcoming winter work season for the Willow project in Alaska, focusing on key milestones and planned activities.

Answer

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.

Charles Meade of Johnson Rice asked about the Nuna project start-up in Alaska and whether its production would be significant enough to be observable in the company's Q1 and Q2 2025 volumes.

Answer

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.

Charles Meade asked for more details on the major Q3 turnaround quarter, particularly at Surmont, and whether better-than-expected execution contributed to the strong Q4 production guidance.

Answer

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.

Inquired about the lower-than-expected production in Q2, the learning curve with the new Bayswater assets, current production levels, and the completion status of the Rush Pad.

Answer

The Q2 production was impacted by a two-month delay in the Bayswater acquisition closing, which pushed the production ramp forward. The underlying ramp trajectory is unchanged. The Rush Pad is on schedule for completion in Q3 with promising initial pressure data.

Charles Meade from Johnson Rice & Company L.L.C. asked for clarification on the Q2 production ramp, the learning curve with the newly acquired Bayswater assets, and the completion status of the Rush Pad.

Answer

Co-Founder, Chairman & CEO, Edward Kovalik, attributed the Q2 production level to a two-month delay in the Bayswater closing, which pushed the development ramp forward but did not alter its trajectory. Co-Founder, President & Director, Gary Hanna, added that the Rush Pad completion is on schedule for Q3, with promising early pressure data indicating strong potential.

Charles Meade of Johnson Rice & Company L.L.C. inquired about the company's reaction to the Montana industrial gas resource report, asking if there were any surprises, and sought clarity on the timeline and goals for commercial offtake agreements for helium and CO2.

Answer

President and CEO Ryan Smith responded that he was pleased but not surprised by the Ryder Scott resource report, as it confirmed their internal belief in the asset's large scale. Regarding offtake agreements, Smith outlined a strategy to pursue intercompany deals for CO2 sequestration and Enhanced Oil Recovery (EOR), an external helium offtake agreement by year-end, and to proactively work on merchant CO2 sales with a TBD timeline.

Inquired about the specific data points from the upcoming wells that will inform the final size of the gas processing plant and the design criteria for these new wells, particularly their target zones.

Answer

The company is seeking data on flow rates, gas composition, and reservoir characteristics to finalize the plant's specifications. The primary design criteria for the new wells is to target and produce from the CO2-heavy Duperow zone. Existing wells will also be worked over to target the Duperow, with one potentially being used as a Class II injection well.

Charles Meade of Johnson Rice & Company L.L.C. sought to quantify the potential for the Oklahoma JV to offset the company's 10% corporate decline rate, asking about magnitude and timing, and also inquired about interest in other geological zones.

Answer

CEO Rusty Hutson confirmed the JV will materially impact the production decline rate in 2026 but stated that more specific guidance would be provided later in the year, noting that even a 1-2% reduction is substantial. He also confirmed there has been significant interest in other formations in the Western Anadarko, and the company is actively evaluating these positions to either develop or monetize.

Charles Meade of Johnson Rice & Company L.L.C. asked for more detail on the magnitude and timing of the Maverick JV's potential to offset the 10% corporate decline rate and inquired about development interest in other geological zones in the Western Anadarko basin.

Answer

CEO Rusty Hutson clarified that the JV program will add a material amount of production in 2026 and that a 1-2% reduction in the corporate decline rate would be substantial, with more specific guidance to come by year-end. He also confirmed there is significant interest in various formations in the Western Anadarko, and the company is now better equipped with engineering support from the Maverick deal to evaluate whether to develop or divest these opportunities.

Charles Meade asked about the drivers behind MOP Natural Resources' stronger-than-expected Q2 production volumes and sought clarification on the Brocklin 3MH well, questioning if it was one of the deep Anadarko targets mentioned.

Answer

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.

Charles Meade inquired about the recent $60 million XTO acquisition, which doubled Mach's acreage, asking for details on production, EBITDA, and the asset profile, including the Hugoton field. He also sought clarification on the rig reduction plan aimed at keeping the reinvestment rate below 50%.

Answer

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%.

Charles Meade asked for details on the company's third rig, including its timing and drilling focus, and requested an outlook on natural gas, similar to the commentary provided on oil.

Answer

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.

Charles Meade of Johnson Rice & Company L.L.C. asked about the initial performance and expected Q4 production contribution from the two recently closed acquisitions. He also sought context on the planned 2025 drilling in Custer County, specifically the Red Fork and deeper Mississippian targets.

Answer

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.

Charles Meade of Johnson Rice & Company L.L.C. asked about the probability of a favorable ruling on the Kern County EIR and the rationale for participating in a well to test the Castle Peak formation in Utah.

Answer

President Danielle Hunter expressed high optimism for a favorable court ruling on the Kern County EIR, citing the meticulous work done and the lack of new objections. CEO Fernando Araujo explained the Castle Peak well participation is driven by promising geology, with potential for thicker sandstones in Berry's acreage, which could unlock multi-layer cube development opportunities.

Charles Meade inquired about the key drivers behind Berry's outperformance in California production growth compared to peers, questioning if it was due to superior regulatory navigation or asset-specific advantages like sidetracks. He also asked for clarity on the news flow and timing for the Uinta wells, from fracking completion to initial peak rates and public announcements.

Answer

CEO Fernando Araujo attributed the California success to the company's experienced and innovative teams, their early adoption of a sidetrack drilling strategy, and the high-return, low-capital-intensity nature of the assets. He noted that 225 of their PUDs are sidetracks. Regarding the Uinta timeline, Araujo detailed that fracking the four wells will take most of June, followed by cleanout and completion. He expects initial production in late July and significant production data in August, which would align with the next earnings cycle.

Charles Meade asked for details on the performance differences between Berry's recent Uinta Basin farm-in wells and what those results imply for the company's first operated pad. He also inquired about the current M&A environment in California and the willingness of private operators to sell assets.

Answer

CEO Fernando Araujo explained that the newer, higher-producing Uinta wells were 3-mile laterals compared to a mix of 2-mile and 3-mile laterals in the first batch, leading to the performance difference. He expressed high expectations for the operated pad, calling the asset potentially transformational. Regarding M&A, Araujo confirmed Berry is actively pursuing bolt-on deals in Kern County and is in discussions with several small private operators, seeing potential for transactions with the right structure.

Charles Meade inquired about the specifics of the second farm-out in the Uinta Basin, including its strategic purpose for derisking acreage and its impact on the capital budget. He also asked for clarification on the performance of California's thermal diatomite assets, questioning if recent results represent a step-change or a continuation of prior success.

Answer

CEO Fernando Araujo explained that the Uinta Basin farm-out with Wasatch Energy Management accelerates the appraisal of their acreage with a minimal capital impact, as Berry's working interest is only 16%. Regarding the California assets, Araujo clarified that while workovers have steadily increased production, the new sidetracks in the thermal diatomite reservoir are a recent development delivering exceptional returns over 100%, representing a significant enhancement to their program.

Charles Meade of Johnson Rice & Company L.L.C. asked about the steep 40% production decline at the Jubilee field over the past year and inquired about the potential alternative operating models being explored to lower costs at the GTA project.

Answer

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.

Charles Meade of Johnson Rice asked for details on the GTA project's 'Phase 1+' expansion, including its composition and timeline, and questioned the specific operational assumptions underlying the 2025 Jubilee production guidance. He later followed up on the positive early performance data from the GTA wells.

Answer

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.

Charles Meade asked about the drivers behind the 2025 CapEx reduction and the impact of the Tiberius project delay, as well as the 2025 drilling priorities for the Jubilee field and the role of new 4D seismic data.

Answer

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.

Charles Meade inquired about the operational progress of the Alaska exploration well and sought more detail on the better-than-expected well productivity and future down-spacing plans in Howard County, Permian Basin.

Answer

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.

Charles Meade asked about the key takeaway message from the new slide in the supplement showing a mock-up of the GranMorgu development layout in Suriname.

Answer

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.

Asked for clarification on the location of attractive M&A opportunities and for insights into any early signs of an activity uptick in the Haynesville for 2025.

Answer

The company stated that M&A opportunities are being evaluated in both the Haynesville and the SCOOP/STACK fairway, with capital deployed based on the highest potential return, not a specific basin. Regarding 2025 Haynesville activity, while major operators have moderated activity, rig counts on PHX's minerals have remained steady, and some smaller operators plan to bring wells online in December, though the overall outlook remains dependent on operator decisions.

Asked about operator behavior in the Haynesville regarding turning wells online, the price needed to increase rig counts, the responsiveness of private vs. public operators, and the latest developments in the SCOOP play.

Answer

Management stated the Haynesville is economic around $2.75-$3 gas. The rig count is below maintenance levels, causing production to decline, and the DUC inventory has shrunk. They expect significant Haynesville volume growth in 2025-2027. Unlike the Permian, the Haynesville is dominated by a few large players, so small private companies won't materially impact volumes. In the SCOOP, development is concentrated in a core fairway by large operators, and activity on the margins is not significant.

Inquired about the performance of specific Continental wells in the SCOOP play, asking about the potential for stacked development of the Sycamore and Woodford formations. Also asked how commodity price volatility is affecting the M&A environment and the ability to close deals.

Answer

Executives are very pleased with the Continental well results, which have outperformed their type curve. They confirmed it is not an 'either/or' situation and that the Sycamore and Woodford zones can be co-developed and 'wine racked', with potential for multiple benches in each zone, suggesting significant upside. On M&A, they acknowledged volatility can create gaps, but in the current price environment, there are still many opportunities with reasonable seller expectations. They stated it is still a 'buyer's market' for them.

Charles Meade sought to understand the operational sequence for ramping up Marcellus activity and asked how the scale of potential projects in Lea County, NM compares to the large Windham Row project.

Answer

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.