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Date

May 5, 2026, at 9 a.m. ET

Call participants

  • President and Chief Executive Officer — Kaes Van't Hof
  • Chief Operating Officer — Daniel N. Wesson
  • Chief Financial Officer — Jere W. Thompson
  • Executive Vice President, Reservoir Engineering — Albert Barkmann

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Takeaways

  • Production baseline -- Oil production is now set at an "approximately 520 thousand-plus barrels a day" baseline, as indicated by management.
  • Reinvestment rate -- Reinvestment rate declined to 34% from a previously planned 44%, following improved free cash flow generation at current strip prices.
  • Rig and completion activity -- Management adopted a "green light framework," adding two to three rigs and a fifth completion crew to capitalize on market signals and a backlog of DUCs (drilled but uncompleted wells).
  • Well performance -- Year-to-date well performance is "up relative to last year," driven by optimizations in completion design, perforation strategies, and automation reducing downtime.
  • Debt reduction -- Net debt has decreased to roughly $12.7 billion, with a new internal target to move toward $10 billion "on the order of a couple of months from now," due to strong excess free cash flow.
  • Buybacks and dividends -- Diamondback has bought back 42 million shares for $6 billion at $148 per share, while signaling flexibility in capital returns and recent dividend increases.
  • Waha gas protection -- The company remains "well protected with financial and physical hedges" against negative Waha gas pricing, and plans to shift further toward physical protection as new pipeline capacity comes online.
  • Acquisition line items -- Recent acquisition expenditures mainly consist of small Midland Basin deals, $50 million to $75 million in leasehold bonus, and capitalized interest, G&A, with larger-scale M&A described as "quiet" amidst current volatility.
  • Viper Energy ownership -- Diamondback sold some Viper shares in the quarter, now holding a 39% stake, and management confirmed, "We are done selling Viper shares at Diamondback Energy, Inc."
  • Barnett development -- Activity in the Barnett has accelerated, notably with two rigs focused on obligations within a JV, resulting in an incremental 1.5 net rigs to Diamondback.
  • Lateral length and well count -- Average lateral length per well was about 11,500 feet in Q1, with an expectation of 13,000 feet for full-year 2026; each crew targets roughly 100 wells per year.
  • DUC management -- The company peaked above 200 DUCs in Q1, will draw these down in Q2, and intends to rebuild to maintain operational flexibility across five crews.
  • Oilfield service inflation -- Management stated, "On services, we have not seen much pricing pressure to date. It is really a capacity question. We have not seen industry activity ramp aggressively through these first couple of months of the conflict. There is still quite a bit of capacity in rigs and completions. Calendars are not squeezed enough yet for vendors to push pricing when we look for additional equipment. We have seen some inflation in consumables and items tied directly to the commodity price, but those have been minimal thus far."
  • Surface and power project -- Progress continues toward a power and data center project aimed at utilizing in-basin natural gas at advantageous pricing.

Summary

Diamondback Energy, Inc. (FANG 3.51%) management announced a strategic acceleration in Permian Basin activity, moving to add rigs and a completion crew in direct response to what they described as the world's largest oil supply disruption and rapid global inventory declines. The current operational baseline now assumes oil production at or above 520 thousand barrels per day, with improved well performance credited to both completion optimization and field automation. Capital allocation was positioned with greater flexibility, as management intends to prioritize paying down debt substantially, while retaining the option to ramp up buybacks or M&A if market conditions evolve. The Barnett asset received increased internal focus, with rig activity aligning with joint venture obligations and an eye toward long-term inventory value. Management emphasized risk management around Waha gas pricing and did not indicate exposure to adverse service cost inflation, while noting that acquisition expenditures remain minor, and M&A is limited by volatility.

  • Kaes Van't Hof stated, "We are able to do this in a very capital-efficient manner and get it done quickly because we have this backlog of DUCs, and we prepare our business for up, down, or sideways."
  • The company reported drawing down DUCs in Q2, but backfilling with two rigs, maintaining "somewhere in the high hundreds—around 200 DUCs" to support operational agility.
  • Jere W. Thompson confirmed plans to build cash by the fourth quarter, possibly retiring "$750 million of 2026s outstanding," and considering a broader liability management strategy into 2027.
  • Diamondback's exposure to premium crude indices is enhanced via long-term commitments on EPIC, Gray Oak, and Wink to Webster pipelines, moving approximately 400 thousand barrels per day to premium Gulf Coast markets.
  • Experimental surfactant applications across 50 wells in 2025 yielded average uplift of 100 barrels per day, though results varied, prompting continued technical refinements.
  • Kaes Van't Hof commented, "That private activity growth, particularly in the Midland Basin, has now been consolidated. There will be private growth—the private model has shifted to smaller asset packages developed quickly and farm-ins into larger operators’ positions. There has been growth in Northern New Mexico. By our math that is 20 to 30 rigs, not 100 rigs like 2022. They will move quickly, but the volume impact will not be what it was in 2022."
  • Board decision-making was described as rapid and proactive, with crisis communication leading to accelerated capital allocation changes before earnings publication.
  • Financial hedges and pipeline contracts protect against regional gas pricing weakness, ensuring continued movement of all gas molecules, albeit sometimes at negative prices.

Industry glossary

  • DUCs (drilled but uncompleted wells): Wells drilled and cased that have yet to undergo the final completion process to begin production, providing operational flexibility to ramp output rapidly.
  • Waha: A regional natural gas price hub in West Texas known for pricing volatility due to pipeline constraints.
  • Frac (hydraulic fracturing) crew: Team and equipment responsible for performing hydraulic fracturing operations to stimulate oil and gas production from wells.
  • Simul-frac: Simultaneous hydraulic fracturing of multiple wells from the same pad to increase efficiency and reduce costs.
  • JV (joint venture): Business arrangement in which two or more parties combine resources for project development and share operational and financial risk.
  • EPIC, Gray Oak, Wink to Webster: Major crude oil pipeline systems transporting Permian Basin crude to Gulf Coast markets, facilitating access to premium pricing.
  • Viper Energy: Royalty and minerals subsidiary or affiliate of Diamondback Energy, Inc., referenced for asset monetization and ownership stake management.
  • Leasehold bonus: Upfront payment made to secure oil and gas exploration and production rights on specific acreage.

Full Conference Call Transcript

Kaes Van't Hof: Thanks, Adam T. Lawlis, and welcome, everyone. As with the last few years, we are going to go straight into Q&A. Operator, please open the line for questions.

Operator: We will now open the call for questions. Thank you very much. One moment. As a reminder, to ask a question, you can press 11 on your telephone and wait for your name to be announced. To withdraw your question, please press 11 again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Neil Singhvi Mehta of Goldman Sachs. Neil Singhvi Mehta, your line is open.

Neil Singhvi Mehta: Good morning, Kaes Van't Hof, and good morning, team. The big development here today that you have been signaling is the move to a green light framework from yellow light, adding the two to three rigs and moving to the fifth completion crew. Can you take a moment for the investors on the line to talk about the thought process that went into this decision and how you are thinking about where and when to add activity? And then on the return of cash capital framework, you did not move away from the fixed framework, and while you bumped the dividend, you indicated that you might be slowing down the buyback a little bit.

Can you talk about what you intended to communicate with that? There is a very concentrated seller ownership base here, and if the family ultimately is going to sell into the market or sell down their stake, do you still view Diamondback Energy, Inc. as a logical buyer to help offset that potential risk on the stock?

Kaes Van't Hof: Yes, Neil Singhvi Mehta, that is a good question. There are macro elements as well as micro elements, and we will go through both. From a macro perspective, there is a clear market signal. We are two months into the world’s largest oil supply disruption in history. Diamondback Energy, Inc. and our stockholders are very fortunate that we are solely based in West Texas. We are kind of tourists in this situation, but it is obviously a very serious situation with a lot of oil supply off the market. If that is not a signal to grow production in an advantaged area like the Permian Basin, then I do not know what is.

We hope there is a resolution to the conflict, but even if there is, there is a lot of noise in the system and a lot of barrels that have been taken off the market. Global inventories are starting to decline very rapidly, and we are going to do our small part to add some production into the mix. At the micro, or Diamondback Energy, Inc. level, with the best inventory quality and depth in North America being executed at the best cost structure, if this is not the time to grow now, then when is it?

We are able to do this in a very capital-efficient manner and get it done quickly because we have this backlog of DUCs and we prepare our business for up, down, or sideways. We are able to make one decision and add a frac crew earlier in the year and get that production up immediately. It is a testament to the team’s preparation and the organization working together and being able to do this very quickly, whereas in other organizations it might take longer to make that decision. On returns, allocating capital is the most important job we have as a management team.

The history of the return of capital program for both ourselves and the industry was put in place after the COVID near-extinction event of the industry. Investors said, “I want my money back and I want it in a formulaic manner,” and that has worked very well over the last few years. I do not expect our ability to return capital to stockholders to change. We just want the flexibility to make more cyclical moves versus moves within a 90-day window within a quarter. We have a very good track record of buying back our own stock. We bought back 42 million shares for $6 billion to date at $148 a share.

Clearly, with the stock where it is today, that is a very positive rate of return for our stockholders, and I expect that to continue. We recognize we also have a large shareholder that we found a way to help monetize their stake in a very efficient manner. Outside of their stake, they are most focused on us creating long-term value. Allocating a ton of free cash to the balance sheet in times of extremely high oil prices does create long-term value with, in our mind, a higher floor for the stock long-term. We have a great relationship with the family. We have the ability to help them monetize.

If we use excess free cash flow over the next couple of quarters to pay down debt, we can help monetize their stake more efficiently coming out of this. They are long-term holders and they want the stock higher.

Operator: Thank you very much. Our next question comes from the line of Scott Michael Hanold of RBC Capital Markets. Scott Michael Hanold, your line is open.

Scott Michael Hanold: Thanks. You all had some pretty robust production performance in 1Q and, based on our chat last night, it sounds like your completions were as planned. Can you walk through why performance was so strong? It sounds like it was a lot more well performance versus any other dynamic. Is that something we should anticipate moving forward, and what is embedded in guidance? And when you guided oil, it looks like you are very much greater than potentially 520 thousand barrels a day. If you continue to see this macro environment, how much desire is there to continue to let that oil production grow versus curtail it?

Is there a scenario where you would step it up even higher if the macro continues to be heightened?

Kaes Van't Hof: High level, our well performance year-to-date looks up relative to last year. That is probably a surprise even to us internally. We continue to try new things in terms of completion design and efficiency that are starting to pay dividends. On the production side, which we have been talking about a lot over the last couple of quarters, there are a lot of good things happening in the field in terms of less downtime and more automation—call it AI or automation—impacting that side of the business. Better wells and lower downtime is a good recipe for a production beat. On the oil trajectory, it is a fluid situation, and the board wants us to take this quarter by quarter.

If there is outperformance and we still have triple-digit oil prices, and the market is calling for oil to come to market, then this is a year where, instead of pulling back activity, you keep the efficiencies going and production continuing to climb. We are ready to react. We still have some things in our back pocket to grow further, but for now, this approximately 520 thousand-plus barrels a day on oil is the new baseline.

Daniel N. Wesson: Post the Endeavor merger and getting the team together, we started trading a lot of ideas on optimizing primary completions as well as the base. On the completion optimization side with perforating strategies, rate design, and sand loadings, we think we are seeing uplift in the wells, and time will tell as we continue to implement that completion design. On the production side, workovers, acid jobs, chlorine dioxide jobs, and surfactant jobs are starting to pay dividends. Layering in machine learning as we look at our data streams and processes and implementing AI into our field operations is reducing downtime, which has been a big part of the beat in Q1.

These incremental optimizations across the board are starting to show through to the top-line number.

Operator: Thank you very much. Our next question comes from the line of Neal Dingmann of William Blair. Neal Dingmann, your line is open.

Neal Dingmann: Morning, Kaes Van't Hof and team. My question is on activity. How much, if any, will negative Waha prices impact what you might or might not do? And the same question with oilfield service prices—are you expecting OFS inflation given what is going on with prices? And secondly, on capital allocation, especially given continued record free cash flow growth per share you will likely have, how does capital for M&A stack up against buybacks or near-term debt repayment?

Kaes Van't Hof: On Waha, pricing is deeply negative, but we are well protected with financial and physical hedges. Our mix of physical to financial is going to move more toward physical when the two new pipes come on, hopefully in the second half of the year. We are protected to get through this tight spot from a financial perspective while we continue to add oily inventory—we are drilling some of the oiliest rock in the basin. We continue to work on our physical protection on the gas side. We have worked on a power project for almost a year; we will see if we can get that done.

We have talked at length about monetizing our gas, and we are on the cusp of that as these pipes come on. On capital allocation, on day one in finance you learn the options for free cash flow: grow organically or inorganically, pay a base dividend, pay down debt, buy back shares, or hold cash. We have decided to pull the organic growth lever in a small way by going to the top end of our CapEx guidance. Inorganic growth—M&A—we have been very good at over the years, but this volatility makes it difficult to get deals done, private or otherwise, so M&A is probably fairly quiet for the foreseeable future.

With oil prices where they are, I do not know if investors are capitalizing this price environment yet. For us, the bigger use of free cash will be to pay down debt rapidly and convert that debt value to equity value in our NAV, and keep some cash for a rainy day because this is a very volatile environment.

Daniel N. Wesson: On services, we have not seen much pricing pressure to date. It is really a capacity question. We have not seen industry activity ramp aggressively through these first couple of months of the conflict. There is still quite a bit of capacity in rigs and completions. Calendars are not squeezed enough yet for vendors to push pricing when we look for additional equipment. We have seen some inflation in consumables and items tied directly to the commodity price, but those have been minimal thus far. We will see what activity does in the Permian and across the Lower 48 to gauge service inflation through the rest of the year.

Operator: Thank you very much. Our next question comes from the line of Arun Jayaram of JPMorgan Securities. Arun Jayaram, your line is open.

Arun Jayaram: Good morning. The calendar 2026 and 2027 strips are around $90 and $75. How do you think about your approach to development in a much stronger oil price than we saw 90 days ago? For the two to three incremental rigs, how are you thinking about capital allocation across your asset base? Are the deeper benches now competing for capital as you get down some of those well costs in the Barnett? And as a follow-up for Jere W. Thompson, you have taken pro forma net debt down to about $12.7 billion.

Given the intention to pay down more debt in a higher commodity price environment, what are some of the targets you are looking for from either a gross or net debt perspective?

Kaes Van't Hof: Even with higher commodity pricing, we are going to hold to the vast majority of our spacing assumptions across the basin. We look at each project on a DSU-by-DSU basis and aim to get as many wells in a section as possible to where the incremental last well generates a 40% rate of return at $60 oil. That provides prudent spacing and solid returns to shareholders despite commodity volatility. Drilling our best stuff first and sticking to that knitting is going to continue. The Barnett, particularly with the size of those wells from a production perspective, generates more PV today, so it is getting more attention.

Albert Barkmann: That is right, Arun Jayaram. With the acceleration plan adding two rigs, there is a big acceleration in the Barnett plan. We are focused on that development and getting ahead of the Barnett obligations that we discussed last quarter.

Daniel N. Wesson: I will add that the Barnett activity and the obligation activity are almost entirely focused on the JV area we have with another partner. Those wells are not as high working interest—about half and half, a little heavier weighted to Diamondback Energy, Inc. So adding two to three rigs picks up around 1.5 net rigs to Diamondback Energy, Inc. While the top line looks like we are adding a bunch of activity in the back half of the year, net to us it will not be nearly as impactful.

Jere W. Thompson: On the balance sheet, we have previously talked about hitting that $10 billion net debt figure in the next 12 to 18 months. With where commodity pricing is and excess free cash flow generation, it looks like we will be able to hit that much earlier—on the order of a couple of months from now. As we move into the back end of the year, we will have an opportunity to reduce not only net debt but also gross debt. We will likely build cash on the balance sheet through the fourth quarter and then take a look at calling our $750 million of 2026s outstanding.

As we move into 2027, we may do a larger liability management exercise with additional cash on the balance sheet, with the idea of taking out as much as we can from a near-term maturity perspective, particularly anything that matures prior to 2030. We are in an advantaged position to move our balance sheet from a position of strength to what I would call fortress, and we can do that in the very near term.

Operator: Thank you very much. Our next question comes from the line of John Christopher Freeman of Raymond James. John Christopher Freeman, your line is open.

John Christopher Freeman: Thank you. Even after increasing activity, reinvestment rate for you all still fell sharply from what you were originally planning last quarter from 44% to 34% at the current strip. You have the ability to increase activity more and still likely have an industry-leading low reinvestment rate. I know returns ultimately drive your decisions, but is there a reinvestment rate that you want to stay below regardless of the commodity environment? And the original 2026 plan did not forecast any meaningful DUC draws or builds. How does that look now with the new plan?

Kaes Van't Hof: We have been polling investors that own the stock to get their opinion on growth and ramping activity. The general consensus was that a little growth in the plan will differentiate Diamondback Energy, Inc. and make a lot of sense, but do not do it in a capital-inefficient manner. We were going to run somewhere between four and five frac crews to hit our original guide. That fifth frac crew was going to go away for five or six months, then come back. It is a Halliburton e-fleet simul-frac, as efficient as it gets. We are just bringing that crew back and going to run five crews consistently.

That will ensure we maintain capital efficiency in the field versus trying to go too fast too soon, which can drive inefficiencies. Staying capital efficient is the priority; the reinvestment rate is the output of that. On DUCs, we will draw down DUCs in Q2 and backfill with two rigs of activity to build our DUC balance back up. We peaked a little over 200 DUCs in Q1. That number will come down in Q2, and the backfill rigs start building that back up.

We likely need to maintain somewhere in the high hundreds—around 200 DUCs—because we like to have two projects behind each crew ready to go so if something happens, we move to another project and keep execution smooth on a quarterly basis. There will be some movement throughout the year.

Daniel N. Wesson: We like to keep a quarter to a quarter-and-a-half worth of inventory ahead of each crew to maintain flexibility if we run into takeaway constraints or other pad issues. Each crew will do about 100 wells a year, maybe a little more. So carrying a couple hundred wells ahead of five fleets is the right DUC balance. As crews get more efficient and get more wells done, either we release crews to keep the same well count or we build more—20 to 30 wells for the year in total—and still stay within our original guidance window. We took the momentum from Q1’s beat and kept it going through the rest of the year.

Operator: Thank you very much. Our next question comes from the line of Analyst from Barclays. Analyst, your line is open.

Analyst: Good morning. Thank you for taking my question. I want to ask about your crude oil marketing. 1Q pricing was a bit stronger. Can you remind us of your exposure to premium price indices and the marketing strategy in general on the oil side? And on the acquisition line item in 1Q, there were just a few hundred million. Are you doing any organic acquisitions or picking up bolt-ons at good pricing?

Kaes Van't Hof: From a strategy perspective, we learned from the Permian takeaway crisis of 2018 that we needed to use our balance sheet to get our crude to the biggest markets. For us, that was Corpus Christi and Houston. We invested in three pipelines—EPIC, Gray Oak, and Wink to Webster—all of which made our investors a lot of money and protected Diamondback Energy, Inc. commercially. We have about 300 thousand barrels a day going to Corpus on EPIC and Gray Oak and another 100 thousand a day going down Wink to Webster feeding Houston’s Refinery Row. We are exposed to water-based pricing and even have one small contract with some Dated Brent exposure. That has been helpful.

That is a good playbook for what we will do on the gas side next.

Jere W. Thompson: On the acquisition line, there were a couple of small acquisitions in our backyard in the Midland Basin. As a reminder, in that line item we include capitalized interest and capitalized G&A, which made up the vast majority there. That plus a couple of small acquisitions and roughly $50 million to $75 million in leasehold bonus drove the figure.

Operator: Thank you very much. Our next question comes from the line of Phillip J. Jungwirth of BMO. Phillip J. Jungwirth, your line is open.

Phillip J. Jungwirth: Good morning. Can you talk about how you are viewing Viper ownership and what is optimal for Diamondback Energy, Inc.? You sold some in the quarter and still own 39%. The company’s free cash flow outlook is stronger, so less need for divestitures. Is there any minimum level of ownership you would look to maintain, and how does that play into overall capital allocation? And in the 2022–2023 upcycle, private operators drove an outsized share of rig additions and oil growth. How would you characterize the ability of privates in the Permian to respond to higher oil prices now versus a couple of years ago, given implications for tightening OFS markets?

Kaes Van't Hof: We did sell down a little ownership in Viper as a follow-on from the dropdown where Diamondback Energy, Inc. took a lot of Viper stock. We could have taken more cash then but instead decided to wait and sell a little last quarter. We are done selling Viper shares at Diamondback Energy, Inc. The growth opportunity set for Viper is significant. There could be a world where Diamondback Energy, Inc.’s ownership is reduced through dilution—that is possible—but no desire today to monetize more shares. In another few months, both companies will be positioned from a balance sheet perspective to do anything from an M&A perspective, and that is where we wanted to be.

On privates, in 2022 you saw Endeavor (now part of Diamondback Energy, Inc.) go from two rigs to 15 rigs; CrownRock (now part of Oxy) went from two to eight; EnCap North (now part of Aventa) from two to six; Double Eagle (now part of a combination of us and Exxon) from one to six. Those were big moves. That private activity growth, particularly in the Midland Basin, has now been consolidated. There will be private growth—the private model has shifted to smaller asset packages developed quickly and farm-ins into larger operators’ positions. There has been growth in Northern New Mexico. By our math that is 20 to 30 rigs, not 100 rigs like 2022.

They will move quickly, but the volume impact will not be what it was in 2022.

Operator: Thank you very much. One moment for our next question. Our next question comes from the line of Scott Andrew Gruber of Citigroup. Scott Andrew Gruber, your line is open.

Scott Andrew Gruber: Good morning. In light of the impact of the privates you just mentioned, how do you think about Diamondback Energy, Inc.’s volumes over the next five to ten years on an organic basis? Do you think about being in modest growth mode, stepping higher during periods of elevated prices like today and maintaining that new level, so net-net you are growing? Or when commodity prices are soft, do you pare back activity and let production fade back down? Also, turning to capital efficiency, it appears to improve with the updated plan, but it is hard to separate the DUC draw impact from adding rigs in the Barnett where you are still ramping learnings and efficiency.

As you lap the DUC draw into 2027, do you think you will be able to show improvement relative to the initial program this year?

Kaes Van't Hof: The operator with the best inventory quality, lowest cost structure, and longest inventory depth has the right to grow organically and create shareholder value. We have been talking about trying to hit the organic growth accelerator for a while; we just have not had the macro conditions to support it. In a world where mid-cycle pricing is a little higher—call it $70-plus WTI—then a couple percentage points of organic growth can really add to NAV and long-term free cash generation. One important point we ran in the model this year is that this new plan generates more free cash flow per share at any oil price above $60 than the prior plan.

In a $70-plus world, this is advantageous to shareholders long term. On capital efficiency, DUC draws and bringing back DUCs in the Barnett are noise. Below that, the team is executing. We set records on the drilling side on two-, three-, and four-mile laterals. In Wolfcamp D development, we gave the team a goal of $300 a foot for drilling, down from $360 a foot last year—we are already at $300 a foot. In Barnett drilling, we said drilling needs to be below $400 a foot to get to $800 a foot total to make the Barnett competitive—we already put a well in under $400 a foot.

Efficiencies continue to improve above ground, and the big move is subsurface—drilling and completing better wells. Those are the long-term capital efficiency drivers.

Operator: Thank you very much. Our next call comes from the line of Derrick Whitfield of Texas Capital. Derrick Whitfield, your line is open.

Derrick Whitfield: Good morning, and thanks for taking my questions. Regarding your share buyback and its guiding principles, where do you view mid-cycle pricing now in light of the current Middle East conflict and the risk premium associated with that? And could you speak to what you are seeing in degradation of inventory quality across the Permian, clearly beyond Diamondback Energy, Inc.?

Kaes Van't Hof: If I was not long-term bullish, I would be out of a job. Within three months, we went from the projected largest oversupply in history—which was debatable—to now the largest undersupply in history, and we are only two months in. It is hard to move off our mid-cycle pricing assumptions: mid-$60s WTI, mid-teens NGLs, and $3 gas, with Waha diffs. There is a case for energy security becoming much more important globally, which likely means more storage—more landed storage versus storage in riskier geopolitical areas. That makes the U.S. barrel more important than it has ever been. For U.S. shale, we think the cost curve is moving up.

Operators have done a good job with efficiencies, longer laterals, better development, but geologic time catches up and there are signs of degradation in productive quality throughout the U.S. We keep ourselves at the low end of the cost curve through inventory depth and quality and the cost at which we execute. We are well positioned, but it is too early to raise mid-cycle pricing.

Derrick Whitfield: As a follow-up on the Barnett referencing the play outline, how large could you reasonably grow this position beyond the 200 thousand you are highlighting?

Kaes Van't Hof: We announced this position after we thought we had a solid base of what we could get. We have continued to add in Q1 on a small basis. Now we are doing a lot of trades. Many big operators have Barnett positions, and we are all looking at blocking up three- and four-mile laterals. There is private equity in Midland building six- to eight-section positions that likely come to market. I think the position will grow. We have the sizable base we need to continue to grow it.

Operator: Thank you very much. Our next question comes from the line of Analyst from Pickering Energy Partners. Analyst, your line is open.

Analyst: Good morning. Can you provide color on the cadence of net lateral footage per quarter throughout the year and the lateral length per well? We would assume the additional 200 thousand lateral feet is back-half weighted. And any updates on the surfactant tests?

Daniel N. Wesson: The additional lateral footage is going to be evenly weighted toward the back half. We went up to about 6.2 million lateral feet, so we are looking at probably 1.5 to 1.6 million per quarter in the back half of the year. On lateral lengths per well, Q1 was one of our lighter quarters at about 11.5. For the full year 2026, we still expect to be at 12.9, ramping through the back half. On surfactants, we had a big push toward the end of last year to get tests in the ground across different rock types and chemistries.

We have those tests in, the team is studying, we are refining the process, and plan our next deployment early this quarter.

Kaes Van't Hof: One thing to add: we tested around 50 wells last year. On average we saw about a 100 barrels-a-day uplift. Some wells were up by 400 or 500 barrels a day and some were zero. Now we are figuring out what we did right in the 400–500 barrels-a-day wells and what we did wrong in the zeros. This is version 1.0. I think Diamondback Energy, Inc. and the basin are on the cusp of technological breakthroughs related to increasing recoveries past primary development. That will be a mega theme over the next four to six years with a lot of dollars and time spent.

That is why we have held as much acreage as we have—we have some of the best oil in place in the basin and some of the smartest people working to extend the basin’s life by a decade or two.

Operator: Thank you very much. Our next question comes from the line of Analyst from Truist. Analyst, your line is open.

Analyst: Morning, thanks for the time. On the return of capital framework and pursuing growth this year, what would an upper bound of oil production growth be for Diamondback Energy, Inc., assuming you have the green light on the macro? Is it fair to assume 5%, or could it be higher? And any update around your surface position in light of a new market entry—specifically the power project?

Kaes Van't Hof: I do not want to get into a specific number. We have already grown low single digits year-to-date. I do not think there is a lot of investor appetite for a large CapEx bump and more than mid-single-digit growth. It is early and there is a lot of noise, and no one is sure how this macro unfolds. We are keeping our cards close to the vest—putting out a good forecast in Q1 and seeing how the rest of the year unfolds. Investor appetite is not for the go-go days of 2017–2018 with multiple CapEx increases and mid-double-digit growth. We will keep it steady and capital efficient, and take the macro quarter by quarter.

Jere W. Thompson: On the surface and power project, we are making meaningful progress with our partners. We view the power and data center opportunity as a unique way to use our natural gas in-basin at advantaged pricing. Once we finalize a project, we will be able to discuss it in more detail, but it continues to move forward.

Operator: Thank you very much. Our next call comes from the line of Charles Arthur Meade of Johnson Rice. Charles Arthur Meade, your line is open.

Charles Arthur Meade: Good morning, Kaes Van't Hof and team. On the acceleration of CapEx, can you give us an inside baseball account of how you came to that decision? Did the board leave you latitude, or did you arrange a quick meeting to make the case and act on it? I am trying to get insight into how you operate as a fast mover in a volatile oil tape.

Kaes Van't Hof: Our board is very nimble for its size—13 members—and they move quickly when the decision is obvious. We took advice from Jamie Dimon last year: communicate with your board often and tell them everything. We decided to over-communicate through this crisis. The crisis kicked off a week after earnings; we had set the budget. We sent three or four notes to the board in March to update them on our thinking. Then it was a simple meeting ahead of earnings to make this decision. The board gave resounding support for the plan.

Operator: Thank you very much. Our next question comes from the line of Leo Paul Mariani of Roth. Leo Paul Mariani, your line is open.

Leo Paul Mariani: There has been discussion of weak Waha prices in 2Q. Could there be short-term negative volume impact? Are there wells with lower oil cut where you might choke some for a period given how bad gas prices are? And on growth, your guidance for oil is a bit open ended with 520 thousand-plus. You did 520 thousand in 1Q and it looks like you are guiding to 520 thousand again. You talked about a little growth—if the oil environment holds, should we think about that plus a little growth in the second half?

Kaes Van't Hof: At these NGL prices, negative $3 Waha basically cuts out the value of your NGLs. Worse than that—negative $4 to negative $6—you start to eat into the value of your oil production. Oil is $100 a barrel, not $60, so it is different math on shutting in oil barrels because of Waha pricing. That is likely happening in the basin; in New Mexico with tighter midstream and flaring restrictions, that is probably more acute. For us, when Waha blew out in October due to maintenance, we shut in 2 thousand to 3 thousand barrels a day for a period. When Waha came back, we brought it back.

I would bet we are around that range today with Waha as weak as it is. It is not impeding new development, particularly with our financial hedges. Every molecule we have produced has moved; it is just moving at a negative price. On oil guidance, that is fair—we will take it quarter by quarter. If we are outperforming and the market needs it, we will hold activity and produce more oil.

Operator: Thank you very much. As a reminder, to ask a question, you will need to press 11 on your telephone and wait for your name to be announced. To withdraw your question, please press 11 again. Our next question comes from the line of Doug Leggate of Wolfe Research. Doug Leggate, your line is open.

Doug Leggate: Thanks. I wonder if I could come back to the balance sheet. With no variable dividend taken out of the capital return structure, is it inconceivable that your net debt could basically go to zero over the next two or three years? Would you allow it to go to that level? And not so much about your growth but what you are seeing from your nonoperated positions—this might be a Viper question. There is a lot of non-op working interest that can influence consolidated growth. How would you characterize what you are seeing on non-op activity?

Kaes Van't Hof: That would be a good problem to have. We will be transferring a lot of value from the debt side of the NAV to the equity side over this quarter. We will take this quarter by quarter; we are early into this oil price environment. Should it persist and the stock continue to go up, we will allocate less to buybacks and continue to put cash on the balance sheet. This is a cyclical business; we want the flexibility to pounce on opportunities when the cycle turns—M&A, buying back a ton of stock, even leaning on the balance sheet to buy back stock. The key terms are flexibility and long-term value creation.

At the end of the day, we want to get to zero debt and one share outstanding. It will be a race between those two with free cash generation over the coming decades. On non-op, Diamondback Energy, Inc. carries very little non-op, but Viper sees roughly half the wells in the basin. Early signs are no major changes on permitting, but discussions in the field are that rigs are getting picked up on the private side. If we had to forecast the Permian rig count by year end, we are probably up 25 to 30 rigs from where we are today.

Operator: Thank you very much. Our next question comes from the line of Analyst from Melius Research. Analyst, your line is open.

Analyst: Thanks. You have to be thinking about a market that has significantly changed in the last 60 days and an oil price that could be structurally higher. Understanding you raised guidance for this year, how are you thinking about the out years and how you want to set up the company to continue to grow at a mid-single-digit rate or not in 2027, 2028, 2029? Not looking for guidance, but how is your longer-term thinking evolving? And as you think about your inventory depth versus peers—you are in a leading position—how would you phrase your position versus peers given the longevity you have?

Kaes Van't Hof: If we are in a higher-for-longer world, an advantaged company with advantaged inventory like Diamondback Energy, Inc. should answer the call for production growth—so long as it maintains capital efficiency. That would move the business from a steady-state bond-like free cash generator to a free cash flow per share growth generator over the next few years into the decade, if supported by the macro. It is early, but the world changed a lot since our last call. On inventory, we are fortunate to have incredible quality and duration. We are always looking for the next stick—organically in Barnett development or Upper Spraberry over the last few years, and inorganically.

This machine is built to do significant transactions like Endeavor, and also the sub-$20 million deals. We do not want a unit in the Midland Basin trading hands without Diamondback Energy, Inc. knowing it could be in our hands.

Operator: Thank you very much. I am showing no more questions at this time. I would now like to turn it back to Kaes Van't Hof for closing remarks.

Kaes Van't Hof: Thank you, everybody, for your interest. We are always available to answer any questions—just reach out to the number or email on the notices.

Operator: Thank you for your participation in today’s conference. This does conclude the program, and you may now disconnect.