Leo Mariani

Leo Mariani sought clarification on the definition of "economic inventory" in the Permian, specifically if the 10% rate of return is a field-level, pre-tax return without corporate burden. He also asked for a rough ballpark percentage for the expected decline in Egypt's gross oil production in 2026.

Answer

President Steve Riney confirmed that the 10% rate of return for economic inventory is a field-level return, including full field costs (like central facilities) but before corporate burden, and is considered both pre-tax and after-tax given current tax circumstances. CEO John Christmann explained that while they've sustained oil volumes with water floods, the shift to 50% gas rigs will lead to a slight decline in gross oil production, though some new gas fields are rich in condensate, contributing to oil volumes.

Leo Mariani of ROTH MKM asked about the outlook for APA's share buyback program in light of softer oil prices and the increased focus on debt paydown. He also sought clarification on the expected decline trajectory for gross oil volumes in Egypt.

Answer

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

Leo Mariani asked for an update on the accounts receivable situation in Egypt and requested a breakdown of the guided $600 million in 2025 purchased oil and gas sales between the Cheniere contract and domestic gas trading.

Answer

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

Leo Mariani questioned the rationale for pulling back on U.S. activity with oil prices around $70 and asked for clarity on Egypt's production outlook, specifically how net oil production could remain flat if gross volumes are declining.

Answer

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

Leo Mariani asked about the cadence of capital expenditures and production for 2026, specifically if CapEx would be front-half weighted and if there would be any Q1 production dip due to storms followed by a Q2 rebound. He also inquired about the focus and achievements related to the $400 million non-D&C spend and the outlook for cash taxes in 2027 and 2028.

Answer

Co-CEO Will Hickey confirmed that production should be flat throughout 2026, with no Q1 dip due to storms, crediting the field team's efforts. He also stated that CapEx would be relatively equally weighted between the first and second halves. Regarding non-D&C spend, Will Hickey noted less deflation compared to D&C, particularly for items like tanks, vessels, and compression. Co-CEO James Walter added that while efficiency gains have been extraordinary on D&C, non-D&C has focused on stemming tariff-driven inflation. CFO Guy Oliphint stated that cash taxes are expected to remain low through 2027, with the company not becoming a full cash taxpayer until 2028 or beyond.

Leo Mariani asked about the 2026 cadence for capital and production, specifically regarding front-half weighted CapEx, any Q1 production dip from storms, and a Q2 rebound. He also inquired about the $400 million non-D&C spend and the outlook for cash taxes.

Answer

Will Hickey, Co-CEO and Director, stated that production should be flat throughout 2026, with no Q1 dip due to storm recovery efforts, and CapEx will be relatively equally weighted. He noted less deflation on non-D&C spend (tanks, vessels, steel compression). Guy Oliphint, EVP and CFO, confirmed low cash taxes for 2026 and 2027, with full cash taxpayer status not expected until 2028 or beyond.

Leo Mariani from Roth Capital Partners, LLC sought clarification on the outlook for well costs in the second half of the year and asked if the company's cautious macro view implies a strategy of holding oil production flat for the foreseeable future.

Answer

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

Leo Mariani requested an update on the company's gas marketing strategy, including potential involvement in data center deals. He also asked for more detail on the claim that returns at $60 oil are comparable to last year's returns at $75 oil.

Answer

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

Leo Mariani from ROTH Capital Partners questioned why the company isn't pursuing more share buybacks given its low valuation and strong cash flow, rather than waiting for a market downturn. He also asked for the specific drivers of the expected reduction in controllable cash costs for 2025.

Answer

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

Leo Mariani asked about the expected activity and CapEx cadence for Q4 and whether the company might reduce its rig count to translate efficiency gains into capital savings.

Answer

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

Leo Mariani asked about the sustainability of Viper Energy's lease bonus income, which saw a significant increase in 2025, and whether 2026 could see similar levels due to new zone development. He also inquired about the trend of Viper's oil cut, which has moved from mid-50s to low-50s, and its contributing factors.

Answer

President Austen Gilfillian expressed optimism that 2026 lease bonus income could be similar to 2025, driven by the deep rights story playing out in both the Midland and Delaware Basins, and proactive management of a larger asset base. CEO Kaes Van't Hof added that automation and AI, particularly from the Sitio team, will enhance lease management. Regarding the oil cut, Mr. Van't Hof explained that the trend reflects broader Permian Basin GORs, with increased efficiency in gas systems and plants leading to dramatic gas and NGL beats, indicating a combination of factors beyond just secondary zone development.

Leo Mariani inquired about the trend of Viper's oil cut moving from mid-50s to low 50s, asking if it's attributable to secondary zone development or increasing GOR.

Answer

Kaes Van't Hof, CEO, attributed the trend to Viper acting as a 'bond for the Permian Basin,' providing insight into basin-wide GOR trends. He cited exposure through Sitio, more efficient gas systems and plants, and dramatic gas and NGL beats as contributing factors, suggesting it's a combination of these elements rather than solely secondary zones.

Leo Mariani sought clarification on the 2026 mid-single-digit growth guidance, specifically whether it was unadjusted for the pending asset sale and how stripping out non-Permian volumes would affect the growth rate. He also asked if investors should expect an acceleration in the variable dividend component as debt is paid off, given the company's lean into buybacks.

Answer

President Austen Gilfillian clarified that the Q4 guidance includes non-Permian assets; stripping out the 5,000 bbl/day contribution from non-Permian assets from the 66,000 bbl/day Q4 midpoint provides the go-forward starting point for 2026, from which a couple thousand barrels of growth leads to mid-single digits. He stated that variable dividend acceleration is 'all price-related,' reiterating that buybacks are the third priority and signal the stock is cheap, but Viper's balance sheet flexibility allows for both buybacks and significant cash distributions.

Leo Mariani of Roth Capital Partners asked about the expected timeline for reaching the net debt target and whether there was room for dividend increases in addition to buybacks. He also inquired about the current M&A environment and the availability of deals.

Answer

CEO & Director Kaes Van’t Hof indicated it is reasonable to expect the board to consider a base dividend increase in the coming quarters. He reaffirmed the plan to return 100% of cash flow once the debt target is hit. On M&A, he reiterated a patient stance, emphasizing the need for investors to realize the benefits from the two recent transformative deals before pursuing new ones.

Leo Mariani of Roth Capital Partners asked about the expected timeline for reaching the net debt target, whether it would occur in 2026, and if there was room for a base dividend increase. He also inquired about the current M&A environment and the availability of deals.

Answer

CEO Kaes Van’t Hof indicated it was reasonable to expect the board to review a base dividend increase in the coming quarters and reaffirmed the plan to return 100% of cash flow once the debt target is met. On M&A, he reiterated a patient stance, emphasizing that the focus is on digesting the two recent transformative deals and ensuring investors benefit from the expected accretion before pursuing further large-scale transactions.

Leo Mariani of ROTH MKM asked if dividends could increase in the coming quarters due to acquisition accretion despite weaker oil prices, and also requested clarification on lower cash tax guidance and G&A expense trends.

Answer

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

Leo Mariani asked about the degree of fragmentation in the minerals landscape and the potential for dividend accretion following the close of the Endeavor-related Drop Down deal.

Answer

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

Leo Mariani sought more clarity on leverage parameters for the Endeavor drop-down, asking about a potential maximum leverage target for Viper. He also questioned the M&A outlook post-drop, asking if Viper would be positioned to pursue other deals in late 2025 and what the current landscape for mineral consolidation looks like.

Answer

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

Leo Mariani revisited the Barnett, asking about the number of wells drilled/completed in 2026, what's needed to hold the position over five years, and if activity will step up in 2027/2028. He also asked about potential capital savings from continuous pumping if frac crews are dropped.

Answer

COO Danny Wesson stated they expect to drill ~30 Barnett wells in 2026, completing ~10, with a significant ramp-up to ~100 wells in 2027 for growth. CEO Kaes Van't Hof confirmed this pace is capital efficient for holding the position. Danny Wesson clarified that continuous pumping won't drive significant cost savings from service providers due to additional equipment, with main benefits being optimized completions, decreased cycle time, and bringing wells forward in the plan.

Leo Mariani asked for a rough estimate of the number of Barnett wells Diamondback plans to drill or complete in 2026, the activity level needed to hold the position over the next five years, and if a significant step-up in activity is expected in 2027-2028. He also inquired about continuous pumping, its potential to drop crews, and whether it could lead to meaningful capital savings.

Answer

COO Danny Wesson stated that Diamondback expects to drill about 30 Barnett wells in 2026, popping closer to 10, with a significant ramp-up to around 100 wells in 2027 to hold the position in a capital-efficient manner. Regarding continuous pumping, Danny Wesson explained that while it requires additional equipment and may not drive significant cost savings from service providers, the big benefit comes from optimizing completions, decreasing cycle times, and improving water out frequency, which positively impacts full-year cycle time and allows for bringing wells forward in the plan.

Leo Mariani asked for commentary on what Diamondback would view as a 'red light' scenario for 2026 in terms of costs and oil prices. He also inquired about other uses of capital in a 'yellow light' scenario, specifically the continuation of healthy buybacks and the potential for bolt-on acquisitions.

Answer

Kaes Van't Hof (CEO, Diamondback Energy) defined a 'red light' scenario as consistently printing months in the $50s or near $50 oil, which would prompt a re-evaluation of capital deferral. He highlighted Diamondback's strong position at $63 oil with a 36-37% reinvestment ratio, secure dividend, strong balance sheet, and low costs. In a 'yellow light' scenario, Kaes Van't Hof stated that the primary use of free cash remains the base dividend, followed by buying back at least 1% of public float per quarter. After that, the focus would be on debt reduction, with ongoing small bolt-on deals and cashless value-accretive trades, while being more selective on big M&A.

Leo Mariani asked for a definition of a 'red light' scenario for 2026 in terms of costs and oil prices. He also inquired about how other uses of capital, beyond the base dividend, might come into play in a 'yellow light' scenario, specifically regarding buybacks and potential bolt-on acquisitions.

Answer

Kaes Van't Hof (CEO, Diamondback Energy) defined a 'red light' as consecutive months printing in the $50s, or near $50 oil, which would prompt a re-evaluation of capital deferral. He highlighted Diamondback's strong position at $63 oil with a 36-37% reinvestment ratio, secure dividend, strong balance sheet, and COVID-low costs. He confirmed the base dividend as primary, followed by buying back at least 1% of public float per quarter. Remaining free cash would go to debt reduction, with continued small bolt-on deals and cashless value-accretive trades. He stated Diamondback would be more selective on big M&A.

Leo Mariani of Roth Capital Partners, LLC inquired about the triggers for a 'red light' scenario to slow activity and asked for a shareholder return framework for FANG similar to the one provided for Viper.

Answer

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

Leo Mariani asked for the drivers behind updated guidance for LOE and transportation costs, and whether the pace of share buybacks would be inversely correlated with oil prices and activity levels.

Answer

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

Leo Mariani sought to quantify the potential D&C and LOE cost synergies from the Double Eagle acquisition, asking for their run-rate well costs. He also asked whether capitalized interest is included in the 2025 capital budget.

Answer

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

Leo Mariani suggested the 2025 production outlook might be conservative given the Q4 run-rate and asked if the company would allow oil production to decline in a weak macro environment. He also inquired about any potential cash tax benefits from the Endeavor deal.

Answer

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

Leo Mariani from Roth Capital Partners asked for a rough timeframe for Expand Energy's goal of achieving a $0.20 uplift on gas, specifically if it's a 5-year goal or potentially shorter. He also sought confirmation on the company's buyback strategy, asking if it primarily focuses on times of stock dislocation and prioritizes strengthening the balance sheet.

Answer

Mike Wichterich, Chairman of the Board and Interim President and CEO, stated that the $0.20 uplift goal is targeted for 3-5 years, with an aggressive hope to achieve it in 3 to 3.5 years. He fully agreed with the characterization of the buyback strategy, confirming that it focuses on times of stock dislocation and prioritizes making the balance sheet "even more rock solid."

Leo Mariani inquired about the rough timeframe for achieving the $0.20 uplift on gas and sought confirmation on Expand Energy's buyback strategy, specifically if it prioritizes balance sheet strength and opportunistic buybacks during stock dislocation.

Answer

Mike Wichterich, Chairman of the Board and Interim President and CEO of Expand Energy, stated the $0.20 uplift is a 3-5 year goal, with an aggressive aim to achieve it in 3-3.5 years. He confirmed that the company's priority is to maintain a rock-solid balance sheet, and buybacks will be opportunistic, primarily occurring during times of stock dislocation.

Leo Mariani sought clarification on the natural gas price threshold ($3+) that would support Antero's growth capital spending, asking if it refers to Henry Hub or an in-basin price. He also inquired about the timing of this capital expenditure and the resulting production ramp. Additionally, he asked about the priority between debt paydown and share buybacks, given the recent increase in leverage.

Answer

Michael Kennedy, CFO and SVP of Finance, clarified that the $3+ threshold is more NYMEX-based, noting that even with a $0.70 back differential, in-basin prices would yield strong returns given Antero's low cost structure. He stated that the growth capital is all second-half, with production ramping in the first half of 2027 due to the 6-9 month cycle. Regarding capital allocation, Mr. Kennedy confirmed that debt paydown is a fair priority at current levels, but Antero would opportunistically pursue buybacks if equity opportunities arise.

Leo Mariani sought clarification on the $3+ gas price threshold for growth capital expenditure, specifically whether it refers to Henry Hub or in-basin pricing, and detailed the expected timing of capital deployment and production ramp if the growth option is exercised. He also asked about the company's priority between debt paydown and share buybacks, given recent leverage changes.

Answer

Michael Kennedy, CEO and President, clarified that the $3+ threshold is primarily NYMEX-based, noting that even mid-$2s in-basin pricing yields strong returns. He confirmed that growth capital would be deployed in the second half of the year, with production ramping up in the first half of 2027. Regarding capital allocation, Michael Kennedy stated that debt paydown is a fair priority at current levels, but the company remains opportunistic regarding equity buybacks.

Leo Mariani asked about Antero's involvement in new in-basin power demand projects, the potential timing of announcements, and the future of shareholder returns, including a possible dividend.

Answer

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

Leo Mariani followed up on the capital return split, noting the Q1 skew towards debt paydown and asking if the 50/50 target is for the full year, implying more room for buybacks. He also asked for more color on Antero's involvement in discussions to supply new in-basin demand projects.

Answer

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

Leo Mariani requested color on the quarterly cadence of CapEx and production in 2025. He also asked for clarification on the drilling JV financial structure, noting a discrepancy between the partner's contribution and the guided D&C budget.

Answer

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

Leo Mariani questioned the outlook for 2025 maintenance capital, asking if the 2024 level of $650 million is a reasonable estimate for flat production. He also asked about the near-term production trajectory given the deferral of some well completions.

Answer

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

Leo Mariani sought more details on the Pinnacle deal, specifically the process of replacing Quantum as a capital partner, whether Quantum would continue contributing capital in the near term, and the timeline for finding a new partner. He also asked about Pinnacle's current debt status and its projected timeline to become free cash flow positive.

Answer

President and CFO Roland Burns stated that the process to replace Quantum with a common capital structure has just begun, with business as usual until then. He expects a new credit facility for Pinnacle to be in place soon, followed by an equity sale to facilitate a full redemption by summer. Roland Burns also indicated that Pinnacle is expected to become free cash flow positive in the second half of 2026, after significant capital expenditures for treating plants like Marquez Train Two, which will provide over 1 Bcf/day capacity and position it for third-party business.

Leo Mariani asked for more details on the Pinnacle deal, specifically about replacing Quantum as a capital partner, the current stage of the process, and whether Quantum would continue to contribute capital in the near term. Leo Mariani then followed up, asking if Pinnacle currently has any debt and if it is expected to become free cash flow positive, requesting color on its cash flow life cycle.

Answer

Roland Burns, President and CFO, explained that the process to replace Quantum's preferred capital structure with common equity has just begun, aiming to allow Pinnacle's cash flow to be used internally rather than for large preferred distributions. He expects a new credit facility to be in place soon, followed by an equity sale for full redemption by summer. Roland Burns further stated that Pinnacle is expected to become free cash flow positive in the second half of the year, after significant capital expenditures for treating plants like Marquez Train Two. He noted that the new credit facility, combined with increased cash flow, should be sufficient to fund future capital needs without further infusions.

Leo Mariani of Daniel Energy Partners asked about the D&C cost difference between horseshoe wells and traditional laterals, questioning if the cost gap could narrow as the company gains more experience with the new technique.

Answer

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

Leo Mariani asked if the strong Q4 well performance was primarily from the 240,000-acre development area or new areas, and how new development areas fit into the existing acreage. He also inquired about the drivers behind the consistently low lease operating expenses (LOE) and expectations for LOE trends in 2026.

Answer

Chris Stavros, Chairman, President, and Chief Executive Officer, confirmed that the strong performance was primarily within the existing 240,000-acre development area, but noted plans for additional appraisal outside this area. Regarding LOE, Mr. Stavros mentioned seasonal increases in Q1 due to weather events and field bonus payments, but expressed confidence in the field teams' ability to continue driving down costs over time.

Leo Mariani asked if the strong Q4 well performance was primarily from the 240,000-acre development area or new areas, and sought insight into the drivers behind the low LOE and its expected trend in 2026.

Answer

Chris Stavros, Chairman, President, and CEO, confirmed that the strong well performance was mainly within the 240,000-acre development area, with plans for additional appraisal outside this area in 2026. Regarding LOE, Mr. Stavros noted that Q1 would see slightly higher costs due to winter weather impacts and seasonal field bonus payments, but credited field teams for impressive cost reductions and expects continued gradual improvement.

Leo Mariani inquired about the 2026 Utica program, noting a lower-than-expected 3 turn-in-lines, and asked if this indicates a change in the company's excitement for the Utica or if it's a timing issue. He also asked about potential operational disruptions or volume impacts in Q1 due to recent cold weather events. Lastly, he sought an update on the new tech business, specifically AutoStep and any CNG/LNG ambitions.

Answer

Alan Shepard, President and Chief Executive Officer, and Navneet Behl, Chief Operating Officer, clarified that the Utica TIL count is purely a timing issue, with no change in confidence, and that 5 Utica laterals will be completed this year. Alan Shepard stated that no operational disruptions or volume impacts are expected in Q1 from the cold weather, as the team prepared, and current numbers include any expected impacts. Regarding new tech, Alan Shepard explained that AutoStep is fully internalized, providing cost savings and environmental benefits, and is being rolled out by an OFS company, with 2026 potentially seeing an uptick, though it's not yet materially contributing financially. Other tech businesses have no material updates.

Leo Mariani asked about the 2026 Utica program, specifically the lower number of three turn-in-lines compared to expectations, given the company's previous excitement and progress in the Utica. He also inquired about potential disruptions to operations or volumes in the first quarter due to recent cold weather events and sought an update on the new tech business, particularly AutoSep's progression and any CNG/LNG ambitions.

Answer

Alan Shepard, President and CEO, clarified that the Utica TIL timing is not indicative of a change in belief in the program, and Navneet Behl, COO, added that five Utica laterals would be completed this year, reaffirming confidence. Alan Shepard also stated that no disruptions to operations or volumes are expected in Q1 due to cold weather, as the team prepared extensively. Regarding new tech, he noted AutoSep is fully internalized for cost savings and outsourced for broader adoption, with 2026 potentially seeing an uptick, but no material updates on other tech or CNG/LNG ambitions.

Leo Mariani asked for more detail on the cadence of drilling, completion, and CapEx in the second half of 2025. He also questioned the performance of the Utica wells, asking about potential for further cost reductions and how production results compare to the Marcellus.

Answer

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

Leo Mariani asked for clarification on the cash taxes paid in Q1, which seemed unexpected, and whether the robust $125 million share buyback indicates management sees the stock as a compelling value. He also inquired about any new information regarding potential changes to the 45Q tax credit under a possible Trump administration.

Answer

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

Leo Mariani questioned the drivers behind the New Technologies free cash flow guidance for 2025 after a strong Q4, the potential impact of the new political administration on CMM initiatives, and sought to confirm the 2025 production strategy involving base volume maintenance alongside modest declines from Apex assets.

Answer

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

Leo Mariani asked for clarification on guidance, specifically why five turn-in-lines were removed from the 2024 schedule. He also sought more detail on the potential value of the 45Q and 45V tax credits and the expected timeline for a decision.

Answer

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

Leo Mariani asked about the ramp-up period for Lac Da Vang, including when its peak production of 10,000-15,000 barrels per day is expected to occur and the nature of its production profile. He also inquired about the expected timing for Hai Su Vang to start contributing materially to production, aiming for the 30,000-50,000 bpd target, and its peak rate. Finally, he asked for an outline of plans for the Morocco entry, including its drill-ready status, seismic analysis, and anticipated expenditures.

Answer

Eric Hambly, President and CEO, and Atif Riaz, VP, Investor Relations and Treasurer, explained that Lac Da Vang is a two-phase development, with first oil from Lac Da Vang A in Q4 2026, and the second platform (Lac Da Vang B) installed in 2028-2029. Peak production is expected in late 2027 or early 2028, with the second platform helping to sustain production. For Hai Su Vang, appraisal concludes mid-2026, followed by a year-long field development plan process, targeting FID by end of 2027. First oil is reasonably expected in 2031 (possibly late 2030), with peak production by 2033. Regarding Morocco, they expressed excitement for the large untested structure and favorable fiscal regime. Existing seismic data will be reprocessed over the next few years, with expenditures around $5 million maximum, and it is not yet drill-ready.

Leo Mariani asked for details on the ramp-up period for the Lac Da Vang development in Vietnam, including when peak production is expected. He also inquired about the expected start of material contributions from Hai Su Vang (HSV) and its timeline to reach the 30,000-50,000 barrels per day target. Lastly, he asked about Murphy Oil's plans for Morocco, including the timeline to become drill-ready and the current stage of analysis.

Answer

Eric Hambly (President and CEO) explained that Lac Da Vang is a two-phase development, with a peak likely in late 2027 or early 2028, reaching 10,000-15,000 net BOE per day. For Hai Su Vang, he projected first oil in 2031 (or potentially late 2030), with peak production by 2033. Regarding Morocco, Hambly stated that existing seismic data would be reprocessed over the next few years, with low expenditures (max $5 million over three years) to assess prospectivity before drilling.

Leo Mariani requested an update on offshore Canada production, specifically the uptime issues at the Terra Nova facility, and asked about the sustainability of the company's new, lower Lease Operating Expense (LOE) guidance of $10-$12 per barrel.

Answer

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

Leo Mariani asked about the capital plan in a 'middle ground' oil price scenario of around $60 and requested more detail on the Q1 offshore Canada production issue and the lease operating expense (LOE) outlook.

Answer

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

Leo Mariani from ROTH Capital Partners asked about the expected increase in offshore Canadian production, questioning if operational improvements at the Terra Nova field were driving better run times. He also sought clarification on the Eagle Ford, asking if the 1,900 BOE/d impact from the failed completion design was due to exceptionally poor well performance and if the 2025 production growth was an anomaly or a new sustainable level.

Answer

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

Leo Mariani questioned the onshore drilling strategy, asking if the accelerated activity in the Eagle Ford would translate to similar early-year growth in the Montney and Duvernay. He also asked for the outlook on workover expenses, which have been elevated in 2024.

Answer

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

Leo Mariani asked for high-level indications of Occidental's expected production growth for 2026, given the $6.3 billion-$6.7 billion capital range, and whether this range implies maintenance or modest growth. He also inquired if the $400 million flex piece, primarily in unconventional Permian, would be the main driver of growth.

Answer

Sunil Mathew, SVP and CFO, indicated that production for 2026 would be flat to potentially up to 2% growth. He confirmed that the growth would be largely driven by unconventional Permian, with Richard Jackson, SVP and COO, reiterating the flexibility to adjust activity based on macro conditions.

Leo Mariani requested high-level indications of Occidental's expected production for 2026, given the projected $6.3 billion-$6.7 billion capital range, asking if this represents a maintenance level or modest growth. He also inquired about the specific unconventional areas, particularly the $400 million flex piece in the Permian, that would primarily drive next year's growth.

Answer

Sunil Mathew (SVP and CFO) stated that 2026 production is expected to be flat to potentially up to 2% growth. He confirmed that this growth would be largely driven by the unconventional Permian. Richard Jackson (SVP and COO) added that the capital flexibility allows for prioritizing efficiency to maintain activity, with the option to reduce activity based on macroeconomic conditions.

Leo Mariani from Roth MKM questioned if the 2025 CapEx and OpEx cuts would have a modest production impact in the next 1-2 years. He also asked for clarity on the full-year chemicals guidance, given the first-half outlook and economic uncertainty.

Answer

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

Leo Mariani asked whether a potential change in the U.S. administration would alter Occidental's strategy for its low-carbon ventures (LCV) business over the next four years.

Answer

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

Leo Mariani asked about Matador's flexibility in adjusting plans, the variables considered, and specifically how the oil macro (e.g., oversupplied market, lower oil prices) influences capital spending decisions, including if there's a price level that would lead to reduced growth.

Answer

Chris Calvert, EVP and COO, and Joseph Foran, Founder, Chairman and CEO, reiterated that capital decisions are multi-variable, not solely dependent on oil price. They emphasized the optionality to reduce activity if commodity prices slide and costs don't decrease proportionally. They highlighted the importance of efficiency gains (e.g., saving $100,000 per day by reducing days on well) and the company's strong balance sheet and midstream business as factors enabling flexibility and long-term value creation.

Leo Mariani of Roth Capital Partners inquired about the allocation of free cash flow, particularly the balance between the 'brick-by-brick' M&A strategy and the newly active share repurchase program, and whether buybacks would be price-sensitive.

Answer

EVP & CFO William Lambert outlined the priorities for free cash flow after the dividend as: 1) brick-by-brick land acquisitions, 2) share repurchases, and 3) debt reduction. He emphasized a flexible, non-formulaic approach to capitalize on opportunities as they arise, using buybacks during periods of market volatility. Co-President Bryan Erman added that the brick-by-brick approach is a core strength and competitive advantage for Matador.

Leo Mariani from Roth Capital Partners, LLC inquired about the allocation of free cash flow, particularly how the company balances its 'brick-by-brick' acquisition strategy with its new share repurchase program.

Answer

EVP and CFO William Lambert outlined a three-pronged approach for free cash flow after the dividend: reinvesting in inventory through 'brick-by-brick' acquisitions, executing share repurchases opportunistically, and managing the balance sheet by paying down debt. He stated there is no set formula. Co-President Bryan Erman added that the brick-by-brick approach is a core competitive advantage for Matador.

Leo Mariani from Roth Capital Partners asked about the allocation of free cash flow, particularly how the company balances its 'brick-by-brick' acquisition strategy with its new share repurchase program.

Answer

EVP and CFO William Lambert outlined a flexible capital allocation framework for free cash flow after the dividend. The priorities are: 1) 'brick-by-brick' land acquisitions, 2) opportunistic share repurchases under the $400 million authorization, and 3) balance sheet management. He stressed there is no set formula, allowing the company to capitalize on land deals and market volatility. Co-President Bryan Erman reiterated that the 'brick-by-brick' program is a core competitive advantage.

Leo Mariani of Roth Capital Partners, LLC asked about the allocation of free cash flow, particularly how the company balances its 'brick-by-brick' M&A program with its new share repurchase initiative.

Answer

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

Leo Mariani of ROTH MKM asked for the rationale behind shifting drilling activity towards West Texas and away from other assets, and questioned if Q2 production would represent the peak for the year.

Answer

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

Leo Mariani from ROTH MKM inquired about potential plans to unlock the value of Matador's midstream business, valued at over $1.5 billion, and asked for the outlook on infrastructure CapEx for 2025.

Answer

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

Questioned the significant production ramp needed to meet H2 guidance, sought clarification on the initial production from Bayswater, asked about the oil cut in guidance, CapEx cadence, and the reason for the low realized NGL price.

Answer

The production ramp in H2 is driven by turning 35 new wells online, with most concentrated in Q3 and Q4. The previously announced Bayswater production number was based on a 12/1 effective date. The oil cut is ~50%. The low NGL price is a result of the company's specific weighted average accounting methodology.

Leo Mariani of Roth Capital Partners, LLC sought clarification on several items, including the previously announced Bayswater production rate, the significant production ramp implied by H2 guidance, the expected oil cut, CapEx cadence, and the quarter's low NGL pricing.

Answer

Co-Founder, Chairman & CEO, Edward Kovalik, clarified that the previously announced production number was based on a 12/1 effective date. He explained the H2 production ramp is driven by turning 35 wells online, with activity concentrated in Q3 and Q4. He guided to a ~50% oil cut and ~75% total liquids. Regarding NGL pricing, Kovalik noted the reported $8.7/bbl was a result of the company's weighted-average accounting methodology.

Leo Mariani of Roth Capital Partners asked about EOG's strategic approach, including potential for bolt-on M&A, during a potentially weaker near-term oil market. He also sought clarification on the company's near-term outlook for the natural gas macro environment.

Answer

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

Leo Mariani requested a comparison of investment returns between the Dorado gas play at $4 gas and core oil plays at $55 oil. He also asked about the timing of the $200 million CapEx reduction, its potential production impact in 2026, and the company's tariff exposure in 2026.

Answer

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

Leo Mariani of ROTH MKM questioned the rationale for reducing activity in the Eagle Ford shale and asked about the status and focus of EOG's domestic oil exploration program for 2025.

Answer

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

Leo Mariani sought clarification on the Utica play, asking about the potential to lower the stated $6-$8 per BOE finding cost and how it relates to a previously disclosed $5 target. He also requested an update on the Powder River Basin's (PRB) performance and future activity levels.

Answer

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

Leo Mariani of Roth Capital Partners, LLC asked for the production mix of the Anadarko asset sale and the rationale for increasing the overall divestiture target at this time.

Answer

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

Leo Mariani requested more specific details on the $500 million capital budget cut, including the types of activities, locations, and any potential medium-term production impact.

Answer

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

Leo Mariani of ROTH MKM asked for more detail on the $600 million divestiture, specifically the associated production volume and commodity mix of the non-core Permian assets being sold.

Answer

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

Leo Mariani asked for specific quantification of expected turnarounds, CapEx, and OpEx for the fourth quarter.

Answer

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

Leo Mariani from Roth Capital Partners, LLC requested more detail on recent Wolfcamp B well results in the Midland Basin. He also asked for an assessment of the company's inventory quality and depth across its DJ, Delaware, and Midland basin assets.

Answer

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

Leo Mariani sought more color on the DJ Basin, questioning the reasons for the significant Q1 volume decline and the flat Q2 guidance, and asked about the production trend for the second half of the year. He also inquired if Civitas is seeing any cost relief from oilfield service providers at the local basin level.

Answer

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

Leo Mariani questioned the company's appetite for further Permian M&A given the competitive market and asked about the drivers behind the increase in Lease Operating Expense (LOE) during the fourth quarter.

Answer

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

Leo Mariani sought more specific detail on the maintenance rig count, asking if a 2-rig DJ and 4-rig Permian program was accurate. He also asked why Civitas finds the Wolfcamp D competitive when other operators have deemed it less economic.

Answer

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

Leo Mariani of Roth Capital Partners, LLC requested more quantitative detail on the Franklin Mountain and Avant acquisitions, asking how recent well results and costs have trended compared to the prior operator and initial expectations.

Answer

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

Leo Mariani asked for quantification of the development runway in the Marcellus's Dimmit box and how returns compare between the Permian and Lower Marcellus at current commodity prices.

Answer

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

Leo Mariani asked if Coterra's three-year capital expenditure outlook is now biased lower due to recent efficiency gains and requested a more detailed explanation of the company's M&A strategy.

Answer

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

Leo Mariani inquired about the specifics of the $75 million increase in the capital budget, the nature of the added wells, and the drivers behind the Uinta Basin's strong well performance and cost trends.

Answer

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

Questioned the 2025 plan to complete significantly more wells than are drilled, asking if this was to draw down DUC inventory and if drilling would need to increase in 2026. He also asked for an explanation for the variance in Uinta's Q4 production and LOE compared to the figures discussed at the time of the acquisition.

Answer

The company explained that the high DUC count was an outcome of the acquired asset's activity and that the 2025 plan will reduce it, but they don't manage to a specific DUC target. Future drilling needs will depend on pad sizes. The Q4 Uinta variance was attributed to it being a 'noisy' integration quarter with limited operational control. They emphasized that the asset's cash margin per barrel is in line with the Midland Basin, meeting their expectations.

Leo Mariani of Roth MKM questioned the 2025 plan to complete significantly more wells than drilled, the resulting DUC inventory drawdown, and the variance in Uinta's Q4 production and LOE compared to initial acquisition estimates.

Answer

COO Beth McDonald clarified that the DUC count, which will be reduced by about 45%, is an output of activity timing, influenced by the pace of drilling at the acquired Utah asset. CEO Herbert Vogel noted that Q4 was a noisy transitional quarter for Uinta, with limited operational control. CFO Wade Pursell added that despite the noise, the Uinta cash production margin was strong and comparable to the Midland Basin, as anticipated.

Leo Mariani questioned the 2025 plan to complete significantly more wells than drilled, implying a DUC drawdown, and asked about variances in Uinta Basin's Q4 performance, such as lower production and higher LOE, compared to initial acquisition projections.

Answer

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

Leo P. Mariani of ROTH MKM asked for an explanation for the Q2 production guidance, which implies a decline steeper than the company's typical rate. He also requested a specific update on the status and timeline of the Kern County Environmental Impact Report (EIR) for oil and gas permitting.

Answer

President and CEO Francisco Leon clarified the Q2 BOE decline is a strategic decision to optimize cash flow, not an indicator of asset performance. By altering power plant operations, CRC reduces low-value gas sales to lower overall OpEx. On permitting, he noted the Kern County EIR process is ongoing, but CRC is pursuing multiple successful avenues for permits and has a constructive dialogue with regulators.

Leo Mariani from ROTH MKM questioned the significant improvement in capital efficiency, pointing out that the guided second-half 2025 CapEx with two rigs appeared similar to the fourth-quarter 2024 spend with only one rig, and asked for the drivers behind this change.

Answer

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

Leo Mariani asked for an update on the drilling permit situation with CalGEM and whether any new permits were being issued. He also inquired about the legislative progress on CO2 pipeline regulations in California.

Answer

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

Leo Mariani asked about the 2025 CapEx budget being lower than previously indicated, whether this signals a philosophical shift, and its potential impact on 2026 production. He also inquired about accelerating the share buyback program and the acquisition cost for the increased working interest in the Monument project.

Answer

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

Leo Mariani asked for quantification of third-quarter storm-related downtime, an estimate for fourth-quarter downtime, and whether 2025 capital expenditures are expected to increase due to rig activity.

Answer

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

Leo Mariani of ROTH MKM questioned the accounting of the $5 million fee from Project Drake, the effectiveness of cost-saving measures given rising operating expenses, and the specifics of the new infrastructure partnership model.

Answer

CFO Geoff Trukenbrod clarified the $5 million from Project Drake is an exclusivity fee expected to be recognized as incremental revenue in Q4, separate from the base business. CEO Jennifer Holmgren and CFO Trukenbrod explained that rising costs are due to upfront project development expenses for projects like Drake, which are expensed now but will be recouped upon transfer to partners. Holmgren also confirmed a completed JV with Olayan Group and discussions with other infrastructure partners beyond Brookfield.

Leo Mariani inquired about the revenue recognition for the $5 million fee from Project Drake, the reasons for rising operating costs despite stated cost-saving initiatives, and specifics of the new infrastructure partnership model.

Answer

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

Leo Mariani questioned the significant revenue ramp required in the second half of 2024 to meet guidance and asked for details on the Q1 increase in operating costs compared to Q4 2023.

Answer

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

Leo Mariani asked about the outlook for share buybacks as free cash flow is expected to increase. He also inquired about quantifying recent D&C cost efficiencies and the current outlook for leading-edge oilfield service costs.

Answer

CFO Mark Scucchi confirmed that with the balance sheet in its target range, Range has greater latitude for capital returns and views share buybacks as a very compelling option given the stock's valuation. CEO Dennis Degner addressed costs, stating that while it's early in the RFP process, they have seen some relief in consumables but resilience in rig rates. He emphasized that regardless of service costs, operational efficiencies like achieving 9-10 frac stages per day allow the company to maintain production with a single frac crew.