Noah Hungness

Noah Hungness inquired about Kimbell Royalty Partners' natural gas and NGL realizations, crude differentials for 2026, the impact of the Waha price inflection in 2027, and whether Woodford Barnett activity will primarily boost production or lease bonus revenue, also asking about lease status.

Answer

COO Matt Daly detailed that oil differentials were flat at 2% (Q3-Q4), natural gas differentials increased from 18% (Q3) to 24% (Q4) due to seasonality, and NGLs were flat. He expects Waha takeaway capacity to improve long-term gas differentials. President and CFO Davis Ravnaas noted that over 85% of gas production is outside Waha, and expressed excitement for Woodford Barnett delineation driving production growth at no cost, with almost all acreage being Held By Production (HBP).

Noah Hungness inquired about Kimbell Royalty Partners' natural gas, NGL, and crude oil realizations for 2026, the anticipated impact of the Waha price inflection in 2027, and the potential for production growth versus lease bonus revenue from Woodford Barnett development.

Answer

COO Matt Daly detailed Q4 2025 realizations: oil differential flat at 2%, natural gas at 24% (up from 18% in Q3), and NGLs flat quarter-over-quarter, noting seasonal gas differential increases in Q4/Q1. President and CFO Davis Ravnaas and Mr. Daly confirmed the Waha price inflection should significantly improve differentials, with over 85% of Kimbell's gas production outside Waha. Mr. Ravnaas emphasized that Woodford Barnett development is primarily a production growth story, with most acreage being HBP, and highlighted the mineral owner advantage of not incurring exploration costs.

Noah Hungness of Bank of America Merrill Lynch questioned how the M&A market and valuations are adapting to a less certain growth environment in the Permian. He also asked for color on what drove G&A expenses significantly lower in the quarter and whether that level is sustainable.

Answer

President and CFO R. Davis Ravnaas explained that the M&A market is adjusting, as sellers still seek growth-based multiples while buyers see a flatter environment, suggesting valuations may need to decline over time. COO Matthew Daly added that the lower G&A was primarily due to reduced professional fees and advised analysts to model costs at the lower end of the existing guidance range for the remainder of the year.

Noah Hungness asked about the drivers behind strong Q1 NGL and natural gas realizations and the expected trend for the rest of 2025. He also requested a real-time update on the net DUC (drilled but uncompleted) well count since the end of the quarter.

Answer

Davis Ravnaas, President and CFO, advised using Q1's strong realization numbers as a 'goalpost' for the year, noting the improvement was broad-based across all basins. Regarding DUCs, Matthew Daly, COO, stated the latest disclosed figure was 4.67 net DUCs as of March 31. Mr. Ravnaas added that calculating this is a time-intensive quarterly process and that overall activity remains solid, with no indication of a slowdown.

Noah Hungness asked about the strategy for paying down the remaining preferred shares after the initial redemption in May and questioned the drivers for the lower 'marketing and other' expense guidance for 2025.

Answer

Davis Ravnaas, President and CFO, detailed a plan to use 25% of ongoing cash flow to pay down the revolver, which would then provide capacity for ratable redemptions of the remaining preferreds, a process that could be accelerated by a deleveraging acquisition. Controller Blayne Rhynsburger added that the lower expense guidance reflects a more accurate forecast, noting that prior guidance was likely overly conservative and that these costs fluctuate with commodity prices.

Noah Hungness of Bank of America sought clarification on the timing for when the new high-NRI wells in Loving County would begin contributing to Kimbell's reported results.

Answer

President and CFO Davis Ravnaas, with confirmation from COO Matthew Daly, explained that while the wells are already producing, the company expects to start receiving and reporting the associated production and cash flow in Q4. He added that initial well results have been very encouraging.

Noah Hungness asked if any of Chord Energy's capital activities were affected by Winter Storm Fern in Q1 and what that means for the timing of capital spend through the year.

Answer

CEO Danny Brown confirmed that winter weather in North Dakota impacted some Q1 activity but does not change the overall shape of the capital investment profile, which is still expected to increase through Q3 and pull back in Q4. COO Darrin Henke added that teams did an excellent job recovering production and activity.

Noah Hungness asked about the 2026 decline rate compared to 2025 and the impact of Winter Storm Fern in Q1 on capital activities and the timing of capital spend through the year.

Answer

CEO Danny Brown stated that annual decline rates broadly look similar year-over-year, with a modest, small single-digit percentage shallowing expected longer-term as longer laterals increase their production share. Regarding Winter Storm Fern, Mr. Brown confirmed it impacted some Q1 activity but did not alter the overall capital investment profile for the year, which is still expected to increase through Q3 and pull back in Q4. COO Darrin Henke added that teams did an excellent job recovering production and activity.

Noah Hungness asked if the capital for wells shifted out of 2025 would be spent this year, creating a 2026 production tailwind. He also inquired about Chord's positioning to benefit from new midstream egress projects out of the basin.

Answer

President, CEO & Director Daniel Brown confirmed that a significant portion of the capital is spent in 2025, which will benefit 2026 production, noting this is a normal part of the operational cycle. EVP & CSO Michael Lou added that while Chord has good egress, they support new projects as more options improve long-term differentials and costs, though it is too early to quantify the benefit.

Noah Hungness of Bank of America Merrill Lynch asked if the capital for 15 shifted turn-in-lines (TILs) would largely be spent in 2025, creating a production tailwind for 2026. He also inquired about Chord's positioning to benefit from potential new midstream egress out of the basin.

Answer

CEO Daniel Brown confirmed that a good portion of the capital for those wells is spent in 2025, with the production benefit realized in 2026, noting this is a typical year-end dynamic. On midstream, CSO Michael Lou stated that Chord is in discussion with all parties and would support more egress options, which should lead to better long-term differentials and lower costs, though it is too early to quantify.

Noah Hungness from Bank of America asked for details on the expected oil production cadence for the third and fourth quarters of 2025 and the rationale behind increasing the planned 4-mile lateral spuds from three to seven.

Answer

CEO Daniel Brown projected that oil production would likely drift down in the second half of the year, with Q3 being flattish to Q2, due to the temporary reduction to a single frac crew. COO Darrin Henke added that the confidence to expand the 4-mile program stems from strong initial operational success, with the first few wells being drilled better and faster than anticipated.

Noah Hungness asked if increased midstream competition in the Bakken could lead to lower gathering, processing, and transportation (GP&T) costs for Chord. He also inquired about the amount of natural gas production from the non-op Marcellus position baked into 2025 guidance.

Answer

CEO Daniel Brown and Chief Strategy and Commercial Officer Michael Lou confirmed that the competitive midstream environment is beneficial, and they are always looking for opportunities to improve netbacks as contracts roll off or through win-win renegotiations. Brown stated that the 2025 plan assumes 130-140 million cubic feet per day of gas production from the Marcellus, which Lou added is relatively flat but has upside if gas prices remain strong.

Noah Hungness asked for operational details on the techniques used to successfully deploy coiled tubing to the total depth of extended-reach laterals. He also questioned the timeline for incorporating 3-mile laterals on legacy Enerplus acreage.

Answer

COO Darrin Henke described the coiled tubing success as a competitive advantage stemming from proprietary technical details related to bottom hole assemblies and fluid rates. CEO Daniel Brown explained that while Chord is a firm believer in 3-mile wells, their application on legacy Enerplus acreage will be mixed. Some areas are constrained by existing development, so the 2025 plan will likely include a combination of 2-mile and 3-mile wells on that asset base.

Noah Hungness asked about the $320 million quarter-over-quarter increase in accounts receivable and whether it's expected to unwind in 2026. He also inquired about further upside for average lateral length (11,000 feet in 2026) to reach 2.5 miles and its impact on D&C per foot costs.

Answer

James Walter, Co-CEO and Director, explained that the increase in accounts receivable and payable was correlated with business scaling, keeping working capital constant. Will Hickey, Co-CEO and Director, stated that while existing units are mostly set, new assets will target 2.5-mile laterals, which could reduce D&C per foot by low double digits ($20-25/foot).

Noah Hungness asked about the $320 million quarter-over-quarter increase in accounts receivable and whether it's expected to unwind in 2026. He also inquired about the potential for further upside in average lateral length beyond 11,000 feet, possibly reaching 2.5 miles, and the estimated impact on D&C per foot costs.

Answer

Co-CEO James Walter explained that the increase in accounts receivable and accounts payable (working capital) is correlated with the scaling up of the business, with total working capital remaining relatively constant. Co-CEO Will Hickey stated that while the existing position might offer marginal opportunities for longer laterals, future acquisitions would increasingly target 2.5-mile laterals. He estimated that adding an extra 2,500 feet of lateral length could reduce D&C per foot costs by 'low double digits,' possibly $20-25 per foot.

Noah Hungness of Bank of America Merrill Lynch asked for an explanation of how new rules for commingling on federal lands would impact operations and questioned the source of a $20 million increase in the capital budget, given that well counts were unchanged.

Answer

Co-CEO Will Hickey clarified that commingling allows for building more efficient, centralized tank batteries in New Mexico, saving capital and reducing footprint, but does not unlock stranded acreage. He explained the capital increase was solely due to absorbing costs for eight work-in-progress wells from the recent Apache acquisition.

Noah Hungness from Bank of America asked for the reasoning behind keeping the base dividend flat despite increasing efficiencies and free cash flow capacity. He also inquired about the company's thoughts on implementing creative drilling solutions like U-turn laterals.

Answer

Co-CEO William Hickey explained that since the first enhanced dividend was only paid in November, it was too soon to make another change, but they plan to revisit it annually with the goal of a 'nice increase' next year. Regarding U-turn wells, he stated that while the team is proficient at drilling them with little incremental cost, the company's well-blocked-up land position rarely requires them, so it's not a major part of the program.

Noah Hungness asked about the drivers of low LOE costs and the expected use of free cash flow now that the company's revolver is paid down.

Answer

Co-CEO William Hickey explained that while Q3 LOE was strong, a slight uptick is expected in Q4 due to a recent acquisition, with a medium-term target of $5.50-$5.60 per BOE. Co-CEO James Walter stated that excess free cash flow will be used for accretive acquisitions or opportunistic buybacks; otherwise, the company is content to build cash on the balance sheet to enhance strategic flexibility.

Noah Hungness sought to quantify the potential EBITDA or Free Cash Flow upside from the 'coiled spring' effect, assuming a $65 WTI price, and asked for a breakdown of CapEx between Ground Game spend and standard D&C in the low versus high activity scenarios.

Answer

CEO Nick O'Grady and CTO Jim Evans estimated that every $5 per barrel increase in WTI could generate an additional $100 million to $150 million in annual cash/EBITDA. They noted that in a $65 WTI environment, Free Cash Flow could be similar or even superior in the high activity scenario due to the improved pricing. Evans also stated that the Ground Game spend accounts for approximately $150 million to $200 million of the CapEx difference between the low and high activity scenarios.

Noah Hungness of Bank of America Securities asked for a quantification of the potential EBITDA or free cash flow upside from NOG's 'coiled spring' effect, specifically at a $65 WTI price point. He also inquired about the breakdown of CapEx between Ground Game spend and standard DNC (Drill, Complete, Equip) in both the low and high activity scenarios for 2026.

Answer

CEO Nick O'Grady and CTO Jim Evans estimated that a $5 per barrel increase in WTI could generate an additional $130 million to $150 million in annual cash flow for NOG. They clarified that in a $65 WTI environment, the high activity scenario could yield similar or even superior free cash flow compared to the low activity scenario, despite higher spending, due to the improved pricing. Regarding CapEx allocation, CTO Jim Evans stated that the difference in Ground Game spend between the low and high activity scenarios is approximately $150 million to $200 million.

Noah Hungness asked about the planned use of higher free cash flow under the revised plan, specifically the priority between debt reduction and buybacks, and requested more color on the current M&A market dynamics.

Answer

CEO Nicholas O’Grady outlined the capital use hierarchy as debt reduction (sweeping the revolver), followed by value-accretive inorganic opportunities, and then stock buybacks, positioning the company for counter-cyclical investment. President Adam Dirlam added that the M&A market is robust, with a narrowing bid-ask spread as commodity volatility has settled.

Noah Hungness inquired about the expected production cadence for the remainder of the year and recent trends in service pricing for well development.

Answer

CFO Chad Allen stated that NOG anticipates a flattish production cadence for the first three quarters, with Q2 and early Q3 marking the lowest activity period before a Q4 peak, assuming no major spending pullbacks. President Adam Dirlam added that while operators' plans are currently stable, they could adjust in the second half of the year. Regarding service pricing, Dirlam noted a 10% decrease in normalized well costs was driven by longer laterals, not service cost deflation, and that the company remains conservative on guidance. CTO Jim Evans commented that well costs historically fall with oil prices and that NOG's pre-purchasing of materials has mitigated tariff impacts.

Noah Hungness inquired about the potential impact of steel tariffs on AFE costs and the company's current thinking on share buybacks given recent stock performance.

Answer

CEO Nicholas O'Grady acknowledged tariffs will likely have some upward cost impact but noted the company's conservative budget has wiggle room. Regarding buybacks, he stated that "everything is on the table" and that the topic is a quarterly discussion with the Board of Directors, which will occur in the coming weeks.

Noah Hungness asked for insight into operator well deferrals and how NOG's corporate decline rate has evolved through 2024.

Answer

CEO Nicholas O'Grady and President Adam Dirlam explained that well deferrals are typically seen from private operators sensitive to commodity prices, with activity resuming as the market stabilizes. CFO Chad Allen stated the corporate decline rate began 2024 in the high 30s, has moderated to the mid-30s, and is expected to have a go-forward run rate in the low-to-mid 30s as recent high-decline acquisitions mature.

Noah Hungness of Bank of America inquired about Matador Resources Company's 2% increase in net undrilled lateral footage, asking if it stemmed from delineation or their 'brick by brick' land strategy, and where these location adds occurred. He also questioned significant inventory additions in the Avalon, Third Bone Spring Carbonate, and Wolfcamp D formations, and if the company was observing favorable results from these zones.

Answer

Joe Foran (Founder, Chairman, and CEO) acknowledged the multi-part question. Tom Elsener (EVP of Reservoir Engineering) highlighted strong production from the Avalon, particularly the Gavalon well, noting high oil cuts and significant running room. He attributed the increase in footage to trades and extended laterals, resulting in a 6% increase in average lateral length from 2024 to 2025, including 3.4-mile laterals on Ameredev acreage. Elsener also praised the successful integration of the Third Bone Spring Carbonate into their Delaware Basin inventory.

Noah Hungness asked about Matador Resources' inventory additions, specifically inquiring whether the 2% increase in net undrilled lateral footage was due to delineation or their 'brick by brick' land strategy, and if the company was seeing favorable results from significant inventory adds in the Avalon, Third Bone Spring Carbonate, and Wolfcamp D formations.

Answer

Tom Elsener, EVP for Reservoir Engineering, highlighted strong production from the Avalon, particularly the Gavalon well, noting its high oil cuts and significant running room. He also mentioned a 6% increase in average lateral length due to 3.4-mile laterals on Ameredev acreage and the successful integration of the Third Bone Spring Carbonate into their inventory after successful drilling in the Wolf area, Ranger, and Rustler Breaks.

Noah Hungness from Bank of America Merrill Lynch inquired about the key drivers behind the D&C costs per foot coming in below the guidance range and the sustainability of these cost savings.

Answer

EVP & CFO William Lambert attributed the performance to activity in a lower-cost area of the basin. EVP & COO Christopher Calvert added that the 11% year-over-year cost reduction was primarily due to operational efficiencies, such as faster drilling times for U-turn wells and increased use of trimul-frac completions, rather than service cost deflation. Chairman & CEO Joseph Wm. Foran credited the gains to strong, long-term collaborative relationships with key vendors.

Noah Hungness from Bank of America Merrill Lynch asked about the drivers behind the D&C costs per foot coming in below guidance and queried the sustainability of these cost savings.

Answer

EVP and CFO William Lambert attributed the performance to exemplary results in a lower-cost area of the basin and noted that future guidance only incorporates cycle time efficiencies, not service cost deflation. EVP and COO Christopher Calvert added that costs are down 11% year-over-year due to drilling efficiencies, like shaving 10 days off U-turn wells, and increased use of 'trimmer frac' technology, which saves about $350,000 per well.

Noah Hungness from Bank of America Merrill Lynch asked about the key drivers behind the D&C costs per foot coming in below guidance and whether those drivers are sustainable.

Answer

EVP and CFO William Lambert attributed the performance partly to activity in a lower-cost area of the basin. EVP and COO Christopher Calvert elaborated that costs were down 11% year-over-year, driven by operational efficiencies rather than service cost deflation. He highlighted a 10-day reduction in drilling times for U-turn wells and expanded use of Trimmer Frac technology, which saves approximately $350,000 per well. CEO Joseph Foran credited the success to strong, collaborative vendor relationships.

Noah Hungness of Bank of America Merrill Lynch asked about the drivers behind the company's D&C costs per foot coming in below guidance and how sustainable those cost savings are.

Answer

EVP and COO Christopher Calvert attributed the 11% year-over-year cost reduction primarily to operational efficiencies rather than service cost deflation. He cited faster drilling times for U-turn wells and increased use of the 'trimmer frac' process, which saves approximately $350,000 per well. CEO Joseph Foran added that these gains were achieved through long-term vendor collaboration, not by pressuring suppliers on price.

Noah Hungness asked for clarification on the factors that would push Magnolia's 2026 capital expenditure guidance to either the upper or lower end of the range. He also inquired about the potential impact of strong gas prices during the winter freeze on Q1 gathering, processing, and transportation (GP&T) costs.

Answer

Chris Stavros, Chairman, President, and Chief Executive Officer, expressed confidence in staying at the middle or lower end of the capital range, stating that only significant commodity price increases and service cost inflation would push it higher. He noted that better well performance could lead to lower spending. Brian Corales, Senior Vice President and Chief Financial Officer, anticipated Q1 GP&T to be relatively similar to previous quarters, with only a slight potential increase due to higher gas prices.

Noah Hungness asked about the factors that would push Magnolia's 2026 capital guide to either the upper or lower end of the range, and whether strong gas prices during the winter freeze would translate into higher Q1 GP&T.

Answer

Chris Stavros, Chairman, President, and CEO, stated that capital is expected to be in the middle or lower end of the range, with higher well performance potentially leading to deferrals. He does not anticipate pushing to the upper end unless commodity prices rise significantly and service costs increase. Brian Corales, Senior Vice President and Chief Financial Officer, expected Q1 GP&T to be relatively similar to past quarters, with only a slight potential increase.

Noah Hungness of Bank of America Merrill Lynch asked about the number of well completions being deferred into 2026 and what conditions would prompt the company to pull that activity forward into 2025.

Answer

CEO Christopher Stavros stated that the number of deferred completions remains unchanged at "about a half a dozen." He sees no need to pull them forward into 2025, as the company is already achieving strong 10% production growth with better-than-expected well performance. He indicated that in the current commodity environment, these wells would likely be completed as part of the 2026 program.

Noah Hungness inquired about the number of well completions being deferred into 2026 and the conditions under which the company would consider pulling that activity forward into 2025.

Answer

CEO Christopher Stavros stated that the number of deferred completions remains about a half-dozen. He sees no need to pull them forward into 2025, as current well performance is already exceeding expectations and delivering 10% growth, which is "just fine." He added that in the current commodity environment, those drilled wells would very likely be completed as part of the 2026 program.

Noah Hungness asked about the expected oil cut for the rest of 2025 following the production guidance increase and the outlook for Gathering, Processing & Transportation (GP&T) costs.

Answer

President and CEO Christopher Stavros projected a slight increase in absolute oil volumes but a stable oil cut percentage, remaining around 40-41%. He also explained that GP&T costs generally move in tandem with natural gas prices, so they would be expected to follow the same directional trend as the commodity.

Noah Hungness asked for an update on the M&A opportunity set in the Eagle Ford and inquired about the factors that would influence the capital allocation split between Giddings and Karnes within the guided range.

Answer

President and CEO Christopher Stavros noted that recent M&A opportunities in the Eagle Ford have been of varying quality and have tended to be oilier. He emphasized that Magnolia prioritizes assets that enhance its resource base over simply adding volume. Regarding the CapEx split, he advised not to over-interpret the range, stating it reflects minor timing variations rather than a strategic shift, with no major change expected from the prior year's allocation.

Noah Hungness asked about the M&A market, inquiring if the opportunity set is limited to small bolt-ons or if larger deals exist. He also questioned the rationale for pulling activity forward with efficiency gains instead of taking the CapEx savings.

Answer

President and CEO Christopher Stavros described the M&A opportunity set as "all of the above," including small bolt-ons and larger asset packages, but emphasized a high quality bar for any transaction. Regarding pulling activity forward, he explained that given the soft outlook for product prices, using the modest capital savings to create more operational flexibility and optionality for next year seemed like the better course of action.

Noah Hungness inquired about the potential impact of federal permitting reform bills on regulated pipeline projects and sought details on the DNC costs and expected productivity uplift of Seneca's Gen 4 well design, including for larger Upper Utica frac operations.

Answer

Dave Bauer, President and Chief Executive Officer, stated that permitting reform would primarily accelerate project timelines for both pipeline and renewable industries. Justin Loweth, President of Seneca Resources and National Fuel Midstream, explained that Gen 4 design, with wider spacing and larger completions, adds approximately $150-$175 per foot in DNC costs but is expected to yield significant uplift in IRRs and EUR, with similar cost implications for Upper Utica frac tests.

Noah Hungness from Bank of America inquired about the potential impact of federal permitting reform bills on regulated pipeline projects and asked for details on the DNC costs and expected productivity uplift for Seneca's Gen 4 well design and larger Upper Utica frac.

Answer

Dave Bauer, President and CEO, stated that permitting reform would primarily accelerate project timelines rather than change the company's development view. Justin Loweth, President of Seneca Resources and National Fuel Midstream, estimated Gen 4 design adds $150-$175 per foot in DNC costs, expecting a longer flat production period and higher Estimated Ultimate Recovery (EUR), with similar cost implications for Upper Utica frac.

Noah Hungness of Bank of America Merrill Lynch questioned the company's strategy for securing supply agreements for potential new egress from Northeast Pennsylvania and asked if there is upside risk to the Gen 3 well productivity estimates given recent strong performance.

Answer

Justin Loweth, President of Seneca Resources, confirmed active dialogue on supply agreements, highlighting NFG's 'perfect trifecta' of deep inventory, integrated assets, and financial strength. Regarding well productivity, he acknowledged recent pads are excellent and that the team is testing variables for a potential 'gen beyond Gen 3,' suggesting upside potential exists.

Noah Hungness from Bank of America asked for details on the performance of recent EDA wells, specifically the leading-edge EUR per 1,000 feet or pressure declines, and inquired about the potential for a future 'Gen 4' well design.

Answer

Justin Loweth, President of Seneca Resources and National Fuel Midstream, stated that while it's early, well productivity and pressure declines are exceeding expectations, suggesting an upside bias to the current 2.5 Bcf per 1,000 feet EUR. He confirmed they are already testing variables for a 'Gen 4' design, focusing on interwell spacing and increased proppant loading to further enhance productivity.

Noah Hungness asked about the leading-edge EUR per 1,000 foot for recent EDA tills and the potential for a Gen four well design.

Answer

President of National Fuel Gas Midstream Company Justin Loweth mentioned the EUR expectation of 2.5 Bcf per 1,000 feet and potential gains from adjustments on inner well spacing and profit loading.

Noah Hungness inquired about the progress and potential timing of discussions related to data centers and sought to understand the rationale for increasing production guidance versus maintaining flat production to realize CapEx savings.

Answer

David Bauer, President and CEO, explained that data center discussions are in the early stages but active. Justin Loweth, President of Seneca Resources and National Fuel Midstream, clarified that the production increase is a direct result of outstanding well performance and improved designs, not a strategic shift, and that future growth remains contingent on securing takeaway capacity.

Noah Hungness of Bank of America inquired about the impact of recent election results on the regulatory landscape and the company's comfort with expansion projects. He also asked for the drivers behind the improved fiscal 2025 adjusted EPS outlook, assuming constant natural gas prices.

Answer

President and CEO David Bauer stated that while the company is built to succeed in any political environment, a new federal administration could be beneficial for the energy industry. Treasurer and Principal Financial Officer Timothy Silverstein explained that the primary driver for the improved EPS outlook was a lower DD&A rate following a Q4 impairment, supplemented by minor operational cost tailwinds.

Noah Hungness from Bank of America Merrill Lynch inquired about the company's future growth trajectory, asking if the high growth rate seen this year is sustainable or if management would prefer to moderate it. He also requested more color on the company's plans to explore the credit markets in the fall.

Answer

Tyler Farquharson, President and CEO, responded that production growth is an outcome, not a target, and is balanced against leverage and cash flow. He expects significant growth to continue into 2026, potentially in the mid-teens. Regarding credit markets, he confirmed they are evaluating all options, including increasing the RBL, accessing the traditional high-yield market, or pursuing private credit to term out debt.

Noah Hungness from Bank of America Merrill Lynch inquired about the sustainability of the company's high growth rate and sought details on its plans to explore the credit markets, including potential RBL increases or high-yield debt.

Answer

President and CEO Tyler Farquharson clarified that growth is an outcome of their investment strategy, not a set target. He anticipates strong, potentially mid-teens, growth continuing into 2026. Regarding credit markets, he confirmed they are pursuing a fall RBL increase and are evaluating all options to term out debt, including high-yield bonds and private credit.

Noah Hungness from Bank of America Merrill Lynch asked about the company's future growth trajectory and whether the current 24%+ level is sustainable, and also requested more detail on plans to explore the credit markets.

Answer

President and CEO Tyler Farquharson explained that production growth is an outcome of their strategy, not a fixed target, but he expects strong, possibly mid-teens, growth into 2026 given the current focus on acquisitions. Regarding credit markets, he confirmed they are evaluating all options, including another RBL increase in the fall, as well as terming out debt through the traditional high-yield market or private credit.

Noah Hungness questioned the expected trend for the company's oil cut through the remainder of the year and requested more color on the capital split between traditional non-op wells and the Operated Partnership program.

Answer

Luke Brandenberg, President and CEO, explained that the Q1 oil cut was slightly lower because gas production outperformed expectations while oil production was in line with forecasts. He clarified that the current 60% capital allocation to Operated Partnerships is an output of letting all deals compete for capital, not a predetermined target, which provides significant flexibility to adjust spending based on market conditions.

Noah Hungness from Bank of America questioned the composition of the CapEx guidance (D&C vs. acquisitions) and requested details on the Q4 2024 impairment charge.

Answer

Executive Luke Brandenberg clarified that the CapEx guide includes both D&C and acquisition spend, estimating a long-term split of roughly 75-80% development and 20-25% inventory acquisition. Executive Tyler Farquharson explained the impairment was related to maturing Williston Bakken assets where investment has been low. Brandenberg added that the original deal was profitable, acquired for PDP value with 'free' inventory, and the write-down was on this marginal, unpaid-for inventory.

Noah Hungness inquired about the drivers for the company's lower-than-guided Lease Operating Expense (LOE) and the outlook for this metric. He also asked for details on new leasehold additions in Appalachia, specifically the basin, location, and commodity focus.

Answer

Executive Tyler Farquharson attributed the lower LOE costs to reduced workover expenses and projected that Q4 would remain at the low end of the annual guidance range. Executive Luke Brandenberg explained the Appalachian strategy is focused on the Utica condensate window in Guernsey and Harrison counties, partnering with a local group to acquire unleased minerals in a rich condensate area.

Noah Hungness from Bank of America Merrill Lynch inquired about the production cadence for early 2026, considering the accelerated well turn-in-lines in late 2025. He also asked about the potential pace of future non-core asset sales.

Answer

SVP & COO Katie Hill stated that due to flush production from H2 2025 activity, the company expects to exit Q4 at a high production rate, which will likely decline slightly into early 2026. President & CEO Jason Pigott added that non-core asset sales are opportunistic, aimed at accelerating debt reduction, and will continue if favorable pricing is available.

Noah Hungness from Bank of America Merrill Lynch asked about the production cadence for early 2026 following the H2 2025 well completions and inquired about the future pace of non-core asset sales.

Answer

SVP & COO Katie Hill stated that due to the timing of 38 wells coming online by October 2025, production will exit Q4 at a high point before declining slightly into early 2026. President & CEO Jason Pigott characterized the non-core asset sales as opportunistic, aimed at accelerating debt reduction by monetizing assets not in near-term development plans, rather than following a set pace or goal.

Noah Hungness asked about the production cadence heading into the first half of 2026, considering the plan to bring all second-half 2025 wells online by October. He also questioned the potential pace of future non-core asset sales.

Answer

SVP & COO Katie Hill addressed production, stating that due to flush production from 38 new wells, the company expects to exit Q4 2025 at a high rate, followed by a slight decline into early 2026. President & CEO Jason Pigott responded on asset sales, clarifying that they are opportunistic, aimed at accelerating debt reduction and high-grading the portfolio when favorable market prices are available, rather than following a set cadence.

Noah Hungness asked about the production cadence for early 2026 following the significant well turn-in-lines in late 2025, and questioned the strategy and potential pace of future non-core asset sales.

Answer

SVP & COO Katie Hill stated that due to flush production from 38 new wells, the company expects a high production exit rate in Q4 2025, which will likely see a slight decline into early 2026. President & CEO Jason Pigott added that non-core asset sales are opportunistic, not based on a set schedule, and are pursued when favorable pricing can accelerate the company's primary goal of debt reduction.

Noah Hungness asked about the opportunity to high-grade rigs and completion crews amid potential service pricing weakness. He also questioned the likelihood of further non-cash impairments if oil prices remain at current strip levels and the potential impact on inventory.

Answer

COO Katie Hill confirmed opportunities exist to capture cost efficiencies or high-grade crews, noting a recent rig contract was 20% below the fleet average and all major contracts expire by Q1 2026. CFO Bryan Lemmerman stated that if current prices hold, further non-cash write-downs are likely, referencing a figure in the 10-Q around a couple hundred million dollars for the next quarter, but clarified this is a non-cash calculation that doesn't affect physical reserves.

Noah Hungness questioned the potential impact of steel tariffs on the CapEx budget and asked about the company's decision-making process when choosing between debt paydown and small, bolt-on acquisitions.

Answer

SVP and COO Katie Hill stated that the company is secured on OCTG through most of 2025, resulting in very little exposure to potential tariffs this year. President and CEO Mikell Pigott emphasized that debt paydown is the primary focus for free cash flow, but the company will pursue highly accretive opportunities like the 8-mile project, which feature low-cost, high-return wells. He also noted that extending lateral length is a key strategy for improving inventory quality.

Noah Hungness questioned the company's hedging strategy for the second half of 2025 and 2026, given the sub-$70 oil strip. He also asked for more operational details on specific initiatives planned to achieve further D&C cost reductions.

Answer

CEO Mikell Pigott explained that Vital's hedging strategy remains consistent, aiming to be about 75% hedged and capitalizing on market volatility to add hedges, as they did during a recent geopolitical flare-up. He noted they are currently about two-thirds hedged for 2025. COO Katie Hill added that future D&C cost reductions will come from scrutinizing every service cost, implementing best practices from both basins, and leveraging repeat experience in the Delaware. She expressed high confidence that achieving an additional 5% cost improvement is a matter of 'when, not if.'

Noah Hungness from Bank of America Merrill Lynch followed up on the 2026 outlook, asking if the capital expenditure cadence would be similarly front-half weighted as in 2025. He also requested color on the amount of production currently sidelined by lingering midstream constraints and how quickly that capacity could be restored.

Answer

CEO John Reinhart confirmed that the 2026 capital program is expected to be front-loaded, consistent with prior years, to maximize capital efficiency. He clarified that the vast majority of the recent midstream issues have already been resolved and production restored. The remaining minor constraints are being addressed by midstream partners with projects completing through Q4, and the cumulative impact of these events is what led to guiding toward the low end of the annual production range.

Noah Hungness inquired if the company's cutting-edge drilling and frac efficiencies were already factored into the current 2025 CapEx guidance. He also asked about Gulfport's potential interest in the Borealis pipeline expansion and its general view on signing up for additional firm transportation capacity.

Answer

EVP and COO Matthew Rucker confirmed that average efficiencies from the past year are modeled into the capital guidance, meaning any further improvements represent potential upside. EVP and CFO Michael Hodges stated that they evaluate all pipeline projects on a netback basis and that Gulfport's portfolio of uncommitted volumes provides the flexibility to pursue premium opportunities that improve netbacks.

Noah Hungness sought confirmation that a key takeaway from the company's outlook is its ability to maintain natural gas leverage while growing liquids production. He also asked for the drivers behind the significant upward revision in NGL price realization guidance.

Answer

EVP and CFO Michael Hodges confirmed the company's flexibility to generate strong free cash flow while shifting between gas and liquids. He attributed the higher NGL realization to three factors: an attractive existing Utica barrel from ethane rejection, stronger propane and butane pricing, and favorable terms in the new Marcellus midstream agreement, which also allows for ethane rejection.

Noah Hungness asked if Gulfport's successful discretionary acreage acquisition strategy would continue into 2025 and questioned the drivers behind the widening of oil differentials.

Answer

President and CEO John Reinhart stated that while the company has added significant inventory, its future approach to acreage acquisitions will be 'opportunistic and less programmatic,' with a high bar for new deals. EVP and CFO Michael Hodges explained the wider oil differential guidance was a 'math function' due to back-half weighted production and a declining oil curve, noting that actual month-to-month differentials have remained strong.

Noah Hungness followed up on the 45Z tax credit, asking when CNX expects to reach the $30 million annual run rate and whether the qualifying gas could also be used for PA AEC Tier 1 credits. He also asked about the credit price assumption behind the revised environmental attribute free cash flow guidance.

Answer

CFO & President Alan Shepard clarified that cash from 2025's 45Z credits would be realized in 2026. He stated that initial guidance suggests the programs are stackable, though not all volumes qualify for both. For the environmental FCF guide, Shepard confirmed it's based on current market prices, with the PA Tier 1 strip in the mid-$20s per megawatt-hour.

Noah Hungness asked why CNX's free cash flow guidance remained unchanged despite lower mark-to-market pricing and wider natural gas differentials, seeking to understand the offsetting improvements in the base business. He also inquired about the company's outlook on developing in-basin demand from new power generation and data centers.

Answer

Chief Financial Officer Alan Shepard explained that with 85% of volumes hedged, the impact from price changes on the remaining open volumes is not significant for the full year. He also noted the guidance is a range. On in-basin demand, he expressed a bullish view, stating that while it's uncertain how many announced projects will materialize, the trend is a positive tailwind for all operators in the basin.

Noah Hungness asked for the company's latest thoughts on well spacing for new Utica drill locations and for guidance on how to model cash taxes for 2025.

Answer

COO Navneet Behl stated that current Utica wells are at 1,300-foot spacing, with upcoming tests planned at 1,500 feet. CFO Alan Shepard advised that CNX expects to remain a de minimis cash taxpayer until late 2026 or early 2027, after reaching a cumulative $3 billion in free cash flow.

Noah Hungness inquired about the financial and operational impact of implementing simul-frac operations, specifically on D&C costs per foot, and requested an update on the productivity of leading-edge wells in Borden County compared to legacy wells in Northern Howard County.

Answer

President Michael Hollis detailed that simul-frac operations could cut completion time for a four-well pad in half, yielding approximately $0.25 million in savings per well, or about a $1 per foot reduction in costs. He also highlighted ancillary benefits like reduced offset well downtime and accelerated production timelines. Regarding Borden County, Hollis confirmed that recent well results are strong and consistent with previous wells, which showed a 20% productivity improvement over the prior year.

Noah Hungness requested quantification of the expected decline in per-unit operating expenses (LOE and GP&T) for 2025 and asked about the land spend component of the CapEx budget.

Answer

CFO David Sproule explained that per-unit costs will decline as more low-cost Pennsylvania gas production, which utilizes a wholly-owned midstream system, is blended into the mix, but did not provide a specific number. CEO Zack Arnold clarified that while there is limited need for maintenance land spend, the overall CapEx guidance includes flexibility for opportunistic, high-return deals like adding working interest.

Noah Hungness asked for quantification on the expected decline in per-unit operating expenses (LOE and GP&T) in 2025 and inquired about the outlook for land spending within the CapEx budget.

Answer

CFO David Sproule explained that per-unit costs will decline as more low-cost gas production from their wholly-owned midstream system in Pennsylvania is blended in, but declined to provide a specific number. CEO Zack Arnold added that there is limited need for maintenance land spend in 2025, but the overall CapEx guidance includes flexibility for opportunistic, high-return acreage acquisitions and working interest additions.