John Freeman

John Freeman from Raymond James inquired about National Fuel Gas Company's co-development strategy for Upper and Lower Utica, and whether the company's M&A focus would shift towards upstream or unregulated businesses after the CenterPoint acquisition.

Answer

Justin Loweth, President of Seneca Resources and National Fuel Midstream, stated that the current base plan favors Lower Utica development first, but ongoing co-development tests will inform the conclusive strategy. Dave Bauer, President and CEO, indicated that post-CenterPoint, the company would have flexibility to pursue M&A opportunities in both regulated and non-regulated segments, prioritizing the best shareholder returns.

John Freeman asked about the determined co-development strategy for the Upper Utica and whether the company's M&A focus would shift back to unregulated businesses after the CenterPoint acquisition closes.

Answer

Justin Loweth, President of Seneca Resources and National Fuel Midstream, explained that the current base plan favors Lower Utica development first due to slightly better economics, but ongoing co-development tests over the next 12-18 months will inform the conclusive strategy. Dave Bauer, President and Chief Executive Officer, stated that the CenterPoint deal rebalances the company, allowing flexibility to pursue M&A opportunities in both regulated and non-regulated sectors based on the best shareholder returns.

John Freeman from Raymond James asked about the potential benefits to NFG from the revitalization of the Constitution and NESE pipelines and inquired if the fiscal 2026 guidance incorporates further well productivity gains from next-generation well designs.

Answer

Justin Loweth, President of Seneca Resources, explained that both projects would be beneficial, with NESE positively impacting existing firm transport and Constitution likely improving in-basin pricing. He added that while some productivity gains are baked into guidance, the key upside is how long wells can maintain high, flat production rates, which could offer further positive bias.

John Freeman from Raymond James asked if the company's bullish gas outlook would shift its hedging strategy more towards collars to retain upside, and also sought clarity on the drivers for the lower utility O&M guidance.

Answer

CFO Tim Silverstein confirmed that with a strong balance sheet, they would indeed skew more towards collars, citing recent hedges with $4 floors and $5.50 caps as ideal examples. Regarding O&M, he explained the guidance reduction reflects strong cost control performance, which is a continuous focus for the company to ensure acceptable returns on its regulated assets.

John Freeman asked if the bullish gas outlook would shift hedging toward collars versus swaps and about the utility O&M expense guidance.

Answer

CFO Timothy Silverstein stated they would skew more towards collars and discussed the factors influencing the utility O&M expense guidance.

John Freeman asked about the $75 million full-year CapEx reduction, specifically the $25 million less allocated to Northeast Appalachia, inquiring if it was due to timing, curtailments, or efficiency gains. He also asked about the company's debt reduction progress, how future debt reduction compares to other capital returns like buybacks, and if a similar amount will be allocated to debt reduction next year.

Answer

COO Josh Viets clarified that the Northeast Appalachia CapEx reduction was primarily driven by seasonal demand weakness and prioritizing curtailments in that region. CEO Nick Dell'Osso stated that Expand Energy would continue to prioritize debt paydown into next year, noting the company's ability to both retire significant debt ($1.2 billion) and return capital to shareholders ($850 million) this year, maintaining financial flexibility for future capital allocation decisions.

John Freeman asked if the full-year guidance incorporates the recent record drilling cycle times and questioned why the free cash flow optimization heat map hasn't changed despite significant cash flow improvements.

Answer

Executive VP & COO Josh Viets confirmed that current guidance reflects the Q2 performance with expectations for continued modest improvement. CEO Domenic Dell’Osso and VP of IR Chris Ayres clarified that the heat map's colors are relative; while absolute free cash flow has increased at all price points (reflected in lower maintenance capital), the relative optimization strategy between production levels has not shifted enough to change the chart's color-coding.

John Freeman questioned if the full-year guidance incorporates the leading-edge Q2 drilling cycle times and asked why the free cash flow optimization 'heat map' chart hasn't changed despite significant cash flow improvements.

Answer

Executive VP & COO Josh Viets confirmed that guidance reflects Q2 performance with expectations for continued modest improvement. President, Director & CEO Domenic Dell’Osso and VP of IR Chris Ayres explained the heat map's colors are relative, showing optimal production levels at different prices. The cash flow improvements are reflected in lower maintenance capital at every level, which doesn't shift the relative optimization points.

John Freeman of Raymond James Financial asked if the full-year guidance already reflects the leading-edge Q2 drilling cycle times. He also questioned why the free cash flow optimization heat map hasn't changed its color-coding despite significant improvements in projected cash flow.

Answer

Executive VP & COO Josh Viets confirmed that the guidance incorporates recent performance and even assumes a modest ongoing learning curve. President, Director & CEO Domenic Dell’Osso and VP of IR Chris Ayres explained that the heat map's colors are relative, showing the optimal production level for a given price, and the absolute cash flow increase did not shift the relative optimization choice.

John Freeman asked how management balances its portfolio between stable, low-decline legacy assets and emerging high-growth plays like the Mancos. He also asked for details on recent steps taken to improve gas marketing and mitigate wide basis differentials.

Answer

CEO Tom Ward explained that the balance is maintained by adhering to a disciplined reinvestment rate of ~50% of operating cash flow, which is enabled by the low-decline asset base. CFO Kevin White clarified that a recent marketing arrangement change with NextEra, while reclassifying some costs to GP&T, is expected to yield better overall pricing going forward.

John Freeman sought to confirm that the full-year reinvestment rate would still be around 50% at the current commodity strip, despite a low Q1 rate. He also asked about the M&A market for larger deals and whether the bid-ask spread remains wide in the current volatile environment.

Answer

Executive Tom Ward confirmed the full-year reinvestment rate target remains approximately 50%. Regarding M&A, he acknowledged that distressed opportunities take time to develop but noted Mach is becoming more competitive on bids for assets outside its core Mid-Con area, such as in the Eagle Ford and Permian. This suggests that seller expectations may be adjusting and bid-ask spreads are potentially narrowing.

John Freeman sought clarification on the midstream and land expenditure budget, which doubled as a percentage of the total, and asked about the impact of increased regional drilling activity on Mach's non-op budget.

Answer

CEO Tom Ward and CFO Kevin White clarified that the budget for land and midstream is around $30 million, with the increase primarily driven by leasing activity to support a larger drilling program. Tom Ward added that the non-op budget remains consistently low as the company elects out of most non-operated well proposals.

John Freeman from Raymond James inquired about Mach's 2025 operational plan, asking for the number of wells expected to be turned online, the potential for quarterly lumpiness in the drilling program, and the reasons for the implied increase in Q4 Lease Operating Expense (LOE).

Answer

Executive Tom Ward stated the 2025 plan includes over 40 gross wells and that program pacing depends on commodity prices to maintain the 50% reinvestment rate. Executive Kevin White explained that the higher LOE guidance is due to the temporary dilutive effect of high-volume, low-cost flush production from the recently acquired Paloma assets normalizing.

John Freeman of Raymond James Financial inquired about the timeline for achieving the new $3 billion net debt target and the potential use of divestitures to accelerate it. He also asked if the recent success and acreage expansion in Egypt would lead to a higher CapEx allocation to the region in the future.

Answer

EVP & CFO Ben Rodgers explained that the debt target is not tied to a specific date but is achievable within approximately four years via organic free cash flow, with no mention of divestitures as a primary tool. CEO John Christmann, President Stephen Riney, and EVP of Exploration Tracey Henderson collectively detailed the significant gas potential in Egypt, highlighting the new gas price agreement, recent operational success, and vast exploration opportunities on the newly awarded acreage, suggesting a strong ongoing focus on the region.

John Freeman of Raymond James & Associates, Inc. asked about APA's accelerated cost savings, questioning if the absolute target of $350 million might be increased in the future. He also inquired if the new 6-rig count in the Permian is sufficient to maintain flat production or if it relies on future efficiency gains.

Answer

CEO John Christmann confirmed that APA is significantly ahead of schedule on its cost-saving initiatives and anticipates that the $350 million run-rate savings target will likely be raised in the future. He also expressed confidence that ongoing efficiency improvements will allow the company to hold Permian oil production flat with a 6-rig program well into 2026.

John Freeman inquired about the cash outflow cadence for the North Sea Asset Retirement Obligation (ARO) and sought a breakdown of the drivers behind the projected 10-15% decline in LOE for 2025.

Answer

CFO Stephen Riney detailed the North Sea ARO, stating the net after-tax present value is $1.2 billion, with roughly half to be spent by 2030 in a ramping pattern. He clarified this spending appears as 'costs incurred,' not CapEx. CEO John Christmann attributed the significant LOE reduction to Callon synergies and portfolio simplification, such as divesting high-cost waterflood assets. More detailed breakdowns are expected in February.

John Freeman of Raymond James Financial asked for clarification on the impact of new marketing agreements on future GP&T unit costs and questioned whether Permian Resources might evolve its midstream strategy to include asset ownership, similar to other large E&P peers.

Answer

CFO Guy Oliphint stated that the new agreements will not change GP&T costs, and Co-CEO James Walter clarified the announced netback improvements are net of all costs. Walter also explained that while they evaluate all options, owning midstream assets does not currently compete with the high returns of their upstream drilling program, making them prefer commercial agreements.

John Freeman asked about the company's ability to consolidate the non-operated portion of the new bolt-on acquisition. He also questioned the strategic trade-offs between reducing activity in a weak oil price environment versus maintaining operational momentum.

Answer

Hays Mabry, an executive, stated that the company has active trade discussions with all major Delaware Basin operators and is confident in its ability to convert the newly acquired non-op acreage to operated. Regarding activity levels, he explained that the capital program is returns-focused, and recent efficiency gains are being directed toward lower CapEx rather than higher production, while maintaining maximum operational flexibility.

John Freeman asked for details on the cost savings from recent simul-frac operations and the company's long-term goals for water recycling.

Answer

Co-CEO William Hickey quantified the simul-frac savings at $10 to $15 per foot. He elaborated that the company, currently recycling 50% of its water, aims to increase this to two-thirds or even three-quarters over the next two years, primarily through third-party contracts, which minimizes direct capital expenditure.

John Freeman of Raymond James inquired about the new produced water agreement with Landbridge and asked if Devon has an option to purchase power from the new CPV gas-to-power facility.

Answer

SVP John Raines explained the Landbridge deal is a proactive part of their water management strategy, providing a long-term solution to move water to a lower-pressure part of the Delaware Basin. Regarding the CPV facility, EVP & CFO Jeff Ritenour stated that while it's an option, they have not negotiated a power purchase agreement as their electricity load demand on the Texas side is not as significant as their peers.

John Freeman of Raymond James inquired about the new produced water agreement with Landbridge and asked if Devon has an option to purchase power from the new CPV gas-to-power facility.

Answer

SVP John Raines described the Landbridge deal as a proactive, strategic move to manage over a million barrels of daily produced water in the Delaware Basin, providing long-term disposal capacity in a lower-pressure area starting in 2027. Regarding the CPV facility, EVP & CFO Jeff Ritenour confirmed they do not currently have a power purchase agreement but it remains an option, with Raines adding that their power needs on the Texas side are currently met.

John Freeman of Raymond James inquired about the strategic runway provided by the new produced water agreement with Landbridge and asked if Devon has the right to purchase power from the new CPV gas sales agreement.

Answer

SVP John Raines described the Landbridge deal as a key part of their proactive water management strategy, providing a long-term advantage by moving water to a lower-pressure area of the basin. EVP & CFO Jeff Ritenour and John Raines stated that Devon does not currently have an agreement to purchase power, as its electricity load on the Texas side of the basin is not as high as its peers.

John Freeman questioned the importance of the reinvestment rate in Devon's budgeting process and asked if the recent capital allocation for land trades in the Delaware Basin signals a renewed focus on such transactions.

Answer

President and CEO Clay Gaspar explained that while the reinvestment rate is a consideration, it is not a primary target they 'goal seek' for in budgeting. He characterized the land trades as highly valuable 'ground game' work to secure acreage ahead of the drill bit. He emphasized that the company's $100 million capital reduction was achieved despite absorbing an additional $50 million in capital from these value-accretive trades, highlighting significant underlying efficiency gains.

John Freeman of Raymond James Financial, Inc. questioned if Devon's portfolio offers flexibility to shift capital towards natural gas assets given recent price strength and asked for the number of frac crews assumed in the 2025 plan.

Answer

CFO Jeff Ritenour responded that oil-focused projects consistently deliver superior returns, with gas upside coming from associated volumes. COO Clay Gaspar specified the 2025 plan assumes three consistent frac crews in the Delaware, plus 2-3 additional crews elsewhere, for a ballpark total of six crews.

John Freeman from Raymond James Financial inquired about the specific drivers behind the recent drilling and completion efficiency gains, particularly on the completion side, and asked if the significant well outperformance in the Uinta Basin might alter future capital allocation strategies within the basin.

Answer

CEO & Director David Rockecharlie attributed the efficiency improvements to the expanded use of best practices like simul-frac operations. Regarding the Uinta Basin, he explained that while the company is excited about the expanding economic inventory, they plan to remain patient and methodical in their capital allocation to optimize the long-term development of the significant stacked resource.

John Freeman inquired about the role Crescent's extensive hedge book plays in decisions to potentially alter activity levels. He also asked about the decision-making process for allocating free cash flow between share buybacks and debt reduction.

Answer

CEO David Rockecharlie explained that hedges are treated as a separate asset to protect the balance sheet and are not linked to operational decisions at the drill bit. Executive Brandi Kendall stated that capital allocation prioritizes the balance sheet and dividend, after which they weigh the returns of buybacks, M&A, and drilling. David Rockecharlie added that the stock is a liquid M&A opportunity, unlike the broader A&D market.

John Freeman noted the significant free cash flow projected for 2025 and asked for the priority ranking for its use, specifically between share buybacks and reaching the 1.0x leverage target. He also inquired if more U-turn wells are slated for the 2025 plan.

Answer

CFO Brandi Kendall affirmed that the capital allocation priorities are unchanged: the base dividend and balance sheet strength come first. Beyond that, capital is deployed to the best risk-adjusted return, whether through opportunistic buybacks, internal investment, or M&A. She also clarified that while U-turn wells are a valuable operational tool, none are specifically scheduled in the 2025 plan, but they could be used opportunistically to optimize development.

John Freeman asked about opportunities for well outperformance on the acquired SilverBow assets and sought a target for the percentage of combined Eagle Ford activity that would utilize simul-frac completions in 2025.

Answer

David Rockecharlie, an executive, clarified that both companies had strong operational histories and they expect to be 'better together,' with immediate synergies in D&C costs and long-term gains from drilling and production optimization. He declined to provide a specific simul-frac target for 2025, stating it depends on land and development planning, but confirmed they will aim to increase its use.

John Freeman of Raymond James Financial inquired about Diamondback's strategy for improving oil recovery rates and asked about the production associated with a recent non-operated Delaware Basin asset sale.

Answer

CEO Kaes Van't Hof highlighted the company's development strategy, emphasizing that its low-cost structure allows for drilling more wells per section, which naturally improves resource recovery compared to peers. He also noted that any new technology developed in the basin would benefit Diamondback. He confirmed the divested asset had a little over 1,000 barrels a day of net oil production.

John Freeman sought to clarify if the $65-$70 oil price threshold for accelerating activity was firm even with potential cost improvements, and asked about the factors offsetting rising steel-related costs.

Answer

President Kaes Van’t Hof affirmed that due to macro uncertainty, the company would patiently wait for a $70-plus crude environment before accelerating activity. COO Daniel Wesson explained that while casing costs are up, strong operational execution and anticipated service cost deflation from lower basin activity are offsetting the increase.

John Freeman asked for details on the midstream infrastructure budget, questioning if there were any one-time expenses related to the Double Eagle or Endeavor deals, and also requested the pro forma DUC count following the Double Eagle transaction.

Answer

President Kaes Van't Hof identified about $60 million in midstream CapEx from the Endeavor water business that could be monetized, plus $60-$70 million in accelerated one-time environmental CapEx this year. He stated the goal is to reduce infrastructure spending to 5-7% of total capital. Chairman and CEO Travis Stice added that the pro forma DUC count was just over 200, with Double Eagle contributing about 50 DUCs.

John Freeman asked how Diamondback plans to leverage its dramatically increased scale to improve realized natural gas pricing, particularly with Endeavor's flexible marketing contracts. He also inquired about the practical process for testing and implementing shared best practices between the two companies.

Answer

President and CFO Kaes Van't Hof outlined a multi-pronged gas strategy, including commitments to the EPIC, Whistler, and Matterhorn pipelines, securing future capacity on Blackcomb, and exploring in-basin power generation to diversify risk. Chairman and CEO Travis Stice described the integration process as co-locating teams to foster collaboration, ensuring best practices from both sides are adopted to deliver synergies faster than promised.

John Freeman questioned the apparent disconnect between the record-high wells-in-process (WIP) inventory and the moderated second-half turn-in-line (TIL) forecast. He also asked how the pending legal settlement funds would be treated in capital allocation.

Answer

President Adam Dirlam and CEO Nicholas O’Grady explained that the lag is due to operators deferring completions and elongating spud-to-sales times in the current price environment, which will result in a higher DUC inventory at year-end. They also stated the legal settlement proceeds will be treated as working capital and integrated into the normal capital allocation process.

John Freeman asked for a quantification of the budget allocated to workovers and refracs for 2025 compared to 2024, and how actual 2024 AFE costs compared to the initial budget.

Answer

CFO Chad Allen stated that workovers and refracs are budgeted at 10-15% of CapEx, similar to last year but a larger absolute number. President Adam Dirlam noted that normalized AFE costs saw a ~15% benefit year-over-year in 2024, with downward pressure from efficiencies gained in joint ventures.

John Freeman asked about the potential for further reductions in maintenance capital expenditures into 2026 and the cash flow impact from recent tax law changes.

Answer

CFO Michael Kennedy confirmed that maintenance CapEx is expected to continue declining, driven by ongoing well cost reductions, a return to longer laterals, and other efficiencies. He also stated that due to new tax rules and existing attributes, Antero does not expect to pay any material cash taxes for the next three years, pushing payments out to at least 2028.

John Freeman inquired about the shareholder return strategy, asking if the company is now implementing a 50/50 split between debt reduction and buybacks, or if they are still targeting a debt milestone first. He also asked about the 2026 hedging strategy and whether more hedges should be expected.

Answer

CFO Michael Kennedy confirmed they have pivoted to a 50/50 strategy opportunistically, driven by the perceived value in their shares. He noted the company's strong cash flow visibility and low debt provide this flexibility. Regarding hedging, Kennedy stated there is no change in their bullish long-term view, but the ability to lock in high-return collars for specific 2026 lean gas pads was a unique, attractive opportunity.

John Freeman asked for clarification on the number of drilled but uncompleted (DUC) wells versus wells in progress at year-end, and inquired if Antero is focused on acquiring incremental firm transportation (FT) capacity from other operators.

Answer

CFO Michael Kennedy confirmed that the company brought 16 wells online in January and still has one DUC pad with seven wells scheduled for Q3. He stated that Antero is not seeking additional FT capacity, as the company is satisfied with its current, comprehensive portfolio which provides access to premium markets.

John Freeman of Raymond James Financial asked if, in a hypothetical lower-for-longer oil price scenario, Matador might shift more growth capital from drilling towards its midstream business.

Answer

EVP & CFO William Lambert responded that the company's integrated business model is designed to deliver best-in-class free cash flow margins in any price environment. He stressed that the initial midstream investment was crucial for flow assurance, which enabled strong oil production and free cash flow. EVP G. Gregg Krug reinforced this by highlighting San Mateo's 99% operational runtime, which provides critical takeaway assurance.

John Freeman of Raymond James Financial asked if, in a hypothetical 'lower for longer' oil price scenario, more growth capital might be allocated to the midstream business instead of drilling.

Answer

EVP and CFO William Lambert responded that the primary goal is delivering best-in-class free cash flow margin, regardless of commodity prices. He emphasized that the midstream investment was critical for flow assurance, which enabled the company's strong oil production and free cash flow. EVP G. Gregg Krug added that San Mateo's 99% operational runtime provides crucial reliability for getting products to market.

John Freeman from Raymond James Financial asked if, in a hypothetical 'lower for longer' oil price scenario, more growth capital might be shifted from drilling to the midstream business.

Answer

EVP and CFO William Lambert responded that the primary goal is to deliver best-in-class free cash flow margin, regardless of the price environment. He stressed that the integrated business model is crucial, as past midstream investments provided the flow assurance necessary to achieve upstream production and cash flow. EVP G. Gregg Krug added that San Mateo's 99% runtime provides critical operational reliability.

John Freeman of Raymond James Financial asked if, in a hypothetical lower-for-longer oil price environment, more growth capital might be shifted towards the midstream business rather than drilling.

Answer

EVP and CFO William Lambert responded that the company's primary goal is to deliver best-in-class free cash flow margin, regardless of commodity prices. He emphasized that the integrated business model, where midstream provides crucial flow assurance, allows them to achieve this. EVP G. Gregg Krug added that San Mateo's 99% runtime is a key component of this strategy, ensuring production can reach the market.

John Freeman of Raymond James questioned the company's decision to increase its hedging activity, specifically asking about the rationale for locking in wider natural gas basis differentials for 2026.

Answer

Gregg Krug, EVP of Marketing and Midstream Strategy, explained that the company is constantly monitoring hedges and saw an opportunity to layer some on. He cited concerns about potential capacity issues in 2026 and stated the decision was driven by a desire for an 'extra protection insurance policy' against that vulnerability.

John Freeman of Raymond James inquired about the potential levers Matador can pull to continue lowering D&C costs per foot, such as expanding the use of Trimul-Frac or adopting e-fleets.

Answer

Christopher Calvert, EVP and COO, attributed the recent 8% cost reduction primarily to operational efficiencies, including the successful implementation of Trimul-Frac and remote frac operations. He anticipates further gains in 2025 through increased remote operations and continued drilling time reductions. Glenn Stetson, EVP of Production, also noted that using produced water for hydraulic fracturing is another key cost-saving measure.

John Freeman from Raymond James requested clarification on the updated 2025 development plan, specifically the mix of oil versus gas wells turned-in-line, and asked if factors beyond project returns, such as delineation needs, would influence the 2026 capital allocation given the strong outlook for natural gas.

Answer

EVP and CFO David Sproule confirmed that pulling a gas project forward would alter the previously guided 60-40 oil/gas split, driven by superior near-term returns for gas. He elaborated that while gas returns are currently 'frothy,' the company will still execute on some oil projects due to factors like sunk pad costs and the need to maintain operational flexibility across their balanced portfolio.

John Freeman of Raymond James requested clarification on the planned 2025 production mix given the shift to more gas development. He also asked if factors other than commodity prices, such as Utica delineation, might influence the 2026 development mix away from a heavy gas weighting.

Answer

EVP and CFO David Sproule explained that the shift reflects pulling forward a gas pad, displacing a planned oil project, with all decisions based on discounted returns on investment (DROI) secured with hedges. Sproule noted that while 2026 gas returns look strong, the company will maintain flexibility, as some oil projects remain attractive due to long laterals and previously incurred costs, but investors should anticipate further gas development.

John Freeman asked about the lower-than-expected Q4 D&C CapEx, the spending cadence for 2025, and the company's willingness to increase its focus on natural gas assets given current market returns.

Answer

CFO David Sproule clarified that Q4 activity was actually higher than some models predicted, with more wells completed. CEO Zack Arnold added that 2025 CapEx will be front-loaded due to running two rigs before dropping to one later in the year. Regarding asset allocation, Arnold emphasized that while they constantly evaluate opportunities, they are committed to their balanced program, leveraging their operational readiness in both oil and gas plays.

John Freeman inquired about the lower-than-expected Q4 D&C CapEx, the cadence of capital spending for 2025, and the company's willingness to increase its allocation to natural gas assets given the current commodity strip.

Answer

CFO David Sproule clarified that Q4 activity was actually higher than some models predicted, with more wells completed. CEO Zack Arnold explained that 2025 CapEx will be front-loaded due to running two rigs in H1 before dropping to one. He affirmed that while the company continuously evaluates accelerating gas projects, the current plan remains balanced, supported by a deep bench of ready-to-drill projects in both oil and gas plays.

John Freeman of Raymond James inquired about well spacing optimization in the Utica play and asked about the company's current stance on potential asset divestitures.

Answer

SVP, Exploration and Production, Keith Trasko explained that well spacing in the Utica is not a one-size-fits-all approach and continues to be optimized based on local geology, generally within a 600-1,000 foot range. CEO Ezra Yacob stated that while EOG continuously reviews its portfolio, it has already been active in high-grading assets through divestitures over the past decade.