Jacob Roberts

Jacob Roberts asked about the power capital guidance in the context of Slide 25, questioning if it's influenced by the number or scale of potential PPAs, or geographical distance from Temple. He also sought a longer-term view on gas marketing, including the structure of Barnett takeaway contracts and the strategy to shift volumes to more valuable hubs like Katy and Ship Channel.

Answer

CEO Chris Kalnin clarified that Slide 25 highlights Temple's attractiveness for data center development due to proximity, buildable land, and grid connectivity. He emphasized that closer proximity to generation assets optimizes CapEx and addresses grid congestion for large-scale interconnections. President of Upstream Eric Jacobsen detailed current gas distribution (40% NGPL TexOk, 30% Houston/Katy Ship, 30% Transco) and noted that expiring firm contracts in 2-3 years will provide flexibility to access various markets, including power plants, industrials, and LNG expansion. CFO David Tameron added that BKV actively manages this to achieve the 'highest dollar per molecule' and will provide more marketing strategy details in 6-9 months.

Jacob Roberts asked if the power capital guidance, particularly in the context of slide 25, is influenced by the number of potential PPAs, the scale of agreements, or geographical distance from Temple. He also sought a longer-term view on gas marketing, specifically the structure of Barnett takeaway contracts and the ability to shift volumes to more valuable hubs like Katy and Ship Channel.

Answer

Chris Kalnin, CEO, explained that slide 25 illustrates activity around Temple driven by generation assets, grid interconnectivity, proximity to fiber/data centers, and a favorable building environment. He emphasized that closer proximity to generation assets optimizes CapEx and mitigates grid congestion for large-scale interconnections. Eric Jacobsen, President of Upstream, detailed current gas allocations and noted that expiring firm contracts over the next 2-3 years will provide flexibility to access multiple markets, including power plants, industrials, and LNG expansion. David Tameron, CFO, added that BKV is actively managing marketing efforts to achieve the 'highest dollar per molecule' and will provide more details in the coming months.

Jacob Roberts of TPH & Co. asked about the competitiveness of the Bedrock acquisition process and which factors are most important for future M&A. He also inquired if the liquids composition of the Bedrock assets is similar to BKV's legacy portfolio.

Answer

CEO Chris Kalnin revealed the Bedrock deal was a bilateral discussion, aided by Bedrock's interest in becoming a BKV shareholder. President of Upstream Eric Jacobsen added that for future deals, achieving accretive economics via BKV's playbook is the most critical factor. He also confirmed the Bedrock assets have a slightly higher and richer liquids content compared to BKV's existing assets.

Jacob Roberts asked for details on the Comstock CCUS partnership, specifically the differences in developing a project at an operational plant versus one under construction. He also requested commentary on the macroeconomic conditions mentioned in the prepared remarks and their specific impact on the power business.

Answer

President of Upstream Eric Jacobsen clarified that the Comstock projects will be developed in a phased approach, with BKV handling CO2 capture, compression, and sequestration for a fee as Comstock grows its production. CEO Christopher Kalnin addressed the macro question, explaining that inflation increases the cost of new power generation, which supports higher power prices, while the trend of onshoring data centers and industrial capacity is bullish for power demand in Texas.

Jacob Roberts asked about BKV's CCUS expansion strategy, inquiring about regulatory and geologic factors in target areas and whether a potential JV would be a blanket or project-by-project deal. He also asked if the company would consider power M&A outside of ERCOT and if such investments would require a carbon offset component.

Answer

President of Upstream Eric Jacobsen noted that key states for CCUS expansion have favorable geology and regulatory frameworks. CEO Christopher Kalnin clarified that a potential JV would be a platform-level deal, not project-specific. Kalnin also confirmed BKV is actively looking at power assets outside of ERCOT and can cater to customers who require decarbonized power as well as those who prioritize speed to market, pricing each offering accordingly.

Jacob Roberts inquired about the planned capital allocation between restimulations (refracs) and new horizontal wells for 2025, and asked if a higher mix of refracs would meaningfully shift production decline rates or lease operating expenses (LOE).

Answer

COO Eric Jacobsen explained that refracs are a pivotal part of their program and typically constitute 20-25% of development capital spending. He noted that refracs have a slightly higher first-year decline rate (mid-50% range) than new wells (45%) but still contribute to the company's overall low-decline asset base. He also stated that refracs help lower LOE on a per-unit basis by increasing overall production volumes.

Jacob Roberts asked about Range Resources' outlook on service costs for 2027 and beyond, and whether the company would convert DUC backlog into a deferred approach if costs rise, or accelerate market entry for better pricing. He also sought clarification on the scalability of the recently signed $75 million supply agreement and potential for future projects with the same counterparty.

Answer

CEO Dennis Degner confirmed flexibility in turn-in-line timing and well mix, noting that 2026 service costs show low to mid-single-digit relief, with multi-year agreements providing stability. He expects service costs to stabilize, with future savings potentially funding growth or reducing capital. Mr. Degner affirmed the $75 million supply agreement is scalable and the counterparty is high-quality, setting a strong foundation for future margin-enhancing deals.

Jacob Roberts asked about Range Resources' outlook on service costs for the 2027+ timeframe and whether the company would consider deferring DUC backlog conversion if service costs were expected to rise, potentially allowing for quicker market entry during better pricing scenarios. He also inquired if the recently signed $75 million supply agreement for the Midwest power plant was a starting point, with potential for volume growth, and if the counterparty would be pursued for additional projects.

Answer

CEO Dennis Degner confirmed that Range has significant flexibility in timing turn-in-lines, and service costs for 2026 are expected to be flat to slightly lower, with multi-year agreements providing stability. He noted that costs are approaching an 'asymptotic trend,' with future savings likely coming from operational efficiencies rather than further cost reductions. Mr. Degner affirmed that the $75 million supply agreement is indeed a starting point, with scalability at the site and in the region, aligning with transport capacity starting in 2027. He also confirmed it's a high-quality counterparty, setting a strong foundation for future growth-enhancing deals.

Jacob Roberts inquired about the impact of geopolitical news and tariffs on Range Resources' macroeconomic outlook, particularly concerning the LPG trade, and asked for details on their pricing floors and premiums to Mont Belvieu.

Answer

CEO Dennis Degner explained that Range's business is resilient due to its diversified transport and pricing mechanisms. He stated that while the market will efficiently redistribute barrels, Range's East Coast export access provides a distinct advantage. Degner noted that 80% of Range's LPG exports currently go to Europe, mitigating direct exposure to China, and he expects the company's strong premium to Mont Belvieu to continue.

Jacob Roberts asked for details on new gas takeaway agreements, including cost comparisons and the destination mix, and inquired about the capital spending cadence for 2026-2027.

Answer

CEO Dennis Degner stated the new transport agreements are similar in cost and structure to the existing portfolio, with a slight weighting toward the Midwest but maintaining significant Gulf Coast access. He also clarified that capital spending will remain consistent, with a greater allocation shifting towards completions in 2026 and 2027 to activate the growing DUC inventory.

Jacob Roberts asked for details on the incremental land spend, including what is being acquired and how it enhances the near-term opportunity set beyond just extending the inventory life. He also inquired about the company's approach to managing its remaining 2025 notes.

Answer

CEO Dennis Degner explained the land spend targets unique open parcels that enable lateral extensions, adding the company's most capital-efficient wells and improving the use of existing gathering infrastructure. CFO Mark Scucchi addressed the debt, stating that Range has significant flexibility with its 2025 notes. Options include using cash on hand, the revolving credit facility, or potentially refinancing to optimize interest expense, given the favorable market conditions.

Jacob Roberts asked about the moderate year-on-year decrease in the lateral-adjusted IP rate for Western Haynesville wells shown on Slide 17 and inquired about the expected or underwritten EUR across the Western Haynesville. Jacob Roberts then followed up, asking about the legacy basin's productivity, noting a step down in 2025 vintages based on state data, and requested views on Louisiana productivity per foot in 2025 and its trajectory into 2026 and 2027.

Answer

Dan Harrison, COO, explained that the company has made an effort to control drawdowns more, not pulling wells as hard, so the IP rate should not be interpreted as a trend. He stated that Western Haynesville EURs generally range from 3-4 Bcf per 1,000 feet of lateral, with 3.5 Bcf being a good average. He also mentioned that core samples from pilot holes support resource estimates and are helping to refine lateral targeting. Dan Harrison acknowledged some degradation in productivity across the entire legacy basin due to infill drilling and operators moving to lower type curve areas. However, he expects Comstock's productivity to improve with the drilling of more Horseshoe wells in better type curve areas. Jay Allison, Chairman and CEO, added that these Horseshoe wells offer excellent economics.

Jacob Roberts asked about the moderate year-on-year decrease in the Western Haynesville's lateral-adjusted IP rate, seeking an explanation for this dynamic and Comstock's expected or underwriting EUR across the play. He also inquired about Comstock's views on Louisiana's productivity per foot in 2025 for the legacy side of the basin, and its projected trend for 2026 and 2027.

Answer

Chief Operating Officer Dan Harrison clarified that the IP rate is managed by controlling drawdowns, as wells are capable of higher rates but are flowed back to optimize long-term performance, so the IP rate trend should not be over-interpreted. He noted that core samples support resource estimates and that learnings from cores are improving lateral targeting. Chairman and CEO Jay Allison added that core data now guides optimal lateral landing. Dan Harrison acknowledged a natural degradation in productivity across the legacy basin due to infill drilling, but expects Comstock's productivity to remain flat or slightly improve in 2026 due to Horseshoe wells in better type curve areas. Jay Allison highlighted the economic sense of drilling Horseshoe wells with an added rig.

Jacob Roberts of Tudor, Pickering, Holt & Co. asked about the 2026 capital allocation strategy, including the potential to outspend cash flow for growth and the price point for reducing activity. He also asked for the timeline to obtain conclusive data from choke management experiments.

Answer

President/CFO Roland Burns indicated it was early for 2026 guidance but stated the company does not plan to outspend cash flow and will remain flexible with activity levels based on price. For choke management, COO Daniel Harrison explained that it requires a long timeline, with a minimum of one year and potentially 18-24 months, to get definitive answers on the optimal drawdown strategy, though they gather clues along the way.

Jacob Roberts of Tudor, Pickering, Holt & Co. asked about the company's 2026 capital allocation strategy, specifically whether they would outspend cash flow for growth at higher gas prices. He also inquired about the timeline required to gather sufficient data from choke management tests in the Western Haynesville to determine an optimal strategy.

Answer

President and CFO Roland Burns indicated it is early for 2026 plans but stated he does not foresee a scenario where the company would outspend cash flow, preferring to maintain flexibility and adjust activity to market conditions. On choke management, COO Daniel Harrison explained it is a long-term evaluation, requiring a minimum of a year, and potentially 18-24 months, to fully understand the impact on well performance and finalize an optimal drawdown strategy.

Jacob Roberts asked about the long-term rig count the Western Haynesville could support if gas prices cooperate and whether the company has a specific growth target. He also asked about the Olajuwon well's expected flow rate versus its initial production (IP) rate.

Answer

CEO Miles Allison responded that the company will prudently develop the asset and will not oversupply the market, aiming to meet new demand from data centers and LNG. He highlighted the potential for 12 Bcf of new gas demand and positioned the Western Haynesville as a key source. COO Daniel Harrison stated the Olajuwon well will be flowed on a similar type curve to other core wells, with no midstream constraints affecting its flow rate.

Jacob Roberts of TPH & Co. inquired if the planned 4-rig program in the Western Haynesville is sufficient to meet all HBP and MVC needs with their midstream partner, or if a ramp-up would be needed. He also asked about the extent of seismic and historical data used to understand the play.

Answer

President & CFO Roland Burns stated that the current activity level is very comfortable and sufficient to meet all commitments without getting overextended. COO Daniel Harrison explained that extensive 3D seismic data has been crucial for planning and that the company plans to drill future pilot holes and conduct coring to gather more rock property data.

Jacob Roberts of TPH & Co. inquired about the potential timing of rig additions in 2025 given the current commodity price environment and what constitutes a 'balanced program'. He also asked for an update on the midstream capacity runway in the Western Haynesville.

Answer

President and CFO Roland Burns responded that 2025 rig additions are under evaluation and contingent on winter gas market conditions, with a target of hedging 50% of production to de-risk the program. VP of Finance and IR Ronald Mills added that while current wells will near existing treating capacity, the new Marquee plant coming online will add 400 million cubic feet per day of capacity, providing significant runway for growth.

Jacob Roberts asked about the front-half-weighted capital and turn-in-line (TIL) program and how it translates to a flat production profile, seeking granularity on the TIL schedule quarter-to-quarter. He also inquired about the outlook for AEC pricing in the RMG business line, the pathway to restoring the $65M-$75M annual run rate, and the 45Z outlook, specifically if the $20M-$30M gross-up is tied to steady methane stream volumes.

Answer

Everett Good, Chief Financial Officer, explained that approximately 60% of the year's capital expenditure is front-half-weighted, allowing flexibility for potential frac activity acceleration in the second half, while production remains flat. Alan Shepard, President and Chief Executive Officer, noted that the PA Tier 1 REC market has been stable, with current prices reflecting the marginal cost of new renewable supply. He added that the long-term bull case depends on tightening renewable contribution standards. For 45Z, he confirmed that current production levels can generate about $30 million annually based on initial proposed guidance, pending final guidance.

Jacob Roberts inquired about the front-half-weighted capital and turn-in-line (TIL) program, seeking clarity on how it translates to a flat production profile throughout the year and more granularity on the quarter-to-quarter TIL schedule. He also asked about the outlook for AEC pricing in the RNG business, the pathway to achieving a $65 million to $75 million annual run rate, and whether the 45Z outlook of $20 million grossing up to $30 million is firmly tied to steady methane stream volumes.

Answer

Everett Good, CFO, explained that approximately 60% of the year's total CapEx is allocated to the first half, which supports a flat production profile while providing flexibility to accelerate frac activity in the second half if market conditions improve. Alan Shepard, President and CEO, discussed the PA Tier 1 REC market's stability, noting that long-term price increases depend on step-ups in renewable contribution standards. He confirmed that current production levels are expected to generate about $30 million annually from 45Z, pending final guidance.

Jacob Roberts asked for an update on the performance of the Apex wells that were turned-in-line during the quarter relative to the base business. He also sought clarification on whether the deactivation of the Buchanan power facility on the PJM list would impact CNX's environmental attribute sales segment.

Answer

Chief Operating Officer Navneet Behl stated that the eight wells brought online from the Apex acquisition are producing better than expected. Chief Financial Officer Alan Shepard added that the Buchanan facility's deactivation will have no impact on the company's environmental attribute sales, as CNX utilizes multiple facilities across the PJM Interconnection to create those credits.

Jacob Roberts inquired about the visibility CNX has into the mining plans that determine coal mine methane volumes and whether opportunities exist beyond the Buchanan complex. He also asked about the drivers behind year-over-year changes in gas marketing sales points.

Answer

Ravi Srivastava, President of New Technologies, explained that CNX works closely with mine operators to understand their plans, with volumes primarily coming from the Buchanan mine. CFO Alan Shepard attributed shifts in marketing sales points to routine, daily optimization of the company's firm transportation portfolio, not fundamental changes to contracts.

Jacob Roberts asked if the potential benefits from 45Q and 45V tax credits on CMM volumes are mutually exclusive. He also inquired if the recent stock appreciation has impacted M&A discussions, particularly for opportunities in the New Technology segment.

Answer

Ravi Srivastava, President of New Technologies Group, responded that it is unknown if the 45Q and 45V benefits would be mutually exclusive until final guidance is released. CFO Alan Shepard reiterated that M&A is considered within their standard capital allocation process and declined to comment on specific conversations.

Jacob Roberts asked about the performance of Elastic's federal business beyond the CISA deal, specifically the impact of the government shutdown on Q2 term license revenue and expectations for a catch-up in Q3.

Answer

CEO Ash Kulkarni reported that the overall U.S. public sector performance was strong despite the government shutdown, with demand remaining robust and excellent team execution. He clarified that the CISA deal closed before the shutdown. Ash confirmed that renewals that slipped from Q2 to Q3 due to the shutdown are firm business, not at risk, and are expected to be processed in Q3.

Jacob Roberts asked about the performance of the rest of the federal business beyond the CISA deal and the expected catch-up and size of the impact from the government shutdown on Q2 term licenses.

Answer

CEO Ash Kulkarni described overall U.S. public sector performance as 'great,' despite one less month for closing business due to the shutdown, confirming the CISA deal closed in September. He explained that slipped renewals are firm business, with customers continuing to use the product, and orders are expected to be processed in Q3, not at risk.

Jacob Roberts asked about EQT's assumptions on global LNG supply through 2050 and the cyclicality of the global LNG market. He also inquired about the Deep Utica wells on Olympus assets, specifically their efficiency, cost, and impact on future development thoughts.

Answer

Jeremy Knop (CFO, EQT) acknowledged short-term LNG oversupply risk but expressed long-term bullishness, noting the need for a significant spread to justify new projects and the U.S.'s advantaged position. Toby Rice (President and CEO, EQT) classified the Deep Utica wells as 'early innings' but encouraging, with 30% faster drilling and $2 million per well cost savings, aiming for peer-leading operational records over time.

Jacob Roberts inquired about EQT's outlook on global LNG supply and cyclicality through 2050, and the performance of the two Deep Utica wells on the Olympus assets.

Answer

Jeremy Knop, CFO, expressed bullishness on the long-term LNG setup, noting that the required spread for new projects will need to widen with increasing costs, and the U.S. is advantaged as a supply source. Toby Rice, President and CEO, described the Olympus Deep Utica wells as 'early innings' but encouraging, with 30% faster drilling times and $2 million per well cost savings, setting the stage for future operational records.

Jacob Roberts asked for the drivers behind the increased third-party revenue guidance and whether this new forecast represents an upper limit. As a follow-up on M&A, he questioned if the limited opportunity set for deals applies only to integrated assets or if EQT would consider acquiring pure-play midstream businesses.

Answer

CFO Jeremy Knop explained the change in third-party revenue guidance was primarily an accounting reallocation to align with Equitrans's historical reporting, not a fundamental business change. On M&A, Knop reiterated that EQT's edge lies in integrating upstream and midstream assets, as seen with Equitrans. While open-minded, he expressed skepticism about achieving similar synergies with pure-play midstream assets, stating it's hard to envision such an opportunity at this time.

Jacob Roberts from TPH & Co. requested a risk assessment of the 2025 maintenance capital budget, specifically concerning its relationship with new compression projects. He also asked if lower Q4 midstream spending was deferred or eliminated.

Answer

President and CEO Toby Rice explained that the compression plans are based on normal project management scheduling and risk assessment, with a good level of comfort based on pilot projects, and he does not anticipate significant flex. CFO Jeremy Knop stated the Q4 midstream underspend was 'a little bit of both' deferred and permanently eliminated.

Jacob Roberts sought clarity on the 2025 production outlook, asking if the guided 2,100 Bcfe level (net of sales) implies a decline from the current run rate of approximately 2,400 Bcfe (excluding shut-ins). He also asked if the non-operated asset sale would impact operating expense guidance.

Answer

CFO Jeremy Knop clarified that year-over-year production on the remaining asset base is expected to be 'relatively flat' in 2025. He also confirmed that the non-operated asset divestiture is not expected to cause any material changes to the company's operating expense profile.

Jacob Roberts circled back to the Kage pad, asking about potential future well design changes in the area and whether the company had anticipated such strong results. He followed up by asking if more activity would have been directed there if the results were foreseen, or if that would require a better oil price environment.

Answer

EVP and COO Matthew Rucker stated that they continuously refine well designs and will apply learnings from the Kage pad's long-term performance to future wells. President and CEO John Reinhart added that while the condensate wells are economically attractive, the company's focus for 2026 is leaning more toward dry and wet gas development given the favorable macro environment for gas, rather than prioritizing liquids-focused drilling.

Jacob Roberts asked about the company's flexibility to shift its production mix between liquids and gas based on forward curves and whether operational efficiencies would continue with the move into new areas like the Marcellus.

Answer

EVP and CFO Michael Hodges affirmed the company's flexibility to pivot its capital allocation within a 12-18 month timeframe if a 'sticky change' in commodity prices occurred. President and CEO John Reinhart expressed confidence that operational efficiencies will continue, driven by constant team improvements, and noted that the company continues to break operational records.