DIAMONDBACK ENERGY INC earnings calls

production plans given low inventories

Q (Neal Dingmann · William Blair): Analyst asked if, with low global inventories, the company will keep growing production into 2027 and how they can target high well productivity while maximizing value.

A: Management said they see inventories draining and expect the need to refill them, which biases them toward growing production rather than holding flat. They increased 2026 production by about 3% or 4% versus original plan and currently see low single-digit organic growth while running 5 frac crews. They said technical gains are a series of small improvements that let them maximize wells per section and production per well to generate the most NPV per section.

"So in general, I think that does skew us towards the decision to grow production versus hold production flat." — Kaes Van't Hof (CEO)

gas strategy and power/data center project

Q (Neil Mehta · Goldman Sachs): Analyst asked if improved Waha flows ease egress constraints, the company's gas strategy including LNG and data center power plans, and how they're thinking about return of capital in 2Q and the rest of the year.

A: Management said Waha improving is relief versus Q2 and helps near-term results, and they view gas as a mega theme where Diamondback should own more contracted space to the Gulf Coast for power, data centers, or LNG. They described a specific Bryant Ranch power project that could deliver first gas in the back half of 2027 and said they removed a minimum free-cash return commitment to stay flexible, using buybacks selectively while also cutting net debt by $1.6 billion.

"All of this should allow us to provide a shovel-ready development project, delivering first gas as soon as the back half of 2027 through the use of behind-the-meter recip units." — Jere Thompson (CFO)

why gas outperformed and costs outlook

Q (Scott Hanold · RBC): Analyst asked why natural gas production beat expectations and whether technical targeting or conservative guidance caused it, and then asked about oilfield service cost inflation and a steady-state quarterly capital run rate.

A: Management said the gas outperformance is mainly from improved local marketing, better G&P systems and split connects, reducing flaring and increasing gas sold; technically there was little change in well selection this quarter. On costs, they see limited inflation mainly in consumables and fuel, note all frac fleets are electric which mitigates fuel impact, expect casing prices to rise in the back half of the year by a little over 1% of total well cost, and estimate about "$1 billion to a little over $1 billion a quarter" to hold production flat today.

"The biggest driver has been really an improvement in our ability to market our gas locally." — Daniel Wesson (COO)

Barnett cost reductions and EOR pilot

Q (Arun Jayaram · JPMorgan): Analyst asked for an update on Barnett drilling cost reductions toward $400 a foot and how they will ramp in 2027, and asked for results from the enhanced oil recovery (EOR) pilot and plans to expand it.

A: Management said the Barnett position has been expanded and the first 4-well pad in Spanish Trail has been drilled and will be completed in the next couple of months, expecting consistent drilling closer to $400 a foot. On EOR, they completed a 12-well project with initial results described as very positive, will apply learnings to the next group of wells in Q3, and are moving quickly to test remedial and controlled new-well applications.

"The initial results are very positive." — Albert Barkmann

continuous pumping and small acquisitions

Q (John Freeman · Raymond James): Analyst asked what is achievable for average pumping hours per day (toward 24 hours) and whether recent bolt-on transactions included any production.

A: Management said the team is pushing toward manufacturing-mode completion operations and believes 24 hours is the ultimate goal, but maintenance and redundancy trade-offs matter; they see a next target of 5,000-plus feet per day across crews and think that may be achievable within about a year. On transactions, they said the recent bolt-on deals added very little production but are finding regular $20 million to $100 million deals to net up acreage and extend laterals.

"I think that's kind of the next bogey for us is how do we get to achieving 5,000 feet per day across all of our crews every day." — Daniel Wesson (COO)

mid-cycle NAV and value from power project

Q (Phillip Jungwirth · BMO): Analyst asked how much operational improvements and resource expansions raised mid-cycle NAV and where Diamondback captures value from the shovel-ready power project.

A: Management said operational improvements and M&A since 2021 have materially increased value, citing zones like Barnett that raised NAV from a few hundred million to a couple of billion, and they expect continued value creation from execution. On the power project, they highlighted the main value as a new in-basin egress for natural gas, noted setting aside "$200 to 250 million a day" for the project and potential material uplift from contract structures, and said success could create a repeatable blueprint for more projects.

"I think the biggest driver for us is just having a new in-basin egress solution for nat gas." — Jere Thompson (CFO)

U-turn wells and LOE sustainability

Q (Kevin MacCurdy · Pickering Energy): Analyst asked about productivity and costs for U-turn wells and whether lower LOE below $6 per barrel is structural or temporary.

A: Management said initial U-turn drilling showed lower per-foot costs than stand-alone 7,500-foot wells and inherited short U-turn completions performed in line with straight 10,000-foot wells, but their Diamondback-developed pad is not yet on production. They said LOE beat was driven by higher production while top-line OpEx dollars were flat; the team expects LOE to circle around "$6" a barrel with some inflation pressures from power, water and tubulars but room for upside if volumes continue to outperform.

balance sheet build vs buybacks and 2027 trade-off

Q (Douglas George Blyth Leggate · Wolfe): Analyst asked how far they will build cash on the balance sheet instead of using it for buybacks, and whether better capital efficiency means cutting CapEx or growing production in 2027.

A: Management said they will maintain flexibility: sometimes they'll grow organically, other years they may reduce CapEx and return cash depending on the cycle, and they are prepared to put cash on the balance sheet to cover near-term maturities in 2026 and 2027 and to address a maturity tower in 2029 to 2032. They emphasized they are not building cash to fund large risky deals, and historically M&A has rarely used significant cash.

"I think that there's some near-term aspects that we want to cover, right?" — Kaes Van't Hof (CEO)

AI deployment and timeline

Q (Geoff Jay · Daniel Energy Partners): Analyst asked how far along they are in deploying AI for predictive maintenance, automation, and improving uptime and what the timeline looks like.

A: Management said they are in the first inning and expect big benefit over time, focusing initially on artificial lift optimization and managing downtime with AI and automation, which is going very well. They see lots of room to expand and noted even a 1% improvement in decline rate could meaningfully reduce needed sustaining capital.

"We're tackling it first on artificial lift and using the AI and the automation to help manage that optimization on a day-to-day process, which is going really, really well for us." — Chad McAllaster

NAV drivers and other businesses

Q (Paul Sankey · Sankey): Analyst asked for more detail on how NAV moved in the quarter, how upstream performance and other businesses affect NAV, and whether NAV still matters for buybacks.

A: Management said they keep price assumptions constant and Q2 free cash flow above mid-cycle helped NAV, with Barnett growing from a few hundred million in NAV to a couple of billion as an example. They said they have midstream value from Deep Blue and see expanding multiples on water businesses, and that reduced share count plus lower net debt should increase per-share value.

"The Barnett moved from something that had like a couple of hundred million dollars of value in our NAV to now a couple of billion." — Kaes Van't Hof (CEO)

water injection capacity and midstream spend

Q (Gabe Daoud · Truist): Analyst asked if recent RRC changes constrain injection capacity and whether non-D&C spend of $600 million this year will change in 2027 or if Barnett needs incremental midstream spend.

A: Management said they have not seen constraints yet and that the solution is significant, interconnected SWD capacity rather than isolated SWDs; Deep Blue is investing to loop lines and add SWD capacity with Diamondback as anchor. They expect non-D&C spend to go up slightly next year and some Barnett development will require new batteries and infrastructure early in development before normalizing.

"I would say, Deep Blue has used the asset base that we gave them with Diamondback as the anchor customer and done a great job adding third-party business and also working to connect the system and improve it." — Kaes Van't Hof (CEO)

design changes lowering equipment cost and EOR lessons

Q (Derrick Whitfield · Texas Capital): Analyst asked which design changes lowered equipment cost per well this quarter and what lessons they learned from EOR so far and plans beyond the first 50 wells.

A: Management said much of the cost improvement comes from longer lateral lengths which reduce per-foot cost, and combining best practices from both legacy teams reduced nonproductive equipment and infrastructure capital. On EOR, they are mapping which rock types and specific surfactant technologies work best, learning from initial packages, and plan to apply those learnings to future wells while still being early in the program.

"I mean, a lot of it is driven by just extending lateral lengths, right?" — Daniel Wesson (COO)

macro volatility and Wolfcamp D changes

Q (Charles Meade · Johnson Rice): Analyst asked whether geopolitical events (e.g., Strait of Hormuz) will end market volatility or if structural changes mean more volatility, and asked about the Wolfcamp D cost and productivity trends.

A: Management said they focus on global inventories rather than geopolitics, believe inventories will need to be refilled over multi-years which supports oil demand, and acknowledged volatility remains high. Regarding Wolfcamp D, they said drilling cost goals were lowered toward "$300 a foot" stretch goals and they're hitting those, and adding Wolfcamp D inventory post-merger has not hurt productivity per foot this year despite expanding zones.

"The team had a budget of like $350, $360 a foot and their stretch goal is to drill wells at $300 a foot, and they're actually hitting their stretch goal." — Kaes Van't Hof (CEO)

Delaware Basin plans and EOR economics

Q (Leo Mariani · ROTH): Analyst asked what is planned for the Delaware Basin given low activity and whether EOR has shown clear economic benefit so far.

A: Management said no major capital is allocated to the Delaware this year or likely next, but farm-outs and Viper leasing have unlocked inventory and there is leasing and activity beneath the surface. On EOR, they said they are convinced there is economic benefit: some wells saw zero uplift while others tripled or quadrupled, with the average uplift described as "somewhere in the range of 150 to 200-barrel a day well going up by 100 to 150 barrels a day," and they need to learn why results vary so widely.

"Some wells saw zero uplift, some wells saw production triple or quadruple versus where they were before." — Kaes Van't Hof (CEO)