Matthew Portillo

Matthew Portillo asked about Devon's Bakken program, specifically how the shift of capital to Grayson acreage might change the mix of three- and four-mile lateral development, and the implications for the asset base's breakeven.

Answer

John Raines, SVP of E&P Asset Management, noted that while 2025 averaged 2-mile laterals in the Williston, 2026 will average closer to 3-mile laterals, with the introduction of 4-mile laterals (the first 4-mile pad is currently being drilled). He confirmed that longer laterals enhance economics and significantly reduce breakevens for the programs.

Matthew Portillo inquired about Devon Energy's Bakken program, specifically how the shift to Grayson acreage might change the mix of three- and four-mile lateral development and its impact on asset base break-evens.

Answer

SVP of E&P Asset Management John Raines noted that 2025 Bakken lateral lengths averaged around 2 miles. For 2026, the average will be closer to 3 miles, with the introduction of 4-mile laterals (first pad currently drilling). He confirmed that longer laterals enhance economics and significantly reduce break-evens.

Matthew Portillo asked for confirmation of the Bakken capital budget for 2025 and inquired about cost savings achieved since the Grayson acquisition. He also questioned if the seemingly elevated capital in the Powder River Basin could be a lever for reductions in 2026.

Answer

SVP, Asset Management John Raines confirmed the Rockies well count was on track. SVP, E&P Operations Tom Hellman detailed significant post-acquisition savings in the Williston, including a 15% reduction in drill costs and 8% in completion costs. Regarding the Powder River, John Raines explained the capital is focused on appraising the Niobrara. President and CEO Clay Gaspar added that upfront infrastructure investments are impacting current costs but are key to driving long-term well costs down significantly.

Matthew Portillo of TPH&Co. requested an update on inventory depth in the Anadarko Basin and asked for details on the Permian program, specifically the allocation to the Wolfcamp B zone and its impact on the basin's oil cut.

Answer

COO Clay Gaspar explained the Anadarko program currently relies on the Dow JV to compete economically. SVP John Raines specified that the Wolfcamp B co-development will increase from ~10% of the Delaware program in 2024 to ~30% in 2025, while the basin's overall oil mix will remain consistent year-over-year at just under 47%.

Matthew Portillo from TPH asked about the significant shift in Gulf Coast natural gas supply-demand balances, inquiring about changing demand dynamics and any shifts in contract tenor or pricing for offtake agreements with LNG players, utilities, or industrial consumers in Louisiana and Texas. He also questioned Expand Energy's productivity trends in the Haynesville over the next few years, contrasting them with industry trends of accelerating rig counts in East Texas and degradation in core basin well results.

Answer

Mike Wichterich, Chairman of the Board and Interim President and CEO, noted the Gulf Coast's activity and gas-on-gas demand, with end-use customers seeking proximity to the wellhead. Dan Turco, EVP of Marketing and Commercial, highlighted 25 Bcf/day of U.S. gas demand coming online, with half from LNG in their Haynesville backyard, and observed a strong demand for security of supply, especially with challenges in interstate pipeline capacity between Texas and Louisiana. Josh Viets, EVP and COO, asserted Expand Energy's unmatched Haynesville inventory depth and quality, combined with 15+ years of operational history, leads to superior break-evens and productivity. He cited adding 5 years of inventory below $3.50 break-even in one year and referenced slide 30 for outperformance, attributing success to temperature management, optimized sand sourcing, and improved decline parameters.

Matthew Portillo inquired about the evolving demand dynamics on the Gulf Coast, shifts in contract tenor and pricing for offtake agreements, and Expand Energy's Haynesville productivity trends compared to the broader industry.

Answer

Mike Wichterich, Chairman of the Board and Interim President and CEO of Expand Energy, highlighted high activity on the Gulf Coast with end-use customers seeking proximity to the wellhead. Dan Turco, EVP of Marketing and Commercial, detailed 25 Bcf/day of new U.S. gas demand, with half from LNG on the Gulf Coast, driving demand for supply security. Josh Viets, EVP and COO, emphasized Expand's unmatched Haynesville inventory quality and depth, operational excellence, and superior rig performance, attributing productivity gains to managing temperature and optimizing sand sourcing.

Matthew Portillo asked about the medium-term evolution of gas demand in Texas, Louisiana, and Arizona, and if downstream counterparties recognize the value of long-term supply contracts. He also inquired about the company's view on mid-cycle gas prices, particularly for the Hanzo basin, and the $4.50 gas price target for maximizing free cash flow.

Answer

CEO Nick Dell'Osso discussed growing demand in key U.S. submarkets, highlighting the Lake Charles Methanol transaction as a case study for securing long-term, low-carbon supply. EVP of Marketing and Commercial Dan Turco added insights on the supply-demand dynamics in South Louisiana. Nick Dell'Osso clarified that the company is currently focused on mid-cycle prices around $3.75, acknowledging potential for higher prices but emphasizing a measured approach due to market volatility and conservative demand growth forecasts.

Matthew Portillo asked about the Permian production mix, specifically the reasons for a lower oil cut, and whether it would improve. He also inquired about the company's strategy for water handling and disposal in the basin.

Answer

President, U.S. Onshore, Richard Jackson, confirmed the oil cut is expected to increase in the second half of the year, attributing the current mix to the strategic development of secondary benches to reuse infrastructure. On water management, he highlighted a proactive strategy involving well placement, partnerships, and recycling technology to manage costs effectively.

Matthew Portillo from TPH&Co asked for more color on the successful Dimock Box wells, including the number of additional locations and development timing. He also inquired about views on power demand growth and infrastructure opportunities in Northeast Pennsylvania.

Answer

CEO Thomas Jorden confirmed the Dimock Box wells are 'truly phenomenal' and that Coterra will be drilling there for the 'next year or two,' but did not provide specific well counts. Regarding Northeast PA, Jorden and EVP Blake Sirgo noted the power growth opportunity is real and exciting, but any long-term commitment would require a differentiated price structure, not just in-basin pricing.

Matthew Portillo of TPH&Co. asked for an update on the maintenance capital required to hold oil volumes flat over a multi-year period. He also questioned how the returns in the Anadarko Basin compare to the Permian program in the current strip price environment.

Answer

SVP of Business Units Michael Deshazer estimated that holding the 2025 oil volume of 160 MBo/d flat would require around $1.5-1.6 billion in capital for the Anadarko and Permian. Chairman, CEO and President Thomas Jorden noted that at a 15:1 oil-to-gas ratio or lower, the returns across all three basins become a very competitive 'horse race'.

Matthew Portillo asked for the new return threshold for the Upper Marcellus given cost improvements, and requested detail on the number of wells and zone split for the 2025 drilling program.

Answer

Chairman, CEO and President Thomas Jorden maintained the return threshold in the mid-$3s for gas, emphasizing that investment resiliency against price drops is as important as the headline return. He declined to provide specific well counts or splits for the 2025 program, stating it was more detail than would be productive given the multiple pivot points available.

Matthew Portillo asked about the drivers of strong Q3 gas volumes in the Permian and the impact of the Matterhorn pipeline. He also sought clarity on the operational plan for new Marcellus wells and the timeline to ramp up activity if prices improve.

Answer

Blake Sirgo, SVP of Operations, attributed the Permian gas growth to higher-than-expected gas-oil ratios (GOR), not operational changes, and noted Matterhorn primarily improves pricing on Waha-exposed gas. For the Marcellus, he confirmed new wells are dewatered and then managed as part of a field-wide, month-to-month curtailment program. He emphasized they have 'shovel-ready' projects and can respond quickly to price signals.

Asked asset-level questions about the Bakken, focusing on learnings from the Ajax well spacing and the potential for 3-mile developments, and about the Texas Delaware play's development status and well cost progression.

Answer

In the Bakken, the Ajax 3-mile laterals show significant cost savings and encouraging early production. The Texas Delaware play has moved into the development phase, with a plan for longer laterals and costs trending positively as the company gains more experience and leverages expertise from its Oklahoma team.