John Freeman

Josh Viets confirmed roughly 10 fewer tills this year, happy to float turn-in-lines into 2027 given soft demand.

Mike said approximately 50% from near-term optimization (premium markets and volatility monetization, which are intermingled) and 50% from longer-term demand facilitation (LNG, power, industrial). Near-term category already producing results.

Josh confirmed the heat map framework still drives decisions despite removal from deck. 3-5 year mid-cycle view still central. At current price outlook, 7.5 Bcf per day makes sense. Will be responsive to changing fundamentals as proven in 2024-2025.

Josh confirmed Appalachia upside was from reversing NE curtailments entering Q4, plus some weather-related Haynesville downtime from Winter Storm FERN ice in late January. Full year still expected to average approximately 7.5 Bcf per day.

Mike rejected the characterization, saying all-of-the-above including LNG, manufacturing, and power. Chasing margin downstream. Need to be more aggressive because it is a super competitive space requiring hustle to get in the room.

Nick confirmed continued debt prioritization into 2026 but noted they did both in 2025, $1.2 billion debt reduction and $850 million shareholder returns. Has financial flexibility to allocate to shareholder returns in size when timing is right. More specific answers forthcoming as market conditions develop.

Josh explained Northeast Appalachia bears the brunt of seasonal curtailments due to demand weakness. Q3 and Q4 curtailments predominantly in Northeast. This is the primary driver of the CapEx reduction, not efficiency gains.

Nick and Chris Ayres explained the chart colors are relative rankings, not absolute values. Absolute free cash flow has increased but relative optimization across price levels has not shifted enough to change the heat map coloring. The $4/7.5 Bcf light green corresponds to approximately $3.1 billion 2026 free cash flow.

Josh confirmed full year guidance includes Q2 performance levels plus a modest additional learning curve improvement going forward.

Nick confirmed no incremental infrastructure spending needed. NG3 pipe capital fully spent with online expected year-end. Open to future opportunities like NG3 if attractive.

Josh confirmed all synergy components are in place and performing. Team now focused on executing the full drilling program to realize aggregate dollar targets.

Josh quantified 55-60 deferred TILs and 50-60 DUCs remaining at year-end after 25 TILs brought online in Q4. DUC activation assumed ratable across 2025.

Josh confirmed no major infrastructure step-change needed to grow from 7.5 to 8+ Bcf/day, as combined entity is restoring volumes to pre-existing infrastructure capacity.

Ben quantified captured savings across Permian, Egypt and North Sea and the interest-expense savings component.

Ben reaffirmed the at-least-60% return commitment and flagged heavier second-half buybacks.

Christmann said gas price was geared to $75-80 Brent inclusive of infrastructure, and many discoveries required minimal infrastructure. Program staying ~50/50. Riney added they are agnostic between gas and oil at mid-cycle and actual marginal gas price on new volumes is higher than the $4.25 average.

Christmann emphasized unprecedented times, commitment to 60% returns framework (71% cumulative since inception). Rodgers noted 75%+ returned to shareholders since Q4 2021, $3.2B in buybacks, $3.6B debt reduction. Being patient on deployment mix given conflict volatility. Decom raised $20M for additional Gulf wells.

Riney estimated roughly 1/3 each: virtually no weather downtime, earlier TILs cleaning up faster than expected, and phenomenal improvement in underlying run time. Christmann noted workover rigs got both holidays off because run times were so good.

Riney confirmed continued progress: end of 2025 shallow wells under $500/ft in Midland and under $700/ft in Delaware. Declined to give exact 2026 breakdown by basin on the call, directed to follow-up with IR team.

Christmann cited G&A and Permian capital as two main drivers. Went from $60M in-year in February to $300M now. Rodgers added: incremental $50-100M for 2026 will come primarily from G&A and LOE rather than capital.

Christmann said 2026 will be a light exploration year. Potential for building ice roads in Alaska late next winter and possible Suriname exploration wells late in year, but overall light.

Rodgers said 3-5 years at mid-cycle pricing, potentially 1-2 years if prices are higher. Plan is through organic FCF generation with 40% of FCF directed to debt reduction. No intention to use further divestitures.

Christmann provided extensive context on 3 decades of oil focus now pivoting to gas. Henderson outlined prospective Paleozoic plays in western acreage, AG Basin gas targets, and underexplored eastern acreage. Riney noted they can now pursue best prospects regardless of hydrocarbon type.

Christmann confirmed they believe 6 rigs can hold production flat and expects to sustain that well into 2026 based on further efficiency gains.

Christmann confirmed savings are being pulled forward and expects the $350M target will be raised at a later date. In-year capture went from $60M to $130M.

Clay said gross potential exceeds $1B but they will hold the target until synergies flow through the financials, emphasizing credibility and transparency.

Clay confirmed flywheel effect from existing business optimization work should accelerate synergy capture, particularly in production; Trey added tailwinds from AI and data-driven culture carry through.

John Raines confirmed robust ground game continuing; added 100+ net locations since last year predominantly in Delaware; Q1 acquisition capital ~$150M (90% Delaware) including lease sale wins.

Clay said target unchanged but culture shift means wins beyond $1B are expected; optimization is now permanent operating philosophy, not a program with an end date.

John described comprehensive water strategy: 25-40% to recycle, WaterBridge JV, super system in NM, strategic third-party offloads.

Jeff said no power purchase agreement yet but it's an option; Devon hasn't fully electrified Texas facilities so demand is lower.

Clay said reinvestment rate is monitored but not the singular budgeting target; capital allocation within assets is primary.

Clay explained trades are ongoing ground game focused ahead of drill bit; real $250M swing from original budget after accounting for speed gains.

Jeff said gas upside comes from associated gas; oil projects remain highest-return priority across basins.

Danny framed a realistic path toward 24-hour pumping and 5,000 feet/day, with equipment-redundancy trade-offs.

Starting at ~200 DUCs, drawing down then backfilling. Need high-hundreds/~200 DUC carry for 5 frac crews (1.5 quarters ahead per crew). Adding 20-30 wells for year within original guidance.

CEO pivoted from reinvestment rate target to capital efficiency as priority. Keeping 5th frac crew running consistently vs letting it go ensures efficiency. Learning from basin history.

Danny said continuous pumping removes the biggest NPT (well swapping), enabling shorter stage testing at no extra cost. Kaes noted tangential benefits beyond raw footage improvement.

Danny explained casing reprices quarterly on an index; tubing procured at longer lead times opportunistically. Section 232 tariff relief needed for casing inflation to reverse; activity levels are the swing factor.

Kaes was supportive of technology developments while noting Diamondback's Slide 9 shows they are both a cost AND technical leader in basin development.

Kaes confirmed the $70+ threshold for re-acceleration regardless of cost improvements, emphasizing patience given supply and demand uncertainty.

Danny and Travis credited drilling execution and expected service cost deflation as the primary offsets to tariff-driven casing inflation.

Kaes identified $60M midstream CapEx from EDS and $60-70M of one-time environmental CapEx, both expected to decline.

Keith explained spacing varies 600-1000 feet depending on geology. Southern areas with thinner pay but better frac barriers may support wider spacing. Continuously incorporating new data rather than using set designs.

Ezra confirmed ongoing portfolio review and noted active divestiture history over the past decade. Suggested portfolio is already well high-graded without committing to specific plans.