Michael Scialla

Michael Scialla asked if the potential for adding a frac crew in the second half of 2026, in response to material changes in gas prices, is included in the current capital expenditure guidance range. He also requested more color on the three deep Utica wells turned-in-line for the quarter, specifically regarding cost and production, acknowledging it's early days.

Answer

Everett Good, Chief Financial Officer, confirmed that any uptick in activity, such as adding a frac crew, is not included in the base capital expenditure ranges, as current strip prices (beyond February) do not yet incentivize such additions. Alan Shepard, President and Chief Executive Officer, added that the company would not chase spot activity but would consider additions based on long-term calls associated with new infrastructure or power plants that move the 2027-2029 strip. Navneet Behl, Chief Operating Officer, stated that drilling costs for the deep Utica wells are aligned with guidance at about $1,700 per foot, and performance is in line with expectations. He also mentioned ongoing spacing evaluations at 1,300-foot and 1,500-foot.

Michael Scialla asked if the potential for adding a frac crew in the second half of 2026, in response to gas price changes, is already built into the $20 million CapEx guidance variance for the year. He also requested more color on the three deep Utica wells turned-in-line for the quarter, specifically regarding their cost or production performance, despite being in early stages.

Answer

Everett Good, CFO, clarified that any increased activity is not included in the base CapEx ranges. Alan Shepard, President and CEO, emphasized that the company would not chase spot activity but would consider long-term calls tied to new infrastructure or power plants that would impact the 2027-2029 strip. Navneet Behl, COO, reported that the average Utica drilling cost is about $1,700 per foot, and the performance of the new wells is in line with expectations, with spacing evaluations currently underway.

Michael Scialla asked how rising in-basin demand from AI data centers might affect CNX's long-term natural gas price outlook and hedging strategy. He also inquired about the specific drivers behind the Q2 production outperformance.

Answer

CFO & President Alan Shepard stated that while long-term bullish, potential AI demand does not change their short-term hedging strategy, which remains focused on balance sheet management. CEO Nick DeIuliis emphasized the path to realizing this demand is uncertain, so the company's capital allocation playbook is unchanged. COO Navneet Behl attributed the Q2 production beat to strong new well performance, operational execution, base production efficiency, and high uptime.

Michael Scialla sought details on the Apex acquisition, specifically how the 8,600 net undeveloped Utica acres were calculated from the total acreage. He also asked about the formation of the initial wells to be turned in line and the current performance and costs of CNX's Utica wells.

Answer

CFO Alan Shepard clarified that the 8,600 acres represent the specific Utica rights controlled at acquisition, not rights across the entire 36,000-acre footprint, and confirmed the initial wells are all Marcellus. COO Navneet Behl stated that Utica wells are performing as expected, in line with the 3 Bcf per 1,000 feet target, with Alan Shepard adding that capital efficiency goals are being met.

Michael Scialla questioned if any infrastructure or cost issues would constrain a ramp-up of the deep Utica play if gas prices improve. He also asked for more detail on well costs and whether the play is now economically competitive with the Marcellus.

Answer

CFO Alan Shepard confirmed no near-term constraints exist for a Utica ramp-up, with any decision being a function of price. COO Navneet Behl detailed significant cost reductions, with drilling costs down to ~$750/foot. Both executives affirmed the Utica play is highly prolific and competitive with Marcellus assets.

Michael Scialla requested an update on Range Resources' supply agreement conversations, inquiring if they are limited to Pennsylvania, involve end users or joint ventures, and whether additional takeaway capacity or infrastructure is needed for the three-year plan.

Answer

CEO Dennis Degner stated that conversations are dynamic, primarily focused on Range's producing region in Pennsylvania, with many inbound calls from potential end users. He highlighted positive movement on the Fort Cherry joint venture with Liberty and Imperial, noting state support. Degner confirmed that the disclosed infrastructure additions with MPLX are sufficient for the three-year plan, emphasizing Range's patience for future growth beyond 2027.

Michael Scialla (Stephens Inc) requested an update on Range Resources' ongoing supply agreement conversations, inquiring whether they are limited to Pennsylvania and involve end-users or joint ventures, and also asked about the sufficiency of current takeaway capacity and infrastructure for the company's three-year growth plan.

Answer

CEO Dennis Degner stated that supply agreement discussions are dynamic, primarily focused on the Pennsylvania producing region with potential end-users, and that the Fort Cherry Joint Venture with Liberty and Imperial is progressing. He confirmed that existing infrastructure and disclosed capacity additions, particularly with MPLX, are sufficient for the three-year plan through 2027, with no additional takeaway needed.

Michael Scialla inquired about the specific infrastructure needed for new in-basin demand projects like data centers and whether securing approvals for this infrastructure poses a significant regulatory risk.

Answer

CEO Dennis Degner explained that these projects are being sited near existing infrastructure, requiring only short 'jumper lines' rather than major pipelines. He expressed optimism about the regulatory environment, highlighting strong state-level support for economic growth and citing Pennsylvania's 'Site Act' fund as a positive indicator that these projects will be supported and advanced efficiently.

Michael Scialla inquired about the flexibility to shift production mix and asked for Range's perspective on the long-term demand for LNG amid concerns of a potential oversupply.

Answer

CEO Dennis Degner confirmed the company has flexibility to shift between wet and dry gas development but expressed high confidence in the NGL demand outlook. CFO Mark Scucchi and executive Alan Engberg addressed the LNG question by highlighting Range's diversified end markets, which mitigates risk, and pointed to significant, contract-backed LNG demand growth expected through 2028.

Michael Scialla asked if all of Range's NGLs are exported via Marcus Hook, if there are any capacity constraints there, and if some volumes could be redirected to the Gulf Coast. He also inquired about the driver for raising the low end of the 2024 CapEx guidance.

Answer

Alan Engberg, Manager of Marketing, clarified that the majority of exported NGLs go through Marcus Hook, where Range can export up to 80% of its LPG production. He noted that Marcus Hook has lower capacity utilization than the Gulf Coast, providing room for Range to increase exports. CEO Dennis Degner explained the CapEx guidance was adjusted at the low end to reflect successful land acquisitions that enable longer, more efficient laterals, a spend that was anticipated within the initial budget range for that specific line item.

Michael Scialla from Stephens Inc. sought clarification on the capital plan, asking if pulling a project forward into Q3 implied reduced Q4 activity. He also inquired about the long-term efficiency of operating dedicated rigs in both Ohio and Pennsylvania.

Answer

President and CEO Zach Arnold explained the annual budget is unchanged because drilling costs per foot are nearly identical for gas and oil wells, so shifting the schedule doesn't alter total spend. He confirmed a one-rig program for the year and noted that while a two-rig program offers some efficiency, current rig mobilization between states is already highly efficient.

Michael Scialla from Stephens Inc. questioned the impact of accelerating a project from Q4 to Q3 on the full-year budget and activity cadence, asking if Q4 activity would now be lower. He also inquired about the potential long-term efficiency gains of running dedicated rigs in both Ohio and Pennsylvania versus the current strategy of moving a single rig between plays.

Answer

President and CEO Zach Arnold clarified that pulling a project forward does not change the overall capital need, as the drilling and completion costs per foot for gas and oil wells are nearly identical. He confirmed the company will maintain a one-rig, one-crew program for the rest of the year, with CapEx declining in Q4 as the effects of running two rigs earlier in the year subside. On rig efficiency, Arnold noted that while there are some gains from dedicated rigs, the time spent moving a rig between states is managed efficiently and is not a major drag on the overall schedule.

Michael Scialla of Stephens asked about the current M&A deal flow, land acquisition capex, the planned rig and frac crew cadence for the remainder of the year, and any observed changes in service costs or availability in Appalachia.

Answer

President and CEO Zack Arnold stated that Infinity is active in M&A processes but can be patient due to its strong balance sheet. He clarified that Q1 land capex was for bolt-on activity and that the company would run one rig and one frac crew for the second half of the year after an active Q2 with two frac crews. He also noted that current well economics work well in today's service cost environment, with a focus on operational efficiency gains.

Michael Scialla from Stephens Inc. inquired about the current M&A deal flow, the nature of Q1 land capital expenditures, the planned rig and frac crew cadence for the rest of 2025, and any observed changes in Appalachian service costs or availability.

Answer

President and CEO Zack Arnold stated that the company is very active in M&A processes but remains patient, using its strong balance sheet as an advantage. He characterized the land spending as typical for increasing working interests and lengthening laterals. Arnold clarified that the company dropped to one rig in Q2 but added a second frac crew, with plans to run one rig and one frac crew for the second half of the year, while continuing to seek operational efficiencies with service providers.

Michael Scialla asked for details on the production cadence for 2025 and inquired about the early performance of the five new Marcellus wells that recently came online.

Answer

CEO Zack Arnold detailed the recent well turn-in-lines, including six oil wells in late Q4 and six more wells (one oil, five gas) in early Q1 2025. He noted that with 6-7 month cycle times, production should ramp throughout the year as drilling programs conclude. While declining to give specific well performance, Arnold stated the company is very excited about the early results from the Marcellus pad, which are reflected in the full-year guidance.

Michael Scialla sought clarity on the production cadence for 2025 and asked for early performance indicators on the newly activated Marcellus pad wells.

Answer

CEO Zack Arnold detailed the recent well turn-in-lines from late 2024 and early 2025, noting that production growth will occur throughout the year based on their 6-7 month cycle times. CFO David Sproule added that growth may not be linear but will see jumps as pads come online. Regarding the Marcellus pad, Arnold expressed excitement about the strong early results, which are factored into guidance, but declined to provide specific production figures.

Michael Scialla from Stephens Inc. asked if the expected growth from Jamaica alters the financing strategy for the new-build FSRU, Hull 3407. He also questioned if the lower-than-expected purchase price for the LNG carrier Shenandoah involved any sacrifice in vessel quality or size.

Answer

EVP & CFO Dana Armstrong stated that while financing for Hull 3407 is still being evaluated, the company is in a strong position with over $400 million in cash and an undrawn $500 million revolver, providing ample flexibility. EVP & COO David Liner confirmed there were no compromises on the Shenandoah purchase, stating they acquired the vessel in great condition immediately after its drydocking at a very good price.

Michael Scialla asked for an update on the Vietnam project, specifically what is needed to convert the existing MOUs into binding agreements. He also requested guidance on the cadence of EBITDA for the remainder of the year, given the timing of maintenance and operations expenses.

Answer

CCO Oliver Simpson noted that Vietnam's government is focused on LNG to address its trade deficit, creating momentum, but there were no definitive updates on moving the MOUs with Petrovietnam subsidiaries to binding agreements. CFO Dana Armstrong explained that while some Q1 EBITDA strength was due to cost timing, she reaffirmed the increased full-year guidance. She also confirmed the drydock schedule for the Exemplar in Q3 and the Explorer in Q4.

Michael Scialla of Stephens questioned the rapid completion of the stock repurchase program in the fourth quarter and asked about plans for a new authorization. He also noted that Q4 gas sales were higher than anticipated and sought commentary on the optimization activities during the quarter and the outlook for 2025.

Answer

CEO Steven Kobos expressed satisfaction with the buyback program's effectiveness but stated the primary focus for capital is on growth, though all tools for shareholder returns remain under consideration. CFO Dana Armstrong explained that Q4 gas sales were boosted by two optimization deals and a pull-forward of an Atlantic Basin deal. For 2025, she noted that over 90% of guided EBITDA comes from the core business, with the remainder largely from assumed LNG optimization.

Michael Scialla of Stifel, Nicolaus & Company, Incorporated followed up on 2025 maintenance CapEx, asking for confirmation that it would be higher than 2024, and inquired about potential growth drivers before the newbuild FSRU delivery in mid-2026.

Answer

CFO Dana Armstrong confirmed that 2025 maintenance CapEx is expected to exceed 2024 levels, primarily due to two capitalized dry docks scheduled for the second half of the year. Regarding near-term growth, CEO Steven Kobos and CCO Oliver Simpson stated that while the newbuild and conversions are key long-term projects, the company is actively pursuing inorganic growth opportunities and is in a strong financial position to act on them.

Michael Scialla of Stephens Inc. asked about the potential scale of the 2026 development program, specifically if a four-rig program was possible given the recent acquisitions. He also questioned if the capital mix would shift more heavily towards the operated partnership strategy in the future.

Answer

President and CEO Tyler Farquharson confirmed that a four-rig program in 2026 is definitely possible as the two new partners begin aggregating inventory. He anticipates 2026 CapEx will be similar to or higher than 2025. While the percentage of capital for operated partners might increase, he noted that the non-op business, particularly in Appalachia, will remain a healthy and significant component of their strategy.

Michael Scialla of Stephens Inc. inquired about the potential for the rig count in 2026, given the acquisition strategy, and whether the capital mix between operated partnerships and non-operated assets would shift significantly.

Answer

President and CEO Tyler Farquharson confirmed that a fourth rig in 2026 is definitely possible as new partners begin aggregating inventory. He noted that while the capital percentage for operated partners might increase, the company still sees substantial non-op opportunities, particularly in the Utica, and expects to maintain a healthy non-op component in its capital program.

Michael Scialla of Stephens Inc. questioned the potential for the 2026 rig count to increase to four and how such an increase would affect the capital allocation mix between operated and non-operated assets.

Answer

President and CEO Tyler Farquharson confirmed a four-rig program in 2026 is 'absolutely' possible as new partners begin development. He noted that while the operated capital percentage might increase slightly, the company continues to see strong non-op opportunities, particularly in Appalachia, and expects to maintain a healthy non-op investment component.

Michael Scialla asked for an update on the performance of the Operated Partnership wells, the rig count plan for the year, and the production outlook for the partnership. He also followed up on drilling plans for the Midland Basin partnership.

Answer

CFO Tyler Farquharson stated that Operated Partnerships are expected to comprise about a quarter of 2025 production and that the company continues to target a 25% rate of return. He confirmed they have scaled back from two rigs to one as a prudent measure. Regarding the Midland Basin, he noted that while the plan is to start development in the summer, it is a real-time conversation given market volatility and is one of the easiest projects to defer if necessary.

Michael Scialla inquired about the conditions for spending the contingent $60-$80 million in CapEx, its potential impact on 2026 production, and the company's rig activity, including plans for the Midland Basin.

Answer

Executive Luke Brandenberg confirmed the spending is market-driven, hinging on hydrocarbon pricing and the availability of non-dilutive financing. He noted this spend would significantly boost early 2026 production with negligible impact on 2025. Brandenberg also confirmed the two current rigs are in the Delaware Basin and that Granite Ridge hopes to begin drilling in the Northern Midland Basin around the middle of 2025.

Michael Scialla of Stephens Inc. asked for more details on the Controlled Capital partnerships, including the allocation of drilling locations to the Midland Basin and the factors determining rig timing. He also questioned if the company's production look-back analysis incorporates development timing risk.

Answer

Executive Luke Brandenberg clarified that the Midland Basin currently holds 5-6 net locations, with the focus on building more inventory before deploying a rig, likely in late 2024 or early 2025. He confirmed the production look-back slide does not include timing risk; it strictly compares underwritten well performance against actual results to demonstrate the accuracy of their underwriting process.

Michael Scialla sought confirmation on the preliminary 2026 drilling plan, including rig counts in the San Juan and Anadarko. He also asked about plans for wells from the Sabino acquisition and the reason for an apparent increase in Q2 GP&T costs.

Answer

CEO Tom Ward confirmed the preliminary 2026 plan (3 rigs in San Juan, 2 in Anadarko, 1 in Oswego) is contingent on commodity prices and operating cash flow. He also noted that both Sabino and iCav have wells ready for completion post-closing. CFO Kevin White explained the GP&T cost increase was a reclassification due to a new marketing arrangement, which was neutral to the bottom line as revenues also increased.

Michael Scialla requested a breakdown of the nine operated wells turned to sales in Q1 and asked for expected well costs and recoveries for the new deep Anadarko wells. He also sought more detail on how the production mix could shift in 2026 if the company proceeds with adding a second deep gas rig.

Answer

Executive Tom Ward specified that seven of the Q1 wells were Oswego and two were Woodford condensate. For the deep Anadarko, he stated the first well is currently drilling and they expect to recover 5 Bcf per section with rates of return exceeding 50%, noting the main risk is cost inflation, not geology. For 2026, Ward projected that with the added gas drilling, natural gas production would grow by over 20% while crude oil volumes would decline by less than 10%.

Michael Scialla requested more information on a recent bolt-on acquisition, including the seller's situation, and asked about the factors behind the Q4 distribution being a lower per-unit amount compared to Q3.

Answer

CEO Tom Ward described the seller as a distressed individual from whom Mach acquired wells at a fair PDP PV10 value, inheriting proven undeveloped locations. CFO Kevin White clarified the per-unit distribution was lower because the total cash was shared with new equity holders from a February offering, and that after a required principal payment, all remaining cash was distributed.

Michael Scialla of Stephens Inc. asked about the current market conditions for refinancing the company's term loan. He also questioned what catalysts would be needed for Mach to begin allocating capital to its Cherokee shale assets.

Answer

Executive Tom Ward detailed the complex factors involved in refinancing, including call premiums, covenants, and fees, stating a decision is forthcoming with a focus on eliminating the 2025 amortization. Regarding the Cherokee shale, he explained that capital would only be deployed after other operators further de-risk the play, as its returns do not yet compete with their Ardmore Basin locations.

Michael Scialla of Stephens Inc. questioned if the increased 2025 budget for Suriname milestone payments indicated an accelerated project timeline. He also asked for an update on the Alaska drilling program, specifically the reason for the pause until the 2026-2027 winter season.

Answer

CEO John Christmann clarified that the Suriname budget change is a rephasing of payments and does not alter the overall project timeline for first oil in mid-2028 or the total cost. Regarding Alaska, Christmann and EVP of Exploration Tracey Henderson explained that following the successful Sockeye-2 discovery, the pause is necessary to reprocess and integrate multiple 3D seismic surveys. This work is critical for optimizing the appraisal of Sockeye and prioritizing future exploration targets across their large acreage position.

Michael Scialla of Stephens Inc. inquired about Talos Energy's free cash flow priorities, questioning the balance between strengthening the balance sheet, increasing share buybacks, and preserving capital for acquisitions, given the company's low 0.7x leverage. He also asked for the rationale behind extending the West Vela rig contract.

Answer

President and CEO Paul Goodfellow emphasized the company's disciplined capital framework, which prioritizes maintaining balance sheet strength and optionality for accretive M&A opportunities. He stated the decision to extend the West Vela rig was driven by its outstanding performance and a favorable new rate, aligning with their strategy of executing high-value projects with top-tier partners.

Michael Scialla questioned the visibility for 2026 production given the 12-18 month investment cycle, asked if projects might shift toward natural gas, and inquired about any renewed interest in the Zama project given potential changes in Pemex's ownership.

Answer

President and CEO Paul Goodfellow indicated the 2026 investment program is likely to be in line with current levels, with a funnel of projects being matured. He noted Talos is a liquid-rich company but will pursue robust low-breakeven projects regardless of commodity type. Regarding Zama, Goodfellow stated Talos is happy with its current partnership and will continue working toward a potential investment decision.

Michael Scialla requested details on the specific facilities contributing to the 6,000 BOE/day of planned downtime in 2025. He also asked for an update on the company's efforts to sell down its working interest in the Helm's Deep prospect.

Answer

Interim Co-President and CFO Sergio Maiworm clarified that the downtime is dispersed across several facilities, with the largest impacts from maintenance and tie-in activities at Prince, Tarantula, Brutus, and Pompano. He added that the Helm's Deep sell-down is still in progress and that the next exploration well slot could be Helm's Deep or another prospect pending commercial discussions.

Michael Scialla from Stephens Inc. asked what management believes is holding the stock back, as it continues to trade at a valuation discount to peers despite the simplified corporate structure. He also questioned the decision to pause drilling in the Uinta basin given the strong well results.

Answer

CEO & Director David Rockecharlie responded that the company's job is to continue demonstrating the business's strength through consistent free cash flow generation, strong returns, and operational excellence. Regarding the Uinta, he explained the pause is a prudent step to evaluate the excellent results in a less-developed area to ensure they maximize future value, not an indication of inferior returns compared to the Eagle Ford.

Michael Scialla sought to quantify the activity that shifted from Q1 to later in the year and asked if the move was proactive. He also questioned if the company's activity floor could be zero, similar to its actions during the COVID-19 pandemic.

Answer

Executive Brandi Kendall confirmed the shift was purely due to timing, with a couple of pads moving into Q2, and reaffirmed the full-year capital guide. CEO David Rockecharlie stated unequivocally that the activity floor is zero, highlighting that the business was intentionally built with a low decline rate and HBP acreage to provide the flexibility to halt activity when it makes financial sense.

Michael Scialla asked about the potential upside to the Uinta Basin's 650-location count given the exciting new delineation results, and inquired about the specific path the company envisions to achieve an investment-grade credit rating.

Answer

EVP & COO Clay Rynd stated that while the early delineation results represent pure upside to the location count, it is too early to quantify the increase. CEO David Rockecharlie outlined the path to an investment-grade rating as a two-part strategy: doubling the production scale of the business and simultaneously maintaining investment-grade credit metrics along the way.

Michael Scialla inquired about how long-term views on oil versus gas markets are influencing M&A strategy and asked for details on the recently acquired Central Eagle Ford assets, including development plans and expected savings.

Answer

An executive, Clay, responded that while they evaluate both oil and gas opportunities, the bar for deals is high and the current A&D market is more active in oil. He noted the Central Eagle Ford asset is development-ready, will benefit from the same D&C savings as the broader business, and is expected to be developed starting in 2025.

Michael Scialla asked for an update on Uinta zone delineation, including how many prospective intervals have been tested, and questioned why overall production guidance wasn't raised after a strong Q2 beat.

Answer

EVP & COO Beth McDonald explained that they have production data from all seven lower cube zones and are actively monitoring the upper cube. She clarified that the strong Q2 performance represented a shift of production forward in the year, not an increase in the total annual volume, hence the unchanged full-year guidance.

Michael Scialla inquired about the volume of Uinta oil sold to local refineries, the associated transportation cost savings, and the visibility on non-operated activity for the remainder of the year and its potential impact on CapEx.

Answer

COO Beth McDonald stated that 15-20% of Uinta crude is typically sold to Salt Lake City refineries to capture lower transportation costs, with the volume determined by refinery capacity. She also noted that non-operated activity is expected to continue at a similar rate and is not considered material enough to alter the full-year CapEx guidance.

Michael Scialla inquired about the reasons for lower Q1 production guidance, the status of prior rail delays, and requested a breakdown of the company's increased drilling inventory, specifically asking if Eagle Ford dry gas locations were included.

Answer

COO Beth McDonald clarified that the Q1 production dip was a temporary timing issue due to a 3-month gap in completions after dropping a frac crew, with production expected to grow through Q3. President and CEO Herbert Vogel added that while the Utah acquisition was a major contributor to inventory growth, the company is not providing a detailed breakdown and is not focused on or including its Eagle Ford dry gas assets in current inventory counts.

Michael Scialla of Stephens Inc. inquired about the reasons for lower Q1 production guidance, the status of third-party rail delays, the source of inventory growth, and plans for developing Eagle Ford dry gas assets.

Answer

COO Beth McDonald explained the Q1 production dip was a timing issue due to a temporary gap in South Texas frac crew activity, which has since resumed. CEO Herbert Vogel noted the Utah acquisition was the primary driver of inventory growth and confirmed the company is not focused on developing its dry gas assets at current prices, preferring to maintain its 10+ years of inventory.

Michael Scialla from Stephens Inc. asked about the next steps and expected milestones for the CTV 1 project now that the final Class 6 permit has been secured, on its path to becoming operational.

Answer

CEO Francisco Leon outlined a clear path forward, stating that CRC will break ground on the project in the second quarter of 2025. The work will involve connecting its cryogenic plant to the injector well, with the goal of flowing CO2 and collecting the first CCS-related cash flow by the end of the year. He indicated the next public update would likely be the announcement that construction has commenced.

Michael Scialla asked if the Midway Sunset cogen plant has excess capacity that could be decarbonized and offered to a customer like big tech. He also sought clarity on how much of the excess power at Elk Hills is available for a dedicated customer versus being tied to the grid.

Answer

Francisco Leon (Executive) confirmed CRC has over 850 MW of power generation statewide, using less than half for its own operations, and is evaluating the entire portfolio for decarbonization opportunities. At Elk Hills, he specified that about two-thirds of the 550 MW plant capacity is excess. While it currently serves the grid and resource adequacy programs, the strategic goal is to bring this power 'behind the meter' for a dedicated partner to optimize its value.

Michael Scialla requested a breakdown of the 2025 CapEx budget, specifically how much is allocated to growth, and asked for details on those growth opportunities. He also sought more information on the power generation opportunities covered by the $27 million allocated to Moser.

Answer

An executive reiterated the $115 million total CapEx plan, with $27 million for Moser growth and the remainder split evenly between maintenance and growth for the legacy proppant and logistics business. The Moser capital is aimed at growing the megawatt base from 212 MW to 310 MW by the end of 2026. He highlighted that the overwhelmingly positive customer response to the acquisition is causing them to re-evaluate the business's ultimate growth potential.

Michael Scialla of Stephens Inc. inquired about EQT's 2025 drilling plans in Southwest Pennsylvania, the mix between Marcellus and Utica wells, and the current view on deep Utica returns. He also asked about the Mountain Valley Pipeline's (MVP) utilization.

Answer

President and CEO Toby Rice stated that there are no deep Utica wells planned in Pennsylvania, as the Marcellus remains the best investment opportunity. CFO Jeremy Knop noted the deep Utica represents future upside but is not currently competitive. Regarding MVP, Rice explained it is expected to be a seasonal pipe until further downstream expansions are complete, but its recent high flows at premium prices demonstrate the critical need for the pipeline.

Michael Scialla of Stephens Inc. asked for an explanation of the mechanics and advantages of using remote operations for Simul-Frac and Trimul-Frac completions.

Answer

Christopher Calvert, EVP and COO, explained that remote operations involve connecting two separate well pads with surface infrastructure, allowing a single frac fleet to complete them as one large, continuous job. This engineering solution turns pads that would not be candidates for these efficient completion techniques into ones that are, which has already generated upwards of $20 million in savings on over 90 wells.