Kevin MacCurdy

Kevin MacCurdy asked about Permian Resources' strategy for free cash flow per share growth, contrasting it with peers who focus on flat or declining volumes. He also inquired about the company's capital allocation priorities for 2026, given strong free cash flow and a healthy balance sheet.

Answer

Co-CEO Will Hickey explained that their strategy focuses on growing free cash flow through organic and inorganic means, suitable for a less mature basin with significant running room. Co-CEO James Walter detailed capital allocation, prioritizing the base dividend, pursuing accretive acquisitions, accruing cash for the balance sheet, and opportunistic share buybacks when dislocations exist.

Kevin MacCurdy asked about Permian Resources' strategy for free cash flow per share growth, contrasting their volume-driven approach with peers focusing on denominator reduction, and inquired about the company's capital allocation priorities for 2026.

Answer

Will Hickey, Co-CEO and Director, explained that Permian Resources' strategy is largely numerator-focused (organic and inorganic growth) due to the exciting opportunities in the Permian Basin, distinguishing it from more mature businesses. James Walter, Co-CEO and Director, outlined capital allocation priorities for 2026, starting with the base dividend, followed by accretive acquisitions, balance sheet cash accrual, and opportunistic share buybacks, referencing slide 16.

Kevin MacCurdy of Pickering Energy Partners asked about the potential for further well cost reductions, given the record drilling times, and inquired about the expected cadence of well turn-in-lines for the second half of the year.

Answer

Co-CEO Will Hickey confirmed significant drilling efficiency gains, with five of the top ten fastest wells drilled in Q2, creating tailwinds for cost reductions in the second half. He noted that the well completion cadence remains consistent with previous guidance of 275 net wells for the year, with a slight back-half weighting.

Kevin MacCurdy asked about the origin of the recent acquisition, whether it was a negotiated deal or a formal process, and how the new assets fit into the development schedule. He also inquired about the drivers behind the strong Q1 production.

Answer

Executive Hays Mabry revealed the deal evolved from ongoing discussions over the last 6-9 months into a formal process. He noted the acquired inventory is highly competitive and will receive capital allocation immediately. Mabry attributed the Q1 production outperformance primarily to artificial lift optimization and strong well results on assets from the 2024 acquisitions.

Kevin MacCurdy from Pickering Energy Partners noted that Permian Resources is using efficiency gains to increase activity, unlike some peers, and asked for the rationale behind this decision. He also questioned how the company is able to achieve minimal cash taxes in 2025 and the outlook for tax deferrals.

Answer

Co-CEO William Hickey explained that the decision is driven by the program's excellent returns, which have improved despite lower commodity prices due to cost reductions. Executive Hays Mabry added the focus is on per-share growth. CFO Guy Olefin stated that minimal 2025 cash taxes are a result of optimized tax planning learned from the Earthstone integration, but noted taxes will become more meaningful in 2026 and 2027.

Kevin MacCurdy asked how many additional wells per year the recent drilling efficiencies translate to and questioned the reason for the recent step-up in NGL volumes.

Answer

Co-CEO William Hickey confirmed that the current run-rate efficiency would yield slightly more than the guided 270 wells per year, as the gains were achieved progressively. An unnamed executive attributed the higher NGL volumes to increased ethane recovery, a decision driven by weak in-basin WAHA gas prices, which provides an overall uplift to BOE volumes.

Kevin MacCurdy observed that the biggest difference between the combined companies' previous year and the pro forma plan appears to be in the DJ Basin. He asked what SM Energy saw in the DJ, what Civitas was doing, and how SM Energy plans to approach it differently in 2026. He also inquired about slide 19, which suggests more wells turned in line than drilled in 2026, asking to confirm if DUCs (Drilled Uncompleted wells) are being drawn down, if this is front-half loaded, and if it's sustainable into 2027.

Answer

President and CEO Beth McDonald stated that the DJ program offers great returns and capital efficiency. She explained that slowing down activity allows the company to strengthen its optionality and flexibility within the basin, optimizing the plan and maximizing free cash flow, especially as technical teams integrate and evaluate the broader portfolio. Regarding DUCs, Beth McDonald clarified that the DUCs count is an artifact of the planned activity slowdown, not a managed target. She emphasized that the company remains focused on capital efficiency and delivering results that maximize free cash flow, with DUC levels depending on pad size, rig count, and activity levels.

Kevin MacCurdy, a Managing Director at Pickering Energy Partners, asked about the significant changes in SM Energy's DJ Basin plan for 2026 compared to the combined companies' previous year, seeking insight into the strategic shift. He also inquired if the company is drawing down DUCs (Drilled Uncompleted wells) in 2026, given that more wells are being turned in line than drilled, and if this trend is sustainable.

Answer

President and CEO Beth McDonald explained that while the DJ program offers strong returns, slowing down activity in 2026 enhances optionality and flexibility to maximize free cash flow and optimize returns, particularly during the integration of technical teams. She clarified that the DUC count is an output of the planned activity slowdown, not a managed target, and reflects the company's focus on capital efficiency and timely completions to maximize free cash flow.

Kevin MacCurdy asked if Vista is observing an expansion in oil field service vendors or equipment entering Argentina, given the improved country backdrop, and if this could lead to further improvements in drilling and completion costs.

Answer

Miguel Galuccio, Founder, Chairman, and CEO of Vista Energy, confirmed seeing significant interest from service companies due to increased activity and macro normalization, which allows for more cross-border freedom. He noted that existing companies are adding capacity, contributing to DNC cost reductions, and highlighted ongoing innovation in practices and inquiries from Permian-based service companies about opportunities in Argentina.

Kevin MacCurdy inquired whether Vista is observing an expansion in oil field service vendors or equipment entering Argentina, given the improved country backdrop and increased attention on the basin, and if this could lead to further improvements in drilling and completion costs.

Answer

Miguel Galuccio, Founder, Chairman, and CEO of Vista Energy, confirmed that there is significant interest from service companies to enter Argentina, driven by increased activity and macro normalization. He noted that existing companies are adding capacity, contributing to DNC cost reductions. He also mentioned inquiries from Permian-based service companies exploring opportunities in Argentina, suggesting potential for further cost improvements.

Kevin MacCurdy of Pickering Energy Partners asked for an update on the progress of the Vaca Muerta Sur (VMOS) pipeline project and any key milestones for investors to watch.

Answer

CEO Miguel Galuccio reported very good progress on the project, with contractual work starting in May across all fronts. He stated the first stage, with a capacity of around 550,000 barrels per day, is expected to be ready by mid-2027. A key milestone recently achieved was the closing of a $2 billion syndicated five-year term loan, which secures financing for 70% of the project cost and reflects strong investor confidence.

Kevin McCurdy asked about Vista's internal view on mid-cycle Brent prices and how potential price weakness could affect the company's long-term plans.

Answer

Chairman and CEO Miguel Galuccio acknowledged recent price volatility but expressed confidence in the strong long-term fundamentals of the oil sector. He highlighted that Vista's portfolio of short-cycle assets and operational agility provides the flexibility to manage through volatile periods, deferring a specific price outlook to the Q2 guidance update.

Kevin MacCurdy asked Range Resources to compare the in-basin demand and supply outlook today versus a year ago when the growth plan was initiated, considering the lower forward curve prices. He also sought clarification on why 2026 differential guidance remains similar year-over-year despite strong Q4 2025 realizations and Q1 2026 gas prices.

Answer

CEO Dennis Degner explained that the growth plan was risked for potential price declines and focused on market share via existing capacity (Rover pipeline) rather than growth for growth's sake, leveraging Range's deep inventory. CFO Mark Scucchi clarified that differential guidance starts with market indications, noting a $0.05 improvement year-over-year, and that strong Q4/Q1 realizations reflect the marketing team's optimization and the 90%+ first-of-month pricing strategy.

Kevin MacCurdy asked Range Resources to compare the in-basin demand and supply outlook today versus a year ago when the growth plan was initiated, particularly in the context of materially lower curve prices, and to comment on the company's confidence in that outlook. He also sought clarification on the 2026 differential guidance, noting strong Q4 realizations and strong Q1 gas prices in the Northeast relative to Henry Hub, and how realizations are expected to trend throughout the year.

Answer

CEO Dennis Degner explained that the growth program was designed to be resilient to potential lower pricing and structured around utilizing existing capacity, such as Energy Transfer's Rover Pipeline, to gain market share rather than solely relying on new demand. He affirmed that pricing remains intact for the current multi-year plan, with growth beyond 2028 contingent on materialized demand. CFO Mark Scucchi stated that the differential guidance, which is about $0.05 better year-over-year, is based on market indications and forward curves. He reiterated that Range's strong Q1 start and consistent premium to Henry Hub are functions of its diversified transportation portfolio and the marketing team's optimization efforts.

Kevin MacCurdy asked for the primary drivers behind the lower-than-expected Q2 capital expenditures, questioning if it was due to efficiencies or service cost deflation. He also inquired about the local NGL market's ability to absorb future production growth.

Answer

CEO Dennis Degner attributed the capital outperformance primarily to significant operational efficiencies, including record drilling speeds and optimized water logistics, rather than service cost deflation. He also expressed confidence in the NGL market, citing Range's flexible export optionality via the East Coast and growing global demand from new infrastructure projects.

Kevin MacCurdy asked if recent market dynamics, including higher gas prices and data center potential, have altered Range Resources' perspective on M&A and consolidation within Appalachia or other basins.

Answer

CFO Mark Scucchi affirmed that Range's view on M&A has not changed. He emphasized that the hurdle for any transaction remains very high due to the quality and longevity of their existing inventory. Any potential deal must be accretive and make the company 'bigger, but better,' as they already possess the necessary scale for competitive operations and market access. Their focus remains firmly within the Appalachian basin.

Kevin MacCurdy sought clarity on the production ramp-up pace between 2025 and 2027 and asked for more specifics on the drivers of margin expansion.

Answer

CEO Dennis Degner described a 'slow and steady' production increase through 2026 and 2027, supported by new infrastructure coming online. CFO Mark Scucchi explained that margin expansion will come from broad-based cost improvements across operating expenses, GP&T, G&A, and interest, contributing to a target breakeven of around $2 NYMEX.

Kevin MacCurdy asked for a quantification of the expected number of drilled but uncompleted (DUC) wells at year-end. He also questioned whether the eventual completion of these wells would represent a permanent step-up in production or be used opportunistically to capture temporary price spikes.

Answer

CEO Dennis Degner estimated the year-end DUC inventory would be approximately 8 to 10 wells, or about two pads' worth, resulting from a $60-$75 million investment. CFO Mark Scucchi added that the deployment of this inventory is flexible; it could support a permanent step-up to a new production plateau if fundamentals warrant, or it could be used opportunistically. The decision will be driven by the nature and steadiness of the market's call on Range's production.

Kevin MacCurdy (Pickering Energy Partners) asked about Ovintiv's growth strategy, specifically how the potential to grow the Montney by 5% annually ranks in the capital allocation framework, given the completed portfolio transformation, reduced debt, and mid-$60s oil prices, and what factors could alter this ranking.

Answer

Brendan McCracken (President and CEO, Ovintiv) outlined two gates for growth: a fundamental market call for incremental volumes (not present today) and the ability to generate more cash flow per share growth from incremental rigs versus share buybacks. He stated that currently, the equation favors buybacks for superior cash flow per share outcomes, leading the company to remain in maintenance mode, despite having unlocked future growth potential through portfolio transformation.

Kevin MacCurdy (Pickering Energy Partners) asked about the growth question, specifically the Montney's potential for 5% annual growth, and how this opportunity stacks up in the capital allocation framework given the completed portfolio transformation, reduced debt, and mid-$60s oil prices.

Answer

President and CEO Brendan McCracken reiterated two gates for growth: a fundamental call for incremental barrels/BTUs (not present today) and whether share buybacks or incremental rigs create more cash flow per share growth. He stated that currently, the equation favors buybacks, leading the company to remain in maintenance mode, while acknowledging the unlocked growth potential for future high-return opportunities.

Kevin MacCurdy of Pickering Energy asked if the company would consider shifting its Montney focus away from the liquids-rich window due to changing price dynamics and if the 50/50 shareholder return split could change based on market conditions.

Answer

Executive Brendan McCracken reaffirmed the company's belief in a multi-product portfolio, stating that having low breakeven options in both oil and gas is the best strategy given future commodity uncertainty. He noted that while the current 50/50 capital return split makes sense, the company is not 'ideologically stuck' and could adjust its allocation in the future.

Kevin MacCurdy asked about Ovintiv's operational sensitivity to natural gas prices, specifically the point at which it would shift capital to gassier assets, and for the company's view on the AECO gas market's development.

Answer

Executive Brendan McCracken explained that the current strategy favors allocating capital to oil wells to capture associated gas upside, viewing share buybacks as a better use of cash than growth. Regarding AECO, he believes the benefit from new LNG offtake will be 'relatively transient,' and the company's strategy remains focused on diversifying away from the AECO hub.

Kevin MacCurdy asked about OpEx trends, specifically the small increase in 2026 guidance for both LOE and GP&T, and whether it's primarily driven by water drop-down on LOE and gas transportation contracts on GP&T. He also inquired if there would be a separate rig dedicated to the Barnett program and if those wells would be geographically separate from cube development.

Answer

CEO Kaes Van't Hof confirmed that water drop-down and gas transportation contracts are major drivers. He cited LOE headwinds including higher unhedged power prices and increased spending on workovers and P&A. GP&T increases are due to traditional CPI escalators and more molecules taken in kind. Regarding Barnett rigs, Kaes Van't Hof stated there would likely be separate rig lines dedicated to the Barnett due to different requirements (depth, mud properties), potentially upgraded rig packages. He added that they would share facilities wherever possible and might mix in core development if Barnett drilling days improve.

Kevin MacCurdy asked about OpEx, noting lower 4Q OpEx but a small increase in 2026 guidance for LOE and GP&T, inquiring about drivers. He also asked if a separate rig would be dedicated to the Barnett program and if wells would be geographically separate.

Answer

CEO Kaes Van't Hof confirmed water drop-down and gas transportation contracts are major factors. He cited headwinds for LOE, including power price increases and increased spending on workovers/P&A. For GP&T, traditional CPI escalators and more molecules taken in kind are drivers. Kaes Van't Hof stated there will be separate rig lines for Barnett, likely focusing on that development, and they will share facilities where possible. COO Danny Wesson added that Barnett's depth requires an 'upgraded rig package,' ideally on separate lines, but could mix with Midland core if drilling days improve.

Kevin McCurdy asked about the benefits of the Sitio acquisition for Viper and the potential M&A market for minerals and royalties, beyond just cash flow contributions for Diamondback Energy. He also inquired about the specific destinations for Diamondback's natural gas to reduce Waha exposure from 70% to 40% by year-end 2026.

Answer

Kaes Van't Hof (CEO, Diamondback Energy) highlighted the 'huge asset' of private well-level data on half of Permian wells from Viper, allowing engineers to study and replicate others' development changes faster, which is a differential advantage. Danny Wesson (COO, Diamondback Energy) reinforced this, emphasizing understanding well performance and returns. Kaes Van't Hof mentioned space on Whistler and Matterhorn pipelines, with Blackcomb coming online next year (adding 200-250 MMcf/d). He also noted commitment to Energy Transfer's Hugh Brinson Pipeline (east) and saving gas for potential western pipelines or power projects, aiming for market diversity.

Kevin McCurdy asked about the benefits of the CEDEO acquisition for Viper beyond cash flow contributions, specifically for Diamondback Energy (FANG). He also inquired about the destination of gas volumes not going to Waha, given the expected reduction in Waha exposure by year-end 2026.

Answer

Kaes Van't Hof (CEO, Diamondback Energy) highlighted the 'huge asset' of private well-level data from Viper, covering half of Permian wells, which allows Diamondback to study and replicate successful development changes faster than others. Regarding gas, Kaes Van't Hof explained that Diamondback will be on two new pipelines (Whistler and Matterhorn today, Blackcomb next year) and has committed gas to the Hugh Brinson Pipeline (post-Energy Transfer buying WTG), with some gas saved for potential western pipelines or power projects, aiming for better gas realizations and market diversity.

Kevin MacCurdy of Pickering Energy Partners asked about the impact of casing cost inflation on well cost guidance and the drivers behind changes to LOE and GP&T guidance.

Answer

COO Danny Wesson confirmed they have seen about 15% inflation on casing and anticipate more, though their procurement agreement provides some discount to spot prices. CEO Kaes Van't Hof explained the GP&T guidance change was due to taking more gas 'in-kind,' while the LOE improvement reflects strong first-half performance and early synergies from the Endeavor integration, with run-rate LOE expected in the $5.60-$5.80 range.

Kevin MacCurdy asked if pursuing M&A opportunities is a priority for Diamondback in the current distressed environment, given its history as a consolidator.

Answer

President Kaes Van’t Hof responded that following the significant Endeavor and Double Eagle acquisitions, the company is now in a period of patience due to market volatility. He emphasized that the current focus is on reducing share count and debt, and any M&A would have to be 'extremely, extremely cheap,' which is not the case at present.

Kevin MacCurdy requested a breakdown of the 2025 CapEx plan between legacy Diamondback assets and the newly acquired Double Eagle assets. He also asked if any CapEx is associated with the assets targeted for divestiture.

Answer

President Kaes Van't Hof explained that Double Eagle accounts for about $200 million of CapEx from Q2-Q4. He noted that the Q1 2025 guidance of $900 million to $1 billion reflects the pre-deal plan, which involved cutting capital due to market volatility. Regarding assets for sale, he highlighted about $60 million in midstream CapEx associated with the Endeavor water business but stated that CapEx for the non-op Delaware position is not a meaningful number.

Kevin MacCurdy asked for more detail on two key operational changes: the use of clear fluids in drilling and SimulFRAC for completions. He questioned if these practices were being brought to the Endeavor acreage and what percentage of 2024 wells utilized them.

Answer

Chairman and CEO Travis Stice confirmed that these are best practices being implemented across the entire pro forma company. He stated that all Diamondback wells in 2024 used clear fluid and SimulFRAC, and as of the fourth quarter, all rigs and completion crews for the combined company are using these systems, with three of the four frac crews being electric.

Kevin MacCurdy asked for details on Devon Energy's standalone 2026 Delaware program, comparing it to 2025 in terms of targeted zones, geography, and forecasted productivity.

Answer

SVP of E&P Asset Management John Raines stated that 2026 well productivity would be similar to 2025, continuing multi-zone co-development. He detailed that 90% of activity would be in New Mexico (30% Todd, 25% Cotton Draw, 15% State Line), with a zone mix of 40% Wolfcamp, 45% Bone Spring, and 15% Avalon, leading to consistent year-over-year well productivity expectations.

Kevin MacCurdy inquired about Devon's standalone 2026 Delaware program, asking how it compares to the 2025 program in terms of targeted zones, geography, and forecasted productivity.

Answer

John Raines, SVP of E&P Asset Management, stated that 2026 well productivity is expected to be very similar to 2025, with a continued focus on multi-zone co-development. He detailed that approximately 90% of activity will be in New Mexico (30% Todd, 25% Cotton Draw, 15% Stateline), and the zone mix will be about 40% Wolfcamp, 45% Bone Spring, and 15% Avalon, ensuring consistent year-over-year well productivity.

Kevin MacCurdy asked about the industry interest in the Anadarko Basin, the drivers behind this renewed interest, and whether this level of interest prompts Devon Energy to reconsider the Anadarko's place in its portfolio. He also inquired about any operational reasons for Devon to retain its equity interest in Waterbridge following its IPO.

Answer

CEO Clay Gaspar noted the Anadarko's gas-oriented nature, favorable positioning (not behind Waha), and structural advantages, reiterating that the company and its board continuously review the portfolio for long-term shareholder value. Regarding Waterbridge, Clay Gaspar explained that the primary objective of the JV was to secure water management in the Delaware Basin, with the equity ownership being a beneficial byproduct and an 'option value.' SVP of Asset Management John Raines added that the relationship remains operationally important for multifaceted water management, including recycling and strategic offloads.

Kevin MacCurdy asked about the recent industry interest in the Anadarko Basin, what factors are driving this renewed attention, and if this level of interest prompts Devon Energy to reconsider the Anadarko's position within its portfolio. He also inquired about the operational rationale for Devon to retain its equity interest in Waterbridge, given the value creation highlighted on slide nine.

Answer

CEO Clay Gaspar noted the Anadarko Basin's gas-oriented nature and favorable positioning (not behind Waha) as structural advantages, reiterating that the company constantly reviews its portfolio with the board to ensure a sustainable 10-year runway. Regarding Waterbridge, Clay Gaspar and SVP of Asset Management John Raines explained that the primary objective was securing water management in the Delaware Basin, with the equity stake being a beneficial byproduct and an 'option value.' John Raines emphasized the critical operational relationship for cost management, future risk mitigation, and diverse water options across the play.

Kevin MacCurdy sought confirmation that the reduced rig count in the Delaware Basin would not negatively impact 2026 production. He also asked if Devon would consider shifting capital towards gassier assets given the relative strength in natural gas prices.

Answer

President and CEO Clay Gaspar assured that 2026 productivity would not be sacrificed, as the rig count reduction is a direct result of significant drilling efficiency gains, allowing them to maintain the same output with less activity. On capital shifts, he stated that while they are commodity agnostic and constantly evaluate options, they are cautious about 'chasing false positives' from short-term price swings, though they are on 'high alert' given the current market dynamics.

Kevin MacCurdy of Pickering Energy Partners asked for the specific reasons behind the reduction in Devon's 2025 capital guidance since it was first introduced.

Answer

COO Clay Gaspar identified two primary drivers for the lower capital guidance: realized D&C savings of $600,000 per well in the Williston Basin, and anticipated capital efficiency gains from the dissolution of the BPX joint venture in the Eagle Ford. He noted the new guide assumes a status quo for service costs.

Kevin McCurdy asked about the higher 2026 turn-in-line count, its cadence throughout the year, and whether it provides flexibility or optionality for growth in 2027. He also requested an expansion on EQT's combo development strategy.

Answer

EQT CFO Jeremy Knop clarified that the higher turn-in-line count is due to lumpiness from combo development and is not intentionally setting up for 2027 growth, as EQT believes the market isn't ready. President and CEO Toby Rice explained that combo development involves drilling six to ten wells off a site across multiple sites sequentially, a core operational pivot instituted six years ago to achieve step-change efficiencies.

Kevin McCurdy asked about the higher 2026 turn line count, its cadence throughout the year, and whether it provides flexibility or optionality for 2027 growth. He also requested an expansion on EQT's combo development strategy.

Answer

CFO Jeremy Knop clarified that the higher turn line count is due to lumpiness from combo development and is not intentionally setting up for 2027 growth. He stated that EQT would explicitly announce any plans for growth beyond efficiency gains. President and CEO Toby Rice explained that combo development, instituted six years ago, involves drilling 6-10 wells off a site across multiple sites sequentially, developing 20-30 wells at a time, which has been a step-change in operational efficiencies and logistics.

Kevin MacCurdy requested details on the Olympus acquisition, including the contribution from its midstream assets, the impact on operating expenses, and the sales points for the acquired gas. He also asked for clarification on the revised MVP capital contribution guidance, questioning if it was due to timing or a project cost increase.

Answer

CFO Jeremy Knop stated that about $80 million of Olympus's EBITDA is attributable to its midstream assets, and the high margins are due to its integrated nature. The gas is currently sold at M2, but EQT sees opportunities to improve that. Regarding the MVP guidance, Knop clarified it was purely an accounting change to separately book distributions and contributions, with no net change to the project's forecasted cash flow or economics.

Kevin MacCurdy from Pickering Energy Partners inquired about the improvements to Expand Energy's maintenance CapEx, as shown on slide six, noting a reduction compared to the previous quarter despite unchanged guidance, and asked about the significance of the wider production range (7.25-7.75 Bcf) compared to the 2026 guidance. He also asked for details on the $75 million budget for the Western Haynesville, including drilling progression, timing, and expected results.

Answer

Josh Viets, EVP and COO, highlighted a $225 million improvement in maintenance CapEx year-over-year for delivering 7.5 Bcf/day, indicating a stronger business. He explained the wider production range reflects the business's flexibility to adjust volumes based on mid-cycle price views ($3.50-$4.50), allowing for higher production in favorable markets or lower in bearish ones. For the Western Haynesville, Viets detailed plans for roughly 2.5 wells, with the first horizontal well recently drilled and expected to begin production in late Q1/early Q2, noting strong operational performance in terms of days and cost. The remaining wells will appraise the acreage position, focusing on longer-term decline parameters.

Kevin MacCurdy questioned the improvements in Expand Energy's maintenance CapEx, the implications of wider production levels on Slide 6, and the progress and expected results from the $75 million Western Haynesville budget.

Answer

Josh Viets, EVP and COO of Expand Energy, highlighted a $225 million improvement in maintenance CapEx year-over-year for 7.5 Bcf/day, noting the wider production range (7.25-7.75 Bcf/day) reflects flexibility based on mid-cycle price assumptions. Regarding Western Haynesville, he reported that the first of roughly 2.5 scheduled wells was drilled efficiently and is being completed, with first production expected in late Q1/early Q2. The remaining wells will appraise the acreage, focusing on longer-term decline characteristics.

Kevin McCurdy asked for details on the vertical well drilled in Western Hanzo, including observations and attractive aspects of the area. He also inquired about the drivers behind Hanzo's CapEx savings and production outperformance, specifically asking about differences in drilling/completion expectations and what makes their well costs significantly cheaper than peers.

Answer

COO Josh Viets stated that the vertical well in Western Hanzo validated resource potential, revealing a thick, dense shale reservoir with high upside, similar to other successful plays. He noted that Hanzo's cost improvements are largely due to leveraging combined team experience and significant drilling efficiencies. Josh Viets also highlighted the strategic investment in their own sand mine and the evolution of Gen 1 through Gen 3 completion designs as key drivers for lower costs and improved productivity.

Kevin MacCurdy asked if Expand Energy's balance sheet and organization were ready for more M&A and questioned if the company might pull back on its productive capacity spending given market conditions.

Answer

CEO Domenic Dell’Osso stated that the company is focused on integrating its recent large merger and is satisfied with its current portfolio, noting any deal would have to meet a high bar of 'non-negotiables.' He also clarified that the productive capacity strategy provides flexibility on when to bring wells online, but the capital spending plan itself is unlikely to change as it's based on strong long-term fundamentals.

Kevin MacCurdy of Pickering Energy Partners asked about the company's appetite for further M&A given assets being marketed in their operating basins. He also questioned if near-term market weakness might lead them to pull back on spending for productive capacity.

Answer

President, Director & CEO Domenic Dell’Osso stated the company is focused on integrating its recent large merger and has a high bar for any potential deals. He clarified that the capital plan for productive capacity is firm, and any adjustments to near-term market conditions would be made by flexing production timing, not capital.

Kevin MacCurdy asked about Expand Energy's appetite for further M&A given assets being marketed in its basins and questioned if near-term market conditions might cause a pullback in spending on productive capacity.

Answer

President, Director & CEO Domenic Dell’Osso stated the company is focused on integrating its recent large merger and is satisfied with its current portfolio, emphasizing a high bar for any potential deals. He also clarified that the company's plan for productive capacity is set, and any adjustments to near-term market conditions would involve production timing, not capital spend, due to the strong long-term outlook.

Kevin MacCurdy asked for clarification on Antero's production ramp for the year, noting it appeared slightly slower than anticipated, and sought details on the variables impacting the ramp and if it was primarily driven by acquired assets. He also questioned the drivers behind international C3 prices, the progression of the arbitrage, and the current debottlenecking status of Mont Belvieu.

Answer

Michael Kennedy, CFO and SVP of Finance, clarified that the production ramp is proceeding as expected, providing specific quarterly figures and outlining the path to 4.3 Bcfe in 2027, potentially 4.5 Bcfe with growth capital. Dave Cannelongo, Senior Vice President of Liquids, Marketing and Transportation, explained that international C3 pricing is influenced by typical winter rises relative to Naphtha, US export infrastructure issues, and strong domestic demand. He confirmed that the Gulf Coast is at the 'front end' of debottlenecking for LPG exports in 2026.

Kevin MacCurdy questioned the production ramp for the current year, asking about the variables impacting it and if the ramp is primarily driven by acquired assets. He also sought clarification on the drivers of international C3 pricing, the arbitrage dynamics, and the status of Mont Belvieu debottlenecking.

Answer

Michael Kennedy, CEO and President, clarified that the production ramp is proceeding as expected, with specific quarterly targets leading to 4.3 Bcfe in 2027 and potentially 4.5 Bcfe with growth capital. Dave Cannelongo, Senior Vice President of Liquids, Marketing and Transportation, explained that international C3 pricing is driven by typical winter demand relative to naphtha, with U.S. export infrastructure issues from 2025 resolving in Q1 2026, and confirmed that Gulf Coast debottlenecking is in its early stages.

Kevin MacCurdy inquired about the drivers of the gassier production mix in Q2 and whether the company's recent hedging activity reflects a bullish internal view on natural gas prices.

Answer

CFO Michael Kennedy explained the gassier mix was temporary, caused by bringing lean gas DUC pads online, and that the mix will become more liquids-rich in Q4. He confirmed the 2026 collars reflect a bullish view, stating the market is 'razor thin' with significant upside potential, making it prudent to lock in the capital program while retaining 80% of the upside exposure.

Kevin MacCurdy asked about long-term strategy, inquiring what market dynamics would prompt Antero to grow production volumes and if there were any operational constraints. He also questioned the company's flexibility to shift LPG sales between domestic and international markets in 2026 if arbitrage opportunities narrow.

Answer

CFO Michael Kennedy stated that significant, long-term local demand, such as from new power plants or data centers, would be required to incentivize growth, as their current maintenance program already fills their firm transportation and processing capacity. Regarding 2026 LPG sales, Kennedy expressed confidence in their marketing team's ability to analyze market dynamics and make opportunistic decisions to maximize value.

Kevin MacCurdy asked how current well costs compare to the 2024 average, what is assumed in the 2025 guidance, and the outlook for service costs. He also inquired about the drivers behind the strong 2025 guidance for ethane pricing and the repeatability of Q4's high ethane production.

Answer

CFO Michael Kennedy stated that current well costs are in the low $900s per foot, down from $925 in 2024, due to new, lower-rate drilling contracts. The 2025 plan bakes in the efficiency gains achieved in 2024. SVP of Liquids Marketing Dave Cannelongo explained the improved ethane differential guidance is due to stronger-priced sales contracts coming online and the expiration of a less favorable contract, giving them high confidence in the 2025 forecast.

Kevin MacCurdy asked for a breakdown of the recent $25 million reduction in 2024 CapEx between efficiency gains and deferred activity. He also questioned how these factors impact the updated $700 million D&C maintenance CapEx budget for 2025.

Answer

CFO Michael Kennedy specified that the CapEx reduction consisted of $15 million from efficiencies and $10 million from deferrals. He confirmed that the $700 million maintenance capital forecast for 2025 fully incorporates these recent efficiency gains, such as improved cycle times and lower well costs.

Kevin McCurdy asked about the production trajectory throughout the year, inquiring if Q2 production would resemble year-end 2025 levels and if the company could provide an exit rate for production, assuming the operation of nine rigs. Kevin McCurdy then followed up, asking about lateral lengths in the Western Haynesville, noting they were lower in Q4 2025 and impacted per-foot costs. He inquired about the outlook for lateral lengths in 2026 and the long-term goals for lateral lengths in the play.

Answer

Roland Burns, President and CFO, declined to provide an exit rate due to its high dependency on timing. Ron Mills, VP of Finance and Investor Relations, added that significant production growth is expected over the year, with over 65 wells coming online after Q1, pointing to a strong Q4 rate. He clarified that the ninth rig's impact would be more significant in 2027 due to capital lag. Dan Harrison, COO, stated that the long-term goal for Western Haynesville laterals is to be longer, acknowledging that geology currently dictates lengths and shorter laterals lead to higher costs. He mentioned targeting a first 15,000-foot lateral soon and expects rotary steerable systems and the 10K rig upgrade to facilitate longer laterals in the future.

Kevin McCurdy asked about Comstock's production trajectory for 2026, specifically if Q2 would resemble year-end 2025 levels given less downtime, and if the company could provide an exit rate assuming nine rigs. He also inquired about the lower lateral lengths in the Western Haynesville this quarter, their impact on per-foot costs, and the long-term goals for lateral lengths in that play.

Answer

President and CFO Roland Burns noted that exit rates are highly dependent on timing, but VP of Finance and Investor Relations Ron Mills added that significant growth is expected over the year, with 65+ wells coming online after Q1, pointing to a strong Q4 rate. He suggested the ninth rig's impact would be more significant in 2027 due to capital lag. Chief Operating Officer Dan Harrison explained that lateral lengths are influenced by geology, and shorter laterals can lead to higher costs. He stated the long-term goal is longer laterals, with plans to drill a 15,000-foot lateral soon, and expects rotary steerable technology and rig upgrades to help achieve this.

Kevin McCurdy asked about the financial and operational impacts of the Surmont Pad 104 WA in Canada coming online ahead of schedule, and whether this early delivery indicates an ongoing trend for operations there.

Answer

Kirk Johnson, Executive Vice President of Global Operations and Technical Functions, ConocoPhillips, confirmed that Surmont Pad 104 WA came online about a month early. He stated that this activity is level-loaded, with a new pad expected every 12-18 months (the next one in approximately 12 months), resulting in no material change to capital or production profiles, but it de-risks growth. Gross volumes continue to climb, offsetting decline, reflecting strong asset performance.

Kevin McCurdy asked about the financial and operational impacts of the Pad 104 WA Surmont pad coming online ahead of schedule in Canada, and whether this indicates an ongoing trend for operations there.

Answer

Kirk Johnson, EVP of Global Operations and Technical Functions, highlighted strong performance at the Surmont asset, with Pad 104 WA achieving first oil ahead of schedule. This activity is cascading to the next pad (104 WB), with new pads expected every 12-18 months. He noted that this level-loaded activity de-risks growth without material changes to capital or production profiles, as gross volumes continue to climb and offset decline, reflecting disciplined capital deployment.

Kevin MacCurdy asked for high-level details on how ConocoPhillips expects to achieve the $4 billion free cash flow from Willow in 2029, specifically regarding margins, production, and maintenance CapEx, and if this is a good number for post-2029.

Answer

Kirk Johnson (EVP of Global Operations and Technical Functions) explained that the $4 billion free cash flow improvement comes from a reduction in capital from over $2 billion (current year spend) to an average of $500 million in sustaining capital post-first oil, combined with the CFO generated from 100% oil sales at Brent premium prices. Ryan Lance (Chairman and CEO) reminded that this is based on $70 prices, with sensitivities provided in materials.

Kevin MacCurdy asked for high-level details on how Willow's $4 billion free cash flow inflection is achieved, including margins, production, and maintenance CapEx in the first year, and if this is a sustainable number post-2029.

Answer

Kirk Johnson, Executive Vice President of Global Operations and Technical Functions, explained that the $4 billion inflection comes from a reduction in capital spend from over $2 billion to an average of $500 million annually post-first oil, combined with the cash flow from 100% oil sales at Brent premium prices. Ryan Lance, Chairman and CEO, reminded that this is based on $70 WTI prices, with sensitivities provided in materials, and thanked participants for their interest.

Kevin MacCurdy asked for an explanation for the Q1 cash flow miss relative to market expectations, focusing on the higher-than-expected cash taxes and the outlook for the year.

Answer

EVP and CFO William Bullock explained that the full-year effective tax rate is now forecast to be higher, near 40%, due to a geographic income mix shifting to higher-tax jurisdictions. The Q1 cash tax rate was specifically impacted by one-time discrete deferred tax items related to Lower 48 dispositions, which created a temporary headwind. He noted that underlying deferred tax benefits from normal operations continue to be realized.

Kevin MacCurdy asked about the quarterly decline in the company's oil mix, questioning if it was driven by the Surmont turnaround and what the outlook is for the oil mix going forward.

Answer

Nick Olds, EVP of Lower 48, noted that the Lower 48 oil mix has been stable at 52-53%. Andy O'Brien, SVP of Strategy, confirmed the questioner's hypothesis, stating there was nothing unusual in the mix and the primary driver for the company-wide change was the major turnaround at Surmont, which is a 100% oil asset.

Kevin MacCurdy asked about the impact of Matador's increased activity on San Mateo's volumes and its EBITDA outlook.

Answer

Bryan Willey, Executive Vice President of Midstream, explained that San Mateo's partnership with Matador is critical, with 70-80% of its revenues coming from Matador. He noted that Matador's growth often leads to growth for San Mateo, and approximately $90-$100 million of the projected 2026 capital expenditure increase is allocated to midstream (San Mateo's share and Matador-owned assets) to support this expansion and continued business growth.

Kevin MacCurdy of Pickering Energy Partners asked for an update on cash taxes, specifically when Matador might become subject to the Alternative Minimum Tax (AMT) and how cash taxes are expected to trend.

Answer

Robert Macalik, EVP of Administration & Finance, stated that recent tax act changes are expected to generate significant cash tax savings. He believes these changes will push out any potential obligations under the AMT for several years based on current commodity price rates, though the company is still finalizing its analysis. This is viewed as a benefit for 2025 and beyond.

Kevin MacCurdy from Pickering Energy Partners requested details on the recent cash tax reductions, asking when Matador might become subject to the Alternative Minimum Tax (AMT) and how cash taxes are expected to trend.

Answer

Robert Macalik, EVP of Administration & Finance, stated that recent tax act changes are expected to generate significant cash tax savings. He confirmed that these changes will push out the company's obligations under the AMT for 'several years' based on current projections, with the benefits beginning in 2025.

Kevin MacCurdy of Pickering Energy Partners asked for clarity on cash taxes, specifically when Matador might become subject to the Alternative Minimum Tax (AMT) and how taxes will trend until then.

Answer

Robert Macalik, EVP of Administration and Finance, stated that recent tax developments are expected to push out the company's obligations under the AMT for 'several years' based on current commodity price rates. He confirmed this will be a benefit to free cash flow starting in 2025, though the company is still finalizing its analysis.

Kevin MacCurdy of Pickering Energy Partners asked for clarity on when Matador might become subject to the Alternative Minimum Tax (AMT) and how cash taxes are expected to trend until then.

Answer

Robert Macalik, EVP of Administration and Finance, confirmed that recent tax changes will provide significant cash tax savings. He stated that these changes are expected to push out any obligations under the AMT for 'several years' based on current rates, providing a benefit to free cash flow starting in 2025. The company is still analyzing the full impact.

Kevin MacCurdy of Pickering Energy Partners asked about the specific criteria governing the share buyback program, including what valuation metrics would be used and if it would be tied to a percentage of cash flow.

Answer

Brian Willey, EVP and CFO, stated that the decision is not based on a single metric but a mix of factors. He reiterated that the company will evaluate all uses of cash—including debt repayment, acquisitions, midstream expansion, adding a rig, or increasing the dividend—to determine what provides the most long-term value for shareholders.

Kevin MacCurdy asked about the company's plans for using its projected $1 billion in 2025 free cash flow, considering its low leverage and unlocked midstream value, and what other considerations exist beyond the dividend.

Answer

CEO Joseph Wm. Foran emphasized a strategy of 'profitable growth at a measured pace,' highlighting numerous opportunities across their inventory and midstream business. He stated a preference for steady dividend increases over stock buybacks, which he believes favor short-term investors. Executive Bryan Erman added that the company is excited to be in a position to return value to shareholders through its growing free cash flow.

Kevin MacCurdy from Pickering Energy Partners asked about the drivers behind the significant production increase from the Ameredev assets and the expected production and activity trajectory for these assets in the medium term.

Answer

Glenn Stetson, EVP of Production, attributed the outperformance to seven new, high-performing Tea Olive wells brought online before the acquisition closed. He noted that Q4 production may see a slight, temporary dip due to shut-ins related to fracturing operations on 11 new wells. Edmund Frost, EVP of Geoscience, added that the strong well results confirm the high quality of the rock in that part of the basin.

Kevin MacCurdy asked about the income trajectory for OxyChem, questioning if the PVC oversupply is temporary and how it affects the 2026 free cash flow outlook.

Answer

CFO Sunil Mathew explained that the market is burdened by excess Chinese capacity, which is compressing margins. He does not anticipate significant improvement in 2026 from announced capacity rationalizations and expects market conditions to remain similar to 2025, with margins near the variable costs of international producers.

Kevin MacCurdy asked about the CapEx savings from this year's expanded four-mile program and the potential annual savings from a 50% adoption rate. He also questioned if the lower turn-in-line count impacts Q4 production or CapEx.

Answer

President, CEO & Director Daniel Brown explained that CapEx savings this year are de minimis due to the program's small scale. He noted that while a larger program would reduce capital, the exact amount depends on the future mix of well lengths. Regarding the turn-in-line count, he confirmed it impacts production volumes but reiterated the company's focus is on optimizing free cash flow per share, not absolute production.

Kevin MacCurdy from Pickering Energy Partners asked to quantify the CapEx savings from doubling the four-mile lateral program in 2025 and the potential annual savings from shifting 50% of the program to these longer laterals. He also inquired if the reduced turn-in-line (TIL) count for the year affected the Q4 production or CapEx guide.

Answer

CEO Daniel Brown stated that CapEx savings for 2025 are de minimis due to the small scale of the change. He noted future savings will depend on the mix of well lengths but confirmed longer laterals exert downward pressure on capital. Regarding the TIL count, Brown explained that while fewer TILs impact production, the focus remains on free cash flow per share, and the timing shift into early 2026 is a normal part of operations.

Kevin MacCurdy from Pickering Energy Partners asked for a summary of the new Texas Railroad Commission guidelines on injection pressure and how they affect LandBridge's competitive position. He also inquired about the potential long-term EBITDA impact and royalty rates associated with the new Devon Energy deal.

Answer

CEO Jason Long explained that the new rules focus on preventing concentrated injection, which aligns perfectly with LandBridge's strategy of using its large, contiguous acreage to spread out disposal activities. CFO Scott McNeely added that this regulatory shift validates their long-held operating philosophy. Regarding the Devon deal, McNeely stated that while he couldn't disclose the exact royalty rate, it aligns with their view of the prevailing market rate, with financial impacts beginning in 2027.

Kevin MacCurdy of Pickering Energy Partners inquired about the implications of a potential Permian oil production rollover on LandBridge's acreage and asked for an update on data center development.

Answer

CFO Scott McNeely stated that LandBridge's acreage is in the most economic core of the basin, insulating it from pullbacks in fringier areas, and that producers have not altered development plans through 2027-28. Regarding data centers, McNeely reiterated the 12-18 month update timeline, noting continued strong momentum. He also highlighted growing opportunities in broader in-basin power generation, which requires land and water, and expects positive updates on that front soon.

Kevin MacCurdy from Pickering Energy Partners asked about the oil price assumptions embedded in the 2025 guidance and the business's sensitivity to commodity prices. He also requested details on the expected EBITDA impact and timing of the new DESRI solar agreement.

Answer

Executive Scott McNeely stated that the 2025 guidance is based on firm operator plans and assumes no meaningful activity ramp, with minimal sensitivity to commodity prices as the minerals business is expected to be less than 10% of revenue. He explained the DESRI solar project will take 2-3 years for development, after which it is expected to contribute mid-to-high single-digit millions in annual cash flow.

Kevin MacCurdy asked about the specific drivers behind the outperformance of the produced water business, which is boosting the 2025 EBITDA forecast. He also inquired about the company's macro outlook for the Delaware Basin, specifically regarding efficiency gains and water cuts.

Answer

Scott McNeely (executive) attributed the produced water strength to the Devon partnership, strong commercial traction with blue-chip operators, and the symbiotic relationship with WaterBridge. Jason Long (executive) added that strategic land acquisition based on geology and pore space has been key. Regarding the macro outlook, Scott McNeely noted that producer efficiency gains and a shift to developing deeper benches with inherently higher water cuts are driving increased water volumes, benefiting LandBridge through higher royalties.

Kevin MacCurdy of Pickering Energy Partners asked how the reduction in rig count would affect the DUC backlog by year-end. He also sought clarification on the use of free cash flow, specifically whether the term loan would be paid off before share buybacks resume.

Answer

SVP of Business Units Michael Deshazer noted that the company enters 2025 with a healthy DUC inventory and the change is manageable. Chairman, CEO and President Thomas Jorden clarified that debt repayment and buybacks can happen concurrently, with debt repayment being front-end weighted and buybacks back-end weighted, and that the 50% return goal is best enabled by maintaining low leverage.

Kevin MacCurdy asked how dynamically EOG plans to manage its new capital structure and if it would continue high payout ratios even if it resulted in a net debt position. He also sought to define the dollar threshold between a 'low-cost bolt-on' and 'significant M&A'.

Answer

CFO Ann Janssen stated that the company has flexibility in its debt and cash levels and will manage them according to business needs. Chairman and CEO Ezra Yacob clarified that the distinction for acquisitions is based on value drivers, not a specific dollar amount. EOG targets low-PDP assets with high undrilled upside, often in emerging plays, to enhance long-term margins rather than paying premiums for established assets.

Kevin MacCurdy requested clarification on Utica well costs, asking for a dollar-per-foot figure for the latest wells. He also sought confirmation that current CMM volumes are not capped and could be increased if incentives materialize, and what the total potential capacity might be.

Answer

CFO Alan Shepard provided a target Utica well cost of approximately $1,800 per foot for 2024. He also confirmed that CMM volumes are not capped and could grow with proper incentives but declined to estimate total capacity without final regulations.