Diamondback Energy Stock

Good day, and thank you for standing by. Welcome to the Diamondback Energy Second Quarter 2026 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the call over to your host today, Adam Lawlis, VP of Investor Relations. Adam, please go ahead.

Thank you, Grace. Good morning, and welcome to Diamondback Energy's Second Quarter 2026 Conference Call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback's website. Representing Diamondback today are Kaes Van't Hof, CEO; Danny Wesson, CEO; Jere Thompson, CFO; and now Mark, Chief Engineer. .

During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors.

Information concerning these factors can be found in the company's filings with SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Kaes.

Good morning, everyone, and I hope everybody read our shareholder letter last night continues to get good feedback from the investment community. And as we've done over the last couple of years, we're just going to move straight into Q&A. So operator, please open the line up for questions. .

At this time, we will conduct the question-and-answer session. [Operator Instructions]

Our first question comes from the line of Neal Dingmann with William Blair.

Happy birthday Kaes from me in the coach. Turning to my first question. So I want to talk about your macro view specifically your remarks last night, you seemed to indicate your thoughts that worldwide inventory levels will remain low for the foreseeable future. So as such, am I correct in thinking that you all will continue to strategically grow production well into '27 given this low inventory backdrop and in terms of oil backdrop?

Yes, Neil, I think it's been pretty hard to predict what's going to happen globally over the last couple of months, certainly our opinion and the data shows that inventories are draining not only on the oil side, but on the product side and absent permanent demand destruction, which we're hopeful is not the case. .

Those inventories are going to have to be refilled. And we can debate at what price those inventories need to be refilled. But I do think that helps us get some confidence that there's a bid for a longer-term bid for oil to refill those inventories and meet gold demand. So in general, I think that does skew us towards the decision to grow production versus whole production flat -- we were the first to respond to the price signals in March to increase our production for the year by 3% or 4% versus original plan.

The team executed on that very, very quickly to where we are today, up somewhere around 4% from where we started the year. And I think the goalposts are for us going into next year, do we hold production flat, which we're kind of doing from these higher elevated levels right now or do we grow organically off of this number in a capital-efficient way.

And right now, the model spits out some form of low single-digit organic growth while maintaining capital efficiency and running 5 frac crews consistently throughout the year. So I think in today's environment, betting on the need to refill inventories, that's probably where our head is today. But as you've seen in the past, Diamondback can react quickly to the positive or the negative.

And I think in this environment, it's prudent to be able to do that. So there's a lot of uncertainty out there, Neil. I think our bet is that these global inventories, including SPRs are going to need to be rebuilt. And that should be a positive for Diamondback shareholders and Diamondback's growth trajectory.

Great points. Okay. And then just secondly, turning to wealth productivity definitely shown on your recent Slide 10. To me, what seems most intrigued in there is not only the high productivity you have, but you're doing this -- I'm looking at the left side of the slide also, why it sort of seems like maximizing value. You're targeting the most zones, wells per section. And I think what you all would say probably the most appropriate completion level. So I'm just wondering, could you talk about how you're able to sort of target these, the lean productivity while maximizing value.

Yes. I think Slide 10 is the most important slide in our deck when it comes to the technical aspects of our business and how we're making capital allocation decisions in the field. So it's been there for a couple quarters now, and we've put in some data on year-to-date performance. And clearly, we're having a good year in 2026 so far. And I kind of steal a comment from one of our competitors because I think his comments smart in that this is kind of a stacked innovation play, right? We've done a lot of things in terms of well construction, well targeting, stimulation and that's leading to better results. And we didn't get here overnight, right? We started by drilling wells in 30 days. Now we're drilling them in 5.

But our culture and our organization is a continuous improvement culture that has led to these results today. So high level, we try to blend the best mix of most wells per section right on the bottom left of that slide, multiplied by the most production per well, and clearly, Diamondback operates at the lowest cost per well, and that should generate or does generate the most NPV per section or acre or asset in the basin. And we're very proud of that, and we got to keep working on that to continuously improve the business. Adam do you want add anything on what we've changed and done over the last couple of years?

Yes. I mean, like you said, I think it's really about maximizing the return on every well that we put in at the issue, Neil. I mean the specifics, when you think about well construction, doing larger tubulars, that allows us to flow the wells back more aggressively on the stimulation side, stage architecture and perforating. And then on the targeting side, the technical teams, taking a deep dive, looking at how we target every well within the DSU, I think is what we're seeing leading to the outperformance on the page here.

Yes. So it's a lot of little wins, Neil. We got to stack up those little wins and keep doing that to maintain our position. .

Thank you. Our next question comes from the line of Neil Mehta with Goldman Sachs.

Yes. Appreciate you taking time I guess the first question is just on the gas side, Waha has firmed up a little bit. So just how are you thinking about egress out of the base and recognizing this is probably a problem that will percolate again. But that does this create some near-term relief? And then as you think about your gas strategy in general, maybe it is a good opportunity for you to update the market where you stand around the data center side and the power side of your business?

Yes, Neil, anything is relief compared to Q2. So we're happy to see these new pipes start to flow, and we've seen some announcements from both Energy Transfer and Whitewater that the 2 big pipes are moving forward. that's resulted in Waha being positive for the whole month of July and certainly a nice tailwind for us and for our shareholders in the near term. But I'll take it a little higher level because I think we believe in the gas mega theme, it's not core to Diamondback's value proposition, but it can be additive to the amount of oil we produce.

And in general, I think that means us owning more space to the Gulf Coast and we can debate where that needs to go in the Gulf Coast. But certainly, the large demand centers are going to be along those pipelines for either power projects or data centers. And then the rest of the gas that gets to the Gulf Coast is going to cross the docs in the LNG terminals. And I think I'm not smart enough to figure this out today. But the question is going to be how much demand can the world handle from an LNG perspective because we're certainly going to have enough supply coming out of the U.S. on the LNG side.

And to fill that, I think the Permian is going to play a big role. I think Diamondback is going to play a big role. So our gas production continues to outperform expectations. I think that will continue over the next 10-plus years. And therefore, we need to have more contracted space to more markets to be in the conversation when the LNG off-takers need supply.

So we're meeting new people in that world and building relationships because I do think kind of the wellhead to water gas strategy has to be part of the Diamondback proposition. On top of that, we also believe in the power of data center mega theme, and we have a project that we've been working on, and Jere is going to give you some color on where we are.

Yes, Neil. Great question. For some background, we and our IP partner put together of what we view as a very unique bridge to grid solution on our 30,000-acre Bryant Ranch location, ultimately to deliver scalable, reliable power near Midland, Texas. We have secured distributed power generation, remediated land and directed access to dedicated nat gas and water supply. .

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 reset units. Beyond this initial phase of power generation, we are working to secure great connected power as soon as 2028, be a batch 0. We believe we are well positioned within the batch 0 queue and are awaiting ERCOT's final determination regarding project eligibility for the next interconnection study as soon as their meeting on August 20.

We are closely monitoring communication out of Austin and remain confident in a project like ours with low water use and new generation ultimately meeting batch 0 standards. We'll give the market a larger update once we've signed the definitive documentation with a hyperscaler but are confident in the direction that this project is going. .

Neil, I'll add 1 thing. I was in a room with a lot of the tech world about 1.5 years ago. It's kind of a mix of Energy and tech. And the energy side of the equation kind of got locked out of the room when we suggested to come with West Texas and build behind the meter. And someone who was in that meeting called me last week and was -- and reminded me of that and said, I'm coming to West Texas, and I want to build behind meter. So I do think we've offered a lot of opportunity out here.

At the end of the day, Diamondback is going to stay in our lane, which is produce the molecules, deal with the -- produce -- provide the surface, provide the water, provide the industry know-how. We're not a power company. We're not a data center company, but we certainly can play an important role in this ecosystem that's coming together.

Yes. That's a really helpful update, and we'll stay tuned for more. And then Kaes, just maybe give the market an update around how you're thinking about return of capital I think you adopted a little bit more of a flexible strategy or way of updating the market. How did you approach it in 2Q? How are you thinking about the balance of the year? And talk about that in the context of your largest shareholder, too..

Yes. So let me just frame the goal, right? The goal for us is to maximize and capitalize on the option value that is inherent in this business, right? We live in a very volatile business where things can change overnight. And we felt that a formula or any sort of restriction on capital allocation does not allow for the maximization of that option value. So that's why we -- last quarter, as prices rose, we said, listen, we're not going to commit to returning a minimum percentage of free cash just because we have to.

And we removed that minimum commitment -- and there's a lot of discussion on the call about it. There was a lot of discussion in the couple of days afterwards with shareholders, explaining our case, and they were very supportive. And -- since then, I have not heard a lot about it from long-only shareholders. They've been supportive. And then you look at what we did, right? So we did allocate a little bit to the buyback in Q2 as weakness stepped in at the end of the quarter.

We've allocated a little bit to the buyback here in Q3. You can see that those numbers that we're willing to buy back at have gone up. But we also reduced net debt by $1.6 billion. And that translates to $5.60 a share of value that went from the debt side of the equation to the equity side because in my mind, our NAV wasn't -- didn't go down much in the second quarter. In fact, it went up.

So I think it's more about looking at what we've done versus what we're going to do. And I do think investors know that we will lean in on buyback when it presents itself. If you look at a year like 2025, we bought back over 5% of our stock. I wish it was 10%, right? And now I think we're positioning the balance sheet to be in a position where we actually can lean on it to buy back shares when the cycle turns in this volatile business.

So really just trying to make the right capital allocation decision every day. And just like the stacked innovation in the field, if we can stack up those wins on return on capital. I think that's a long-term win for our shareholders.

One moment for our next question. Our next question comes from the line of Scott Hanold from RBC Capital Markets.

I was wondering if you could delve into some of the production performance a little bit. You all are delivering more than oil barrels and I guess, guided to but nat gas is really outperforming. And can you just give us a sense of why you think that is? Are you just being conservative with gas expectation? Or is there any kind of zone targeting that different that would cause that? And where do you see that going moving forward?

Scott, it's Danny. Great question. I think it's multiple different things. I'll now talk on the technicals. But I think just the biggest driver has been really an improvement in our ability to market our gas locally as the GMPs continue to mature their systems and build in redundancy and we've worked with our gathering processing partners to at split connects in really strategic areas, we've really improved on our flaring metrics and thus, we've improved in our gas processing and selling gas.

It doesn't feel good to sell it at a negative price, but we've gotten to a point where we've really gotten a lot better at and marketing the gas downstream. And that's the biggest needle mover and I'll let Alb cover any other of the technical background on the gas number?

Yes, not really much in terms of well selection in this quarter associated with the gas production -- we brought on a couple of pads in the southern end of the Midland Basin that were a little higher geo orbit, but that really didn't drive the beat on gas. It's really related to what Danny mentioned before. But with the targeting of the art the Barnett, becoming a bigger portion of the development plan moving forward. I would expect to see that number kind of creep up a little bit.

And then my follow-up is, if you can give us some -- a lens into what you're all seeing on the oilfield service class front, any kind of inflation pressures and when you look at this higher production base you're running at, when you think about like -- I don't know if it's good to think about like just kind of a steady-state maintenance pace exiting this year? Like what is the quarterly capital run rate you all see right now?

Yes, another good question. I think we have optics into some inflation mainly tied to some of our consumables. Obviously, we talked about full costs in the past with the rise in commodity prices, and that's still here.

Thankfully, we -- our biggest fuel consumption would be on the completion side with the frac fleets, but all of our frac fleets are currently electric fleets. So we've kind of mitigated that inflation hurdle through utilizing the electric fleets. What we've seen -- what we're seeing in the future, casing prices in the back half of the year are going to come up -- that's really the big needle mover.

We think it's about 1% -- a little over 1% of our total well cost and inflation. So not much, and we think we can offset it with efficiency gains. It's a little early to talk about '27, but I think somewhere around $1 billion to a little over $1 billion a quarter run rate. The whole production flat is reasonable with what we see today.

But if we continue to add rigs in the U.S., and I think we're up 60 rigs from the bottom, if we continue to go and there's some forecast up there upto 80-ish rigs being picked up. We anticipate we're going to see some more pressure. But time will tell and what happens in the gas basins, along with what happens in the oil basins, what activity does. And as we get closer to '27, we'll be able to talk to you guys more about what we anticipate inflation to do. But right now, that's where we're at, and we're going to try and fight the variable cost side of it, like we've always done and drive efficiencies to reclaim any inflation we see on the consumables side.

Our next question comes from the line of Arun Jayaram from JPMorgan.

I was wondering if you could provide an update on what's going on in the field with the Barnett. It looks like you're running 3 or 4 rigs targeting that play right now in the basin. But I was just kind of interested in your focus on reducing cost from $1,000 a foot to $800? And how you plan to lean into that program in 2027?

Yes, Arun, I mean stepping back to earlier this year, we did a big reveal in our Barnett position. Since then, that position has continued to grow, continue to block it up as well so that we can have longer lateral development as we start developing the position aggressively, basically now. Our first 4-well pad, the Spanish Trail has been drilled and will be completed in the next couple of months.

So it will be interesting to see full section results kind of end of the year into next year. Obviously, with the Viper minerals, that's going to be a very high-return project. And that will also give us a really good idea into the cost side, right? I mean since the beginning, it's been a couple of wells here, a couple of wells there. We haven't done a full section with a e-fleet simul-frac crew getting the cost down on the completion side.

I will say, we're seeing wins on the drilling side. I think we're more on our front foot than anybody else in the basin on Barnett exposure and drilling costs. And they're getting closer to $400 a foot. I think we have 5% or 10% to go. There have been a couple of wells below $400 a foot, but I think we expect to consistently get to around that $400 or less per foot number to make returns competitive with the base plan.

Got it. Got it. Okay. And then my follow-up, I was wondering if you could give us some details on how the enhanced oil recovery program. I know you did a pilot of 50 wells, and I think you're expanding that pilot to another batch of well, maybe just give a little bit of an update on what kind of well productivity improvement you've seen from chemicals and surfactants. And do you plan to evolve that program into new completions?

Yes. So I mean just like we think the gas, power, AI theme is a mega theme, I think on the oil side, enhanced recovery or improving recoveries out of this basin is going to be a mega theme as well on the oil front. I think generally, given our size and scale on asset base, we certainly need to be -- as we said in the letter, we need to be on our front foot on this. I don't think we need to be tip of the spear, but we certainly need to be spending dollars to understand what's happening and that project kicked off last year with our first surfactant program where we learned a lot.

And I'll let Al update you on what we're seeing today and what we expect in the future. But my high level is you're going to hear a lot about all this kind of stuff from large operators over the coming years.

Yes, Arun, we -- so we executed a 12-well project this quarter and are in the process of flowing those wells back currently the initial results are very positive. And I think we're going to take the learnings from this batch of wells in terms of what rock tag, what reservoirs this technology is really suitable for and take those learnings and apply it to the next group of wells they will be doing in Q3. So I think we're just scratching the surface on the potential for this technology, and we're really excited about it going forward.

Yes. I think there's 2 ways to think about it. I think it either reduces your base decline or the replacement of capital for something that's higher returning -- to date, we've only done remedial work where we go back in existing wellbores to learn about this treatment process, but we are now also incorporating it into some of our pads where we have on the new wealth side, where we have a control half of the section and a surfactant half of the section. So moving with haste and learning a lot pretty quickly here.

Our next question comes from the line of John Freeman with Raymond James.

You highlighted a number of impressive operational achievements in the letter. And the one that really stood out for me is just that first full quarter of continuous pumping over 21 hours of average pumping time per day, which is kind of hard for me to even wrap my head around. But just sort of what's like achievable there? I mean like is it like in a couple of years? Or are we going to talk about something that is bordering on close to like 24 hours or something? Just trying to understand what's even -- what's achievable there.

John, yes, thanks. Great question. We continue to try and push the manufacturing mode kind of mindset with regards to the surface operations on the completion and I think it's 24 hours in a day. So I don't think the team is going to quit until they can get to a point where they're pumping a full 24 hours. In reality, there is maintenance associated with the equipment on location and every piece of redundancy costs money.

So there's a balance between adding more equipment out there to get redundancy and how many hours in a day you're pumping. And that's been the fight with the team on doing tribal frac work versus final frac work and those things. But they continue to look at how do they push efficiency, push pumping hours and push rate to get more done in a single day.

I think we've seen some pads that we've -- we broached the 5000-plus foot a day on average. And 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. And so I do think that's achievable and something that we can hopefully talk about in the next year or so when they get to that point. But they're working on it. They're applying new technology at the surface and continues to get better.

And then just 1 housekeeping item. It looks like there was some bolt-on sort of acquisitions during the quarter, looks like kind of net of divestitures like $385 million. Is there any production that was associated with those transactions, just anything else we should be aware of?

Yes. Very little, John. I mean, we're continuing the Barnett leasing play with our partners at Double Eagle, so that's continuing onward. And I'd say outside of that, I've actually been very pleased that the team has been finding, call it, $20 million to $100 million deals to either net up or extend laterals or block up our position. And they've been finding them pretty consistently. I mean, about kind of 1 sizable deal a quarter. And I think looking into Q3, we got another couple of small ones.

So those don't get headlines, but they add up, right? All of this ties into our corporate NAV, higher working interest, longer laterals, should result in a higher stock price.

Done with cash, which is important, John. And the thing I'll say about the Barnett position we built, we built that at very low cost of entry with cash. And that position is worth multiples of that today, and that should just accrue directly to shareholders.

Our next question comes from the line of Phillip Jungwirth at BMO.

I'm curious when you look at the mid-cycle NAV, which I think you mentioned earlier, you feel like went up during the quarter. Obviously, oil price is the main driver here. I think you can see release around 65. But -- the question is more just how much do you think some of the operational improvements and resource expansion initiatives you've achieved can contribute to a higher NAV plus just more volumes or growth.

So just wondering how meaningful overall these are based on your assessments to value and whether improvements in the business can contribute to the thought process around intrinsic value and future capital returns.

Yes, it's a great question. They want 100% do, and I'll take you down a little bit down memory lane here. We put our buyback program in place post COVID that I think, Q3 of 2021, and we told investors we were going to buy back shares at a mid-cycle price at a rate of return above our cost of capital. And that initial top was $90 a share. And here we are, 5 years later, we've obviously done a lot in terms of M&A the asset base has expanded from a zone perspective, things like the Barnett, things like Jo Mill, Middle Spraberry weren't big things in 2021, Upper Spraberry obviously, the cost structure, the lateral lengths.

I mean everything that the team has done in terms of execution in the field, but also adding to the asset base in an accretive manner has resulted in that top going up significantly, more than doubling since that moment. So people ask me what's the future value creation opportunities for Diamondback. And if you look back 5 years ago, and you say we doubled the value of the company at the same at the same parameters, right? We've stuck to our guns on what we think mid-cycle is from a price perspective, we stuck to our guns on what the rate of return is. But the rest of the business has driven those improvements and I expect that to continue.

That's great. And then on the shovel-ready Power project, where is the value creation for Diamondback on a project like this? Is it more utilizing the surface acreage, the gas supply deal or partnering on the data center cooling, which I assume would be deep blue, but let me know if you're thinking of it otherwise. And any color you could provide around the distributed power piece that you referenced earlier? .

Yes, Phillip, it's Jere. A great question. I think the biggest driver for us is just having a new in basin res solution for nat gas. We're setting aside $200 million to $250 million a day for this project. And when you think about contract structure, ideally, you're getting something that's like a Waha plus with a 4. And for us, based off of what we've seen over the past couple of quarters, this would provide a material uplift. You're exactly right. As it relates to the other revenue streams, this could have a material benefit for Deep Blue, of which we own 30% there's some land proceeds that likely could come through the door, either as a onetime payment or structure as the royalty. And these are just kind of scratching the surface of what we're seeing. So really excited about it. But I think nat gas is the one that we're focused on.

Yes. I think the 1 thing I'd say is we -- this is the first step in what I think will be a long process, right? This is us planting our flag proving we can do this. We can make money for our shareholders, but also partner across this tech space. And I think it can be repeatable. You get 1 of these done, you have a blueprint to get round 2, round 3. And if you hear the numbers that the tech guys throw about in terms of what kind of power needs they have this could be meaningful over time for Diamondback. .

Our next question comes from the line of Kevin MacCurdy with Pickering Energy Partners. Kevin, you are live.

I guess for the first question, I'll stick on the operations front. Maybe you can expand a little bit on what you saw on productivity and costs on the U-turn wells. And how you might be integrating that into your plan heading forward? .

Yes. So great question. We haven't completed the 6 wells that we've drilled thus far. We're still in the middle of developing that pad. I think on the drilling front, it was certainly a success for us. There's some things that we learned and some challenges we saw, but we still saw lower per foot well cost than drilling stand-alone 7,500 footers. Now we've completed some turn wells that we inherited from an acquisition and those were short 5,000-foot U-turns a 10,000-foot total lateral length and everything went great on the completion front with those.

But this will be our first fully developed Diamondback pad. We just haven't gotten it on production yet. But as far as the pad we inherited productivity-wise and execution wise, it was in line with what we would see from a regular straight 10,000-foot well.

Great. And as a follow-up, maybe I'll hit on LOE. It looked like it fell below $6 a barrel and was partially drove the EBITDA beat this quarter. You kind of talked about some of the reasons for that. Is there any structure on there for that to continue? Or how are you viewing LOE for the rest of the year?

I think if you look at the top line CapEx number, the dollars were actually flat quarter-over-quarter. So the LOE beat was driven by the production beat. I think the team has done a really remarkable job of fighting off some of the cost pressures we're seeing from power, from water and doing the things that they can -- they do the little things they do to save $1 here and there that adds up. And I think we're still going to see -- I don't think we're going to see LOE trend down in the back half of the year. I think we like that kind of circling that $6 number or a little higher.

But I think if we continue to see volume outperformance, we can see some upside to that number. But I do believe that some of this inflation stuff we have on power and water and tubulars will flow through on the top line LOE number as well. So the team feels pretty confident in that $6 range. But again, the denominator is a pretty big number. So it was just a great quarter on the productivity front and help drive the beat on OpEx.

Yes. But I'd also say that the KPIs that we track that the team can control on LOE look as good as they've ever looked. And as well as some of the things we've done in the field post Endeavor integration, integrating 2 large field organizations takes a little longer than the office, but we're starting to see the benefits of that. in terms of moving to a pump by exception company, a lot more automation. I think that AI is helping diamond back in the office today, but I think AI is going to be an automation are going to be very big drivers of the production base either shallowing or costing less to maintain. .

Our next question comes from the line of Doug Leggate with Wolfe.

Thanks, guys, for having me on. So I've got a couple of things. The first one, I want to take you back to your first comment about the trade-off between the balance sheet and your buybacks, I think you've been more vocal than most about avoiding pro-cyclical share buybacks. But you could make -- you could do some serious damage to your balance sheet with the kind of free cash flow you're generating. So my question is, where are you prepared to take that to in terms of building cash and balance sheet as opposed to going after debt redemptions, but actually just sitting cash, so it was just net debt. That's meant my first question.

And my follow-up very quickly is the capital efficiency is extraordinary. Our latest type curves are significantly above 2025. You've run through a number of reasons why that's happening. My question is, would you take the capital efficiency and lower your spending in '27? Or would you take the incremental production and keep the CapEx flat -- and I know you talked a little bit about growth, but just curious something to tradeoff between those 2 things as well.

Yes. Both good questions. I think there's a near-term discussion and a long-term discussion on both of them. I think on the debate of taking productivity and reducing CapEx or increasing production. I think today, in today's market, we made that decision to spend more within our budget, but growth is the output. I think there's going to be a debate throughout the year. Some years, it's going to be obvious to grow organically. In some years are going to be like 2025 and 2024, where it made sense to cut the CapEx and return more cash to shareholders.

So I think we'll maintain flexibility there, Doug. And I think that also then ties to your other question, which is where are we prepared to take the balance sheet -- and I think that there's some near-term aspects that we want to cover, right? We want to put enough cash on the balance sheet to take care of our 2026s which are callable in a couple of months and also take out or be prepared to take out our 2027. And that was just in a position where we could build cash beyond that to tackle the maturity tower we have kind of in the 2029 to 2032 time frame.

So I'm certainly not afraid to put some cash on the balance sheet. I think it's a good idea, it's prudent at this point in the cycle because we know that cycles turn. And the 1 thing I will say to give investors comfort is we're not building cash here to do big cash deals and blow up the balance sheet, doing deals.

That's not a year for were to growth -- we still want to grow the business and look at opportunities. But if you look at our history of how we've done M&A, it's very really been a significant amount of cash in any of these deals.

Our next question comes from the line of Geoff Jay with Daniel Energy Partners.

Just wanted to follow up on what you said earlier, case about the deployment of AI and like predictive maintenance and remote sensing, et cetera. How far down the pike are you on that? And I guess, what's the time line look like to you kind of for the deployment of those technologies out there to try to improve your uptime?

Yes. I'll let Chad or Danny give the details. I mean I think on all of this stuff, we're in the first inning, right? There's just -- there's so much that we can spitball and debate internally what could happen. I mean, I think in 5 years, we're going to look back and say, we were such rookies at all this stuff, and it's going to be a huge help to our production base. But Chad, anything we're doing it?

Yes. We're really excited about the progress, but it is incredibly early. 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. And then the team is doing a great job just managing downtime with some of these tools, and that's been an incredible value add. So still very early but lots of room to run.

Yes. It's kind of a numerator denominator thing, right? The lower downtime, lower spend, lower decline rate, okay, then we don't have to spend as much capital to sustain production. So I mean just a 1% move in that decline rate which we've been fighting for a long time, it can make a big difference.

Our next question comes from the line of Paul Sankey with Sankey Research.

Can you hear me okay? .

Yes, Paul, we got you.

Kaes you mentioned the NAV, you kind of coy about but you said that the NAV went up more or less during the quarter. Can you just talk a little bit more about how you think about the NAV, particularly first of all, obviously, on the upstream performance side. I don't know if you want to throw the oil price in there, but also the other businesses and whether or not it's still a key driver of buyback attractiveness?

Yes. I mean high level, we try to keep price constant, right? -- reducing your NAV by changing price, I don't think is the right way to look at it. So I think generally, Q2, we obviously generated a significant amount of free cash flow above that mid-cycle price. So that helps NAV. But I also think as we're looking at type curves and well performance and the Barnett development, 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. And so I think as those things continue to develop and we refine our analysis, they should continue to go up if we're doing our job. .

I think on the other businesses, I don't -- certainly don't have any power value in our NAV. We do have a good amount of midstream value with our Deep Blue investment. It's been interesting to watch multiples, expand on the water side of the equation as I think more attention gets brought to that business line in this basin. So I think we're going to be very money ahead on that investment. But all of that ties us together and a reduced share count and a lower net debt value pops out of a higher per share value.

Our next question comes from the line of Gabe Daoud with Truist.

Kaes, I was hoping maybe you could get a little more color on just the last point that you hit on, on the water side. Is there anything that you're seeing just given some of the changes the RRC has made to injection. Are you seeing any constraints at this point or maybe concerned about constraints moving forward?

Gabe, good question. I mean you haven't seen anything yet in terms of constraints on our system. I mean, I think what this means is you have to have significant capacity. You have to have a large interconnected system, the days of 1 or 2 SDs being hooked up to the system makes no sense. And I think we have that valuable partnership with Deep Blue where they are investing capital to loop certain lines, connect certain areas add SWD capacity to make sure that those issues don't happen to us. .

The water discussion is certainly getting a lot more attention in this basin. I think the Delaware Basin, obviously, given the amount of water produced there is working to solve these problems probably sooner than the mid basin will need to. But I think there's a lot of lessons and a lot of learnings that we're following from what those businesses are doing over there or companies are doing over there that we can translate over here. But in general, I would say, Deep Blue has used the acetate 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.

Okay. That's helpful. And then just a follow-up. I think this year, you had non-D&C spend of $600 million across some science and midstream. Just curious how does that change into '27? Does the Barnett like require any incremental midstream or facility spend that maybe we're not thinking of? Or is the answer there, no?

I think generally, the number will go up slightly. But within that number, the mix will move. As we get to large-scale Barnett development in areas where we don't have existing infrastructure. We're going to have to build new batteries. And we're working on that design and making that design tailored towards what of our net well look like versus what Wolfberry wells look like. So as in any deal or any expansion, infrastructure capital is higher in the beginning and then reduces. But I think generally, that number is close with a little bit of upside next year.

Our next question comes from the line of Derrick Whitfield with Texas Capital.

Congrats on a solid update this quarter. Wanted to start on the operational front. Could you speak to some of the design changes you incorporated this quarter to drive lower equipment costs per well?

Yes. I mean I think generally, high level, it's been the combination of how Endeavor was doing things and how we were doing things and finding the best of both on the equip side. I don't know, Dan or Al, do you want to add any detail.

I mean a lot of it is driven by just extending lateral lengths, right? I mean that's the biggest lever we have to pull. And it's 1 of the reasons why we're starting to lean into some of the U-turn development because we talk about a lot, like what is the efficient frontier for lateral lengths. And can we get to a point where our average lateral length continues to creep up beyond 12,000 feet and it just drives so much more efficiency. And so that's really what you're seeing. The biggest change is just a little longer laterals, and you need the same flow line and the same tubing and all that for that well, it just drives down your per foot cost.

And I think some things have come out of the scope as well. So we're always looking at each little line item. But Danny's point is the equip piece and the infrastructure piece, that's nonproductive capital, right? And we want to minimize the non-oil-producing capital in our CapEx budget. .

Great. Makes sense. And as my follow-up, maybe I wanted to touch back on the EOR question from earlier. Could you speak to the lessons you guys have learned so far and how you're thinking about broadening this program as you look out beyond the first 50 wells?

Yes, Derrick. Great question. Really it's figuring out which rock types and methodologies the technology, the specific surfactant technology, we're applying works best in and where we're seeing the best returns -- and then looking at the overall portfolio of the thousands of wells that we operate, where are those rock types situated -- and then thinking about sort of the chemical composition of the surfactant and which ones are working fast and which different rock types. And so that's sort of the ongoing process.

Like I said earlier, I think we're really just early innings on this, and the team's learned a lot. And the initial results that we're seeing from this 12-well package are really promising. But we're going to learn a lot from these 12 and apply a set of next here of wells that we do in the future. And I think this is something that like Kaes talked about earlier, where we could see some shallowing of the decline rate in the decision on do we take capital out of the system or do we lean in. But yes, overall, that's sort of the details of where we are today. .

Our next question comes from the line of Charles Meade with Johnson Rice.

To you and your team. I wanted to go back to your shareholder letter and your theme of volatility and see if you maybe share your view on the macro -- we've been living in the world with a lot of volatility. But I'm curious, we see some this morning. But I'm curious, do you think that stopping the bombing and opening the study from us is what's going to kind of end the volatility? Or do you -- are you anticipating that there's been some structural changes in the oil market that even if we do get these agreements that we're living with more volatility going forward?

Yes. I mean, listen, I think it's been -- it's probably not our place to comment on geopolitical events and instead focus on global inventories. And I think the relationship between inventories and price has broken down a little bit over the last couple of months, but I think that's probably because there's noise in the system.

Someone smarter than me explain the market as basically a sine because of everything that's happened and everything has been disruptive -- and at times, there's going to be heightened volatility on the upside and heightened volatility on the downside with steady state far from a possibility today. So I think generally, chasing headlines over the last 3 months has been exhausting. And I think we've decided to just kind of put our head down and believe that crude oil that comes out of inventories today has to be replaced tomorrow. And over a multiyear period, that should be that should result in a bid for oil for a longer period of time here.

Got it. And then Second question on Wolfcamp D. You wrote about that in your shareholder letter that you've been driving down cost there. And if I look at Slide 11, it's actually interesting that looks like the Wolfcamp D is actually the biggest rate of change from '25 to '26 as far as your lateral footage. So I'm curious, 2 things. which direction does the causality work there? Are you getting the cost down because you're just -- you're drilling more of them and learning more? Or is it the other way around that you're drilling more because you've gotten the cost down? And perhaps you could also talk about what the other side of the equation there, what you're seeing in productivity trends in the Wolf candy.

Yes. So from a cost perspective, the team had a budget of like $3.50, $3.60 a foot and their stretch goal is to drill wells at $300 a foot, and they're actually hitting their stretch goals. So that does improve the returns of the Wolfcamp D what has brought more Wolfcamp D into our program is that when we merge with Endeavor, they had some acreage and kind of the sweet spot of the Wolfcamp D kind of Midland County, Eastern Midland County versus where our prior asset base didn't have as much upside.

But in general, as these other zones get more airtime, I want you to pay attention to productivity because traditionally, if someone brings in -- the company brings in a lot of secondary zones that they hadn't been developing to date, their productivity per foot takes a hit and our productivity per foot, while adding these zones has been consistent to now up this year. So credit to the team, but I think it's also just a combination of a larger asset base with more places to allocate capital post endeavor.

One moment for our next question. Our next question comes from the line of Leo Mariani with ROTH.

There really hasn't been much in the way of Delaware Basin activity over the last handful of quarters. Can you just give us an update kind of what's planned for that asset? Is that just going to kind of sit there and kind of slowly decline with time is something you're going to look to get back after kind of later on down the road? Just any color would be great.

Yes. I mean, while there's no capital being allocated to the Delaware this year, there are some interesting things happening over there. We've done some farm outs in the second Bone Spring in our reward position. Those produce some really good results that unlock some inventory that we probably didn't think was as competitive a couple of years ago as it is today. We see a lot through our Viper lens. And I'll tell you the leasing in the Delaware for Viper has been significant year-to-date, there's a kind of a Delaware Woodford trend that is getting a lot of attention, some big wells, they're expensive wells, the big wells and some leasing going on there.

So there's stuff going on beneath the waves, but no major capital allocated there this year or likely next.

Okay. And then just on EOR, I know it's kind of early days, and you guys are still analyzing results. But at this point, do you think that you've had clear economic benefit at least some of the wells out there, maybe not all of them, I know it works better on some versus others. But are you convinced that there's economic benefit in terms of incremental capital that's gone into some of those existing wells?

Yes, 100%. We just got to figure out -- we've got to learn about what's happening. Some wells saw 0 uplifts, some well saw production triple or quadruple versus where they were before. And the average was somewhere in the range of 150 to 200-barrel a day well going up by 100 to 150 barrels a day, but the dispersion is just so wide. And so I liken it to Wolfcamp B frac in 2014 versus old camp B frac today. These are Wolfcamp B fracs from 2014, and we got to figure out what's going on beneath the surface. And I think with the quality of the data and our ability to process it as quickly as we can today is going to allow for continuous improvement. .

Thank you. This concludes the question-and-answer session. I would now like to turn the call back over to Kaes Van’t Hof, CEO, for closing remarks.

Well, thanks, everyone, for the time and the questions. We again used up a full hour. I continue to be impressed with the analyst community. So thank you for the time.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.

Good day, and thank you for standing by. Welcome to the Diamondback Energy First Quarter 2026 Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your first speaker today, Adam Lawlis, VP of Investor Relations. Please go ahead.

Thank you, Cory. Good morning, and welcome to Diamondback Energy's First Quarter 2026 Conference Call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback website.

Representing Diamondback today are Kaes Van’t Hof, CEO; Danny Wesson, COO; Jere Thompson, CFO; and Al Barkmann, Chief Engineer. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.

I'll now turn the call over to Kaes.

Thanks, Adam, and welcome, everyone. As with the last few years, we're going to go straight into Q&A. So operator, please open the line for questions.

[Operator Instructions] Our first question comes from the line of Neil Mehta of Goldman Sachs.

Yes. So I guess the big development here today that you've been signaling is the move to a green light framework from yellow light, adding the 2 to 3 rigs and moving to the fifth completion crew. So maybe you can just take a moment for the investors on the line to talk about the thought process that went into this decision and just how you're thinking about where and when to add activity?

Yes, Neil, I mean, it's a good question. I think there's some macro elements as well as some micro elements and we'll go through both of those. I think from a macro perspective, obviously, there's a clear market signal. We're 2 months into the world's largest oil supply disruption in history. And I think Diamondback and Diamondback shareholders are very fortunate that we're solely based in West Texas, we're kind of tourists in this situation, but it's obviously very serious situation with a lot of oil supply off the market.

And so if that isn't a signal to grow production and an advantaged area like the Permian Basin that I don't know what is. And we hope there's a resolution to the conflict. But even if there is, there's a lot of noise in the system and a lot of barrels that have been taken off the market. So that's kind of the macro signal that we've been looking at as a Board and the management team, Obviously, global inventories are starting to decline very rapidly, and we're going to do our small part to add some production into the mix. And then you go down to the micro level or the Diamondback level, I mean, listen, with the best inventory, quality and depth in North America being executed at the best cost structure.

If this isn't the time to grow now, then I don't know when it is. And so that decision at a micro level was honestly fairly easy. And I think the last piece about it is we're able to do this in a very capital-efficient manner and get it done very quickly. Because we have this backlog of DUCs and we prepare our business for up, down or sideways, we're able to just make one decision and had a frac crew a lot earlier in the year and get that production up immediately. So I think it's a testament to the team's preparation, everybody in the organization working together and be able to do this very, very quickly, whereas I think in other organizations, it might take a little longer to make that decision.

And then the follow-up is just on the return of capital framework. You didn't move away from the fixed framework in while you bumped the dividend, you indicated that you might be slowing down the buyback a little bit. So can you talk a little bit about that what you intended to communicate with that? And then there is a very concentrated 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 as a logical buyer to help offset that potential risk on the stock .

Yes. I mean, let's take it a little higher level, right? I mean I think allocating capital is the most important job we have to do as a management team. And the history of the return of capital program for both ourselves and the industry was put in place after the COVID near extinction events of the industry and investors said, "Hey, I will my money back and I wanted in a formulaic manner. And I think that's worked very, very well over the last few years.

And I don't 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. So we have a really, really 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's a very positive rate return for our stockholders, and I expect that to continue. We recognize you also have a large shareholder that we found a way to help monetize their stake in a very efficient manner.

And I think outside of their stake, they're most focused on us creating long-term value. and 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. So I wouldn't expect anything to change. We have a great relationship with the family. I think we have the ability to help them monetize. And if we use kind of excess free cash flow over the next couple of quarters to pay down debt, we can help monetize their stake actually more efficiently coming out of this. They're long-term holders, and they want the stock higher.

Our next question comes from the line of Scott Hanold of RBC Capital Markets. .

We all had some pretty robust production performance in 1Q. And based on our chat last night, it sounds like you're -- completions are playing. Can you just walk through some of the specifics why performance was so strong? It sounds like there was a lot more well performance just versus any other kind of dynamic just give us a little bit of thought on that. And is that something we should anticipate moving forward and what's embedded in guidance? .

Yes, Scott. I'll give a couple of high level and I'll let Danny talk about some of the details, but high level, our well performance year-to-date looks up relative to last year. And I think that it's probably a surprise even to us internally, but we've always continued to try new things in terms of completion design, and efficiency that I think is starting to pay dividends.

So I think that's helping. That's one thing. I think the other side of the business, the production side of the business, which we've been talking a lot about over the last couple of quarters, there's just kind of A lot of good things happening in the field in terms of less downtime, more automation, call it AI, call out automation impacting that side of the business. So I think better wells and lower downtime, that's a good recipe for production beat.

Yes. Scott, kaes alluded to it, but we -- post the Endeavor merger and getting the team together, we started trading a lot of ideas on what we were doing to really optimize primary completions as well as the base, and we've talked about it over the past few quarters, but some of the things we're seeing on the completion optimization side with perforating strategies, rate design and sand loadings we think we're seeing some uplift in the wells and time will tell as we continue to implement that completion design. But also on the production side, some of the stuff we're doing on the workover side, some of the acid jobs, the coring to oxide jobs, the [ surfactant ] jobs, we're starting to see that pay dividends. And and really layering on that machine learning, as we continue to look at our data streams and processes and and layered on machine learning and trying to start working towards implementing AI into our field operations, we're seeing that downtime come down, and it's been a big part of our -- of the beat in Q1, just really that little bit of optimization across the board starting to show through to the top line number.

Great. And as my follow-up, when you guided oil and you talked about like a -- it looked like you're referring greater than 1050 a day. Can you just talk through if you continue to see this macro environment, is there how much desire is there to kind of continue to let that oil production grow versus curtail it? And is there a scenario where you actually even look to step it up even higher if the macro continues to be heightened.

Yes. I mean it's a great question, Scott. I think it's kind of a -- it's a very fluid situation, and I think the board wanted us to take this kind of quarter-by-quarter. Obviously, if there's outperformance and then we still have triple-digit oil prices and the market is still calling for oil to come to market.

And I think this is a year where instead of pulling back activity, you kind of just keep the efficiencies going and production continuing to climb. But listen, it's going to be it's going to be fluid, right? We're only 2 months into this conflict and it could be resolved today, but -- and who knows what happens in the macro. So I think we're just ready to react. We still have some things in our back pocket to grow further. But for now this kind of 520-plus 000 barrels a day on oil is the new baseline.

Our next question comes from the line of Neal Dingmann of William Blair.

My question is also on your activity. Specifically, case, how much, if any, will at negative Waha prices impact what you might or might not do? And then the same question with oil service prices and maybe ask about are you expecting [indiscernible] inflation given what's going on with prices?

Yes, Neal, I mean on the Waha side, obviously, the pricing is deeply negative. We're well protected with financial and physical hedges our mix of physical to financial is going to be moving more towards physical when these 2 new pipes come on, hopefully, second half of the year. So I think we're pretty well protected to get through this tight spot from a financial perspective where we can continue to add oily inventory, right, where we're drilling some of the oilier stuff in the basin.

So I think we're pretty well protected there. We'll continue to work on our physical protection on the gas side. We've worked on a power project now for almost a year, and we'll see if we can get that done. But we talked at length about monetizing our gas, and we're kind of on the cusp of that. That's starting to happen here when these pipes come on. But Danny, on the service side, what are you seeing?

Yes. I mean we haven't really seen much pressure to date on the service inflation or service pricing side of the story. It's really a capacity question and what does the service capacity look like and haven't seen industry activity ramp aggressively the release first couple of months of this conflict. And so there's still quite a bit of capacity out there in the rig space and in the completion space.

And -- we're -- the calendars are not squeezed enough yet for them. I feel like to be able to push pricing on to the guys when they go out and look for this additional equipment. We have seen obviously some inflation in some of the consumables and things that are tied directly to the commodity price. But those have been pretty minimal thus far, and we'll just have to see what activity does. -- not only in the Permian, but in the Lower 48 to see what we anticipate service inflation to do through the rest of the year.

And then second question just on capital allocation, especially given the continued record free cash flow growth per share you'd likely have a just wondering specifically, how do you believe capital for M&A stacks up maybe against buybacks or simply the near-term debt repayment, I mean do you factor that in? Or maybe just talk about capital allocation.

Yes. I mean, Neal, I think my first day and my first finance job in New York City, I was asked the question. What can the company do with their free cash flow. And if we're going to go through all the options, you can grow, right, either organically or inorganically. So organic growth, we've decided to hit that lever today in a small way by going to the top end of our CapEx guidance. Inorganic growth, which is M&A. We've obviously been very, very good in M&A over the years.

I think this volatility is kind of difficult to get deals done, private or otherwise. So I think generally, M&A is probably fairly quiet at Diamondback for the foreseeable future. Then you go down the other options of what you can do with your free cash, you can pay up as dividends, which we did and decided to increase today. or you can pay down debt, buy back shares or you can just put the cash in the balance sheet. And I think with oil prices where they are, I don't know if investors are capitalizing this price environment yet today. And so for us, the bigger use of free cash is going to 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, and it can it can flip pretty quickly.

Our next question comes from the line of Arun Jayaram of JPMorgan Securities.

Case, the calendar '26 and '27 strips are around 90 and 75. How do you think about your approach to development in a much stronger oil price than we sat just, call it, 90 days ago. And I was wondering if you could just maybe highlight for the 2 to 3 incremental rigs, how does -- how are you thinking about capital allocation across your asset base? And is the deeper benches now an area that are now competing with capital as you get down some of those well costs in the Barnett?

Yes. I'll let Danny and I'll talk about latest far net developments. But just from a capital allocation perspective, even with higher commodity pricing we're still going to hold to the vast majority of our spacing assumptions throughout the basin. We always got to look at each project, and that's kind of on a DSU by DSU level basis. and kind of say, "Hey, let's get as many wells in this section as possible to where the incremental well, the last well that we had generates a 40% rate of return at $60 oil.

And so we think that provides prudent spacing, but also a solid rate of return to our shareholders despite the commodity price volatility. So I think drilling our best stuff first and sticking to that knitting in terms of spacing is going to continue. Clearly, the Barnett, particularly with the size of these wells from a production perspective generates more PV today, so that's getting more attention. But Al, do you want to give anything on the latest Barnett?

Yes, I think that's right, Arun. I mean looking at the acceleration of the plan coming in with these 2 rigs, really that's the acceleration of the Barnette [indiscernible]. And we're focused on that development and really, it's just kind of getting ahead of the Barnett obligations that we talked about last quarter.

Yes. And I'll just add that the Barnett activity and the obligation activity is almost entirely focused on the JV area that we have with another partner. And those wells are not as high working interest. They're about half and half, a little bit heavier weighted on the Diamondback side. So the 2 or 3 rigs are picking up on the Barnett activity to get ahead on the JV area is really like 1.5 net rigs at Dynamex. So well, the top line looks like we're adding a bunch of activity in the back of the year. Net to us, it won't be nearly as impactful.

Yes. Great. My follow-up is maybe for Jere. You guys have taken, call it, pro forma debt, I believe, net debt down to $12.7 billion, Jere, I was wondering if you could highlight, given the intention to pay down more debt and a higher commodity price environment, what are some of the targets you're looking for, for the balance sheet from either a gross or a net debt perspective?

Yes, Arun, great question. I think we've talked previously about hitting that $10 billion net debt figure sometime in the next 12 to 18 months. Obviously, with where we are from a commodity pricing standpoint and some excess free cash flow generation, it looks like we'll be able to hit that much earlier to the tune of a couple of months from now. And then as we move into the back end of the year, I think we'll have an opportunity to not only reduce net debt but also gross debt. So like we build cash on the balance sheet through the fourth quarter. And then once we get into the fourth quarter, take a look at, obviously, calling our $750 million of [ $26 million ] is outstanding.

And then as we move into 2027, take a look at maybe doing a larger liability management exercise with additional cash on the balance sheet. With the idea of trying to take out as much as we can from a near-term maturity perspective, particularly as it relates to anything that matures prior to 2030. So I think we're in a really advantaged position to move our balance sheet from a position of strength to really kind of an adjective of fortress, and we can do that in the very near term.

Our next question comes from the line of John Freeman of Raymond James.

Even after increasing our activity the reinvestment rate for you all still fell pretty sharply from what you are originally planning last quarter from 44% to 34% at the current strip. So obviously, you'll have the ability if you wanted to even increase activity more and still would have likely had kind of an industry-leading kind of low reinvestment rate. I know that returns ultimately drive all decisions, but is there like a reinvestment rate that you all just want to stay below regardless of kind of the commodity environment?

John, I mean, that's a good question. I mean I think I'd probably take it a little different direction where obviously, we've been pulling investors that own the stock to get their opinion on how they feel about growth and ramping activity. And I think the general consensus was Yes. I think a little growth in the plan will differentiate Diamondback and makes a lot of sense. I just don't want you to do it in a capital inefficient manner. And so if you think about what we're basically doing here, we were going to run somewhere between 4 and 5 frac crews in the model to hit our original guide. And that fifth frac crew was going to go away for 5 or 6 months and then come back. And it's a Halliburton e-fleet, simul-frac as efficient as it gets crew. And so we're just bringing that crew back and going to run the 5 crews essentially consistently. And I think that will ensure we maintain capital efficiency in the field versus trying to go too fast too soon. which sometimes drives -- has driven some inefficiencies in E&P's plans and Diamondback plans in years past. So I think trying to learn from the history of development in this basin, staying capital efficient is probably the priority and I think the reinvestment rate becomes the outset of that. .

That's great. And then just along those same lines, I know the original 2026 plan didn't forecast sort of any meaningful draws or builds. can you just give us a rough idea of kind of how that looks now with the new plan? .

Yes.It's kind of a story through the year, right? So we're going to draw down the DUCs and backfilled that with 2 rigs worth of activity to make sure we build our DUC balance back up, we're basically repeat it a little over 200 DUCs in Q1. That number is going to come down over and then the backfill rigs start to build that back up. So in general, and Danny can opine, but we're going to have to keep a little bit higher DUC balance than we would running 4 crews because we have -- we like to have 2 projects behind each crew ready to go because if something that happens and we just moved to another project, and it looks like everything is going great at Diamondback on a quarterly basis.

So probably need to maintain somewhere in the high hundreds, around 200 DUCs and -- that's kind of where we are today, but there's going to be some movement throughout the year.

Yes. I mean we like to keep kind of a quarter to 1.5 quarters worth of inventory ahead of each crew just so that we can have flexibility if we run into an issue on a pad with takeaway constraints or something like that. And so if you think about each of these crews we'll do about 100-ish wells a year, maybe a little more. And so to Kate's point, he hit the nail on the head, a couple of hundred wells ahead of these 5 fleets is kind of the right carry number of the DUC balance. But Obviously, the more efficient we get and the guys are always chasing the efficiency curve, and you can see it in -- I think it's Slide 9 in our deck today, the improvement quarter-over-quarter and as the crews get more efficient and get more wells done, it either means we got to release crews to keep the same well count or we got to build more DUCs to stay ahead of them. So it's a dynamic and fluid situation, but I think we're talking about adding 20 to 30 wells for the year in total. So -- and still being able to stay within our original guidance window, which we took the momentum from Q1 beat and just kind of kept it going through the rest of the year.

Our next question comes from the line of Betty Jiang of Barclays.

I actually want to ask about your crude oil marketing. So 1Q pricing was a bit stronger. Can you just remind us your exposure to premium price indices and yes, the marketing strategy in general on the oil side? .

Yes. I mean, from a strategy perspective, Betty, we learned from the kind of the Permian takeaway crisis of what was in 2018 that we needed to use our balance sheet to get our crude to the biggest markets. And for us, that was -- let's get more crude down the Corpus Christi and -- as well as Houston. And so we have -- if you remember, we invested in 3 pipelines. Epic [indiscernible] and Weatebster, all of which made our investors a lot of money, but also protected Diamondback from a commercial perspective. So we have about 300,000 barrels a day going down to Corpus on EPIC and Gray Oak. And then we have about another 100,000 a day going down Wink to Webster, feeding kind of refinery row in Houston. And so we're kind of pretty exposed to, call it, water-based pricing, even have 1 small contract that had some dated Brent exposure. So that's been really helping us out. And I think I think that's a good playbook for what we're going to try to do on the gas side, right? I think we're a little behind because oil is 90-plus percent of our revenue, and we've done a good job there. But the next trend is to improve that on the gas side. SP579192376 Got it. That makes sense. And then I want to ask about the acquisition line item in 1Q, there are just a few hundred billion. Are you guys seeing any organic acquisitions and maybe picking up bolt-on things that the pricing yes, can you just speak to that. .

Yes, Betty, this is Jere. There's a couple of small acquisitions that are in our backyard in the Midland Basin. As a reminder, in that line item, we do have capitalized interest and capitalized G&A., and that made up the vast majority there. So that plus a couple of small acquisitions and then let's call it $50 million to $75 million in leasehold files as well.

Our next question comes from the line of Philip Jungwirth of BMO.

Can you talk about how you're viewing Viper ownership and what's optimal for Diamondback just because you did sell some in the quarter, but still own 39%. The company's free cash flow outlook is obviously stronger so less need for divestitures. Is there any minimum level of ownership you kind of look to maintain? And how does that play into the overall capital allocation decisions?

Yes. I mean we did sell down a little bit of ownership in Viper. It's kind of a follow-on from the drop-down where we took the Diamondback side took a lot of stock from Viper in that deal. We could have probably taken more cash, but instead decided to wait and then sell a little bit here last quarter. I would say we're we're done selling Viper shares at Diamondback. I do think the growth opportunity set for Viper is pretty significant. So could there be a world where Diamondback's ownership is reduced through dilution.

I think that's possible. But no desire today to monetize any more shares. I think if you just think about where both companies are going to be from a balance sheet perspective in another few months, they're going to be well positioned to kind of do anything from an M&A perspective, and that's where we want it to be.

Okay. Great. And then in the 2022, '23 up cycle, private operators, they did drive an outsized share of rig additions overall oil growth. You guys have a unique view here being based in Midland. I'm just wondering how you'd characterize the ability to privates in the Permian to respond to what we're now seeing as far as higher oil prices versus a couple of years ago just because it also has implications for tightening of OFS markets?

Yes. That's a very important question and it's gone into our calculus on thinking about the market and thinking about adding activity. If you go back to that 2022 up cycle, you had a company like Endeavour that's now part of in Diamondback -- part of Diamondback, they went from 2 rigs to 15 rigs. The Crown Rock went from 2 rigs to 8 rigs. That's now part of Oxy in-cap North, which is now part of [indiscernible], went from 2 rigs to 6 rigs. Double Eagle is now part of us, combinations and Exxon went from 1 rig to 6 rigs. I mean, these were big moves on the private side. And back then, there was still a lot of private activity growth, particularly in the Midland Basin that has now been consolidated. .

So I think there's going to be private growth. I mean the private model has shifted to more of a smaller asset packages that they develop very, very quickly, farm in the larger operators positions there's been a big growth in kind of that northern New Mexico area. But by our math, right, that's 20, 30 rigs. It's not 100 rigs like it was in 2022. So I think they're going to move very quickly. I just don't think the volume impact will be nearly what we saw in that 2022 time frame.

Our next question comes from the line of Scott Gruber of Citigroup.

Maybe I'll extend upon the last line of inquiry kind of in light of what you just mentioned about the impact of the private case. How do you think about Diamondback volumes, say, over the next 5 to 10 years on an organic basis, do you think about Diamondback kind of being a in modest kind of growth mode over the next 5 to 10 years? And this may happen kind of step-wise when called upon by the market. But do you step higher during periods of elevated prices right today and then maintain that need level that net-net, you're growing? Or when commodity prices are soft, you you pare back on activity and let production fade back down? Just curious on how you think about the longer-term trajectory? .

Yes. I mean, is Scott, I think I'd go back to my earlier comment that the operator with the best inventory quality and the lowest cost structure with the longest inventory depth probably has the right to grow organically and the right to do that and creates shareholder value. So I think we've been talking about trying to hit the organic growth accelerator for a while now. We just haven't had the macro conditions to support it. But I think in a world of -- and who knows what's going to happen where mid-cycle pricing is a little higher, call it, 70-plus on WTI, 75 plus. I think that's a world where from a total shareholder return perspective, a couple of percentage points of organic growth really adds to the NAV of the business and adds to the long-term free cash generation. And that's going to one of the important points that we ran in the model this year was that this new plan generates more free cash flow in 2026 per share than any other [indiscernible] -- sorry, more free cash flow per share than any oil price above $60 oil. And so a $70-plus world, this is advantageous to shareholders long term.

It would certainly help differentiate Diamondback. And then turning back to the capital efficiency of the investment program. It does appear to improve on the margin with the the updated plan, but it's hard to separate the [indiscernible] impact from adding rigs in the Barnett, where you're still ramping on learnings and efficiencies. So just in general, how would you describe the kind of underlying trend in capital efficiency especially as you lap the impact of the doctor, I'll say, kind of into 2027, do you think you'll be able to show improvement kind of relative to the initial program this year?

Yes. Listen, I think things like duck draws and bringing back DUCs [indiscernible], when you develop, I mean, I think that's all kind of noise, right? So below that noise, the team is executing flawlessly. I mean we said records on the drilling side on 2, 3, 4-mile laterals, Wolfcamp D development, we gave the team a goal of $300 a foot for drilling down from $360 a foot drilling last year.

They're already at $300 a foot. Barnett drilling, we said the drilling guys need to be below $400 a foot to be able to get to $800 a foot to make the Barnett competitive with the base program, while we already put a well in the ground under $400 a foot. So I think at the highest level, the business is firing on all cylinders, efficiencies continue to improve above ground, but the big move also is going to be are we drilling and completing actually better wells, subsurface.

And those are all the drivers that -- that separate the noise of -- or are you drawing down DUCs this quarter or this month versus years past, and that's the long-term benefit to capital efficiency.

Our next call comes from the line of Derrick Whitfield of Texas Capital.

Perhaps for you, just 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're seeing in degradation of inventory quality across the Permian, clearly behind down and back .

I mean I'll take the macro question first, Derrick. If I wasn't long-term bullish, I'd be out of a job, right? So I guess we have to be long-term bulls, but but also think about in practical terms, where the situation is right now. And within 3 months, we went from the projected largest oversupply in history, which I think we can debate was not going to be the case to now the largest undersupply in history, and we're only 2 months in. So I think it's hard for us to move off our mid-cycle pricing environment, which is kind of a mid-60s TI kind of mid-teens NGLs and $3 gas, obviously with Waha dips.

But there's certainly a case to be made for energy security becoming a much more important being for the -- for countries around the world to think about, I guess, wearing my oil hat, that probably means more storage, more landed storage versus storage that you can buy somewhere that's in a riskier geopolitical area.

I think that means the U.S. barrel is more important than it's ever been. But again, I think it's early for us to say mid-cycle pricing has gone up by [x ] -- the way we do think about kind of our positioning relative to U.S. shale and where U.S. shales mid-cycle pricing is going is that we do believe the cost curve is going up. We do think operators have done a really good job with efficiencies, longer laterals, better development, but geologic time catches up to you, and there are certain clearly signs of degradation throughout the U.S. in terms of production or productive quality. So we just try to keep ourselves at the low end of that cost curve. And I think we've done a very good job on that front, both from an inventory depth and quality perspective, but also the cost at which we execute on that inventory. So I think we're very well positioned -- and I think it's a little too early for us to go higher on mid-cycle pricing today.

Fair enough. And then as my follow-up, I wanted to shift over to the Barnett referencing the playout line on Page 16. How large could you reasonably grow this position beyond 200,000 that you're highlighting on the slide deck. And you clearly have 1 of the most prolific buyers of assets and business working with us to certainly have that in our favor?

Yes. I mean we did announce this position after we thought we had a pretty solid position on what we could get. I do look forward to -- we have continued to add to the position in Q1, small on a small basis. But I think what's exciting is now we're just starting to do a lot of trades. A lot of the big operators have their Barnett physicians, and we're all now looking at how can we block up to 3-mile laterals, 4-mile laterals. There's obviously a lot of private equity kind of the small Midland-based private equity that's looking to build 6, 7, 8 section positions, those probably come to market.

So I think it's going to happen. I think the position is going to grow. But I think we have the sizable base we need to continue to grow it.

Our next question comes from the line of Kevin MacCurdy from Pickering Energy Partners.

Can you provide any color on the cadence of the net lateral footage per quarter throughout the year and also the lateral length per well we would assume the additional 200,000 lateral feet is back half weighted, any color there would help.

Yes. So I think it's going to be pretty evenly weighted here towards the back half, looking at Yes, we went up to kind of that 6.2 million lateral fee, right? So you're -- we're looking probably at 1.5 to 1.6 per quarter for the back half of the year there.

Great. And lateral lengths per well should increase throughout the year 2? Is that right? .

Yes. So looking at Q1, I think that was probably 1 of our lighter quarters, I think we were like 11.5% for Q1. And so we -- for the full year of 2026. We still expect to be at 12.9%. So we expect that to ramp kind of going through the back half of the year.

Got it. Appreciate that. And maybe as a follow-up, any updates on the surfactant [indiscernible]

Yes. So we had a big push for towards the end of the year last year, really wanted to get some tests in the ground and try some different surfacing combinations with some different rock types and understand what was driving the well performance there. And so we got those tests in the ground. We're looking at it team studying it. And so we're refining the process and plan to move forward with our next deployment kind of early this quarter.

Yes. And Kevin, one thing I'd add to that, we tested 5 wells or so last year. On average, I think we got 100-barrel a day uplift but some wells were up by 400 or 500 barrels a day and some wells were 0. And now we're trying to figure out what do we do right in the 400, 500-barrel a day wells and what do we do wrong in the 0s we're going to figure that out. This is version 1.0, and that's what kind of gets me excited, like I think from a high level, this basin and Diamondback, we're kind of on the cusp of some technological breakthroughs related to increasing recoveries past primary development.

And I think that's probably going to be a mega theme over the next 4, 5, 6 years that you're going to see a lot of dollars in time spent on. And that's kind of why we've held as much acreage as we have. We have some of the best oil in place in the basin. And we got some of the smartest people in the industry working on this to do what I think could be something that extends this basin's life by a decade or 2.

Our next question comes from the line of [indiscernible] at Truist.

Just going back to the return on capital framework and pursuing growth this year, which obviously makes sense. But just curious if you could maybe talk a little bit about what an upper bound of oil production growth would be for Diamondback. Again, assuming you have the green light on the macro. Is it fair to assume that it's 5% for Diamondback? Or would there be an environment where it could be even higher than that?

Yes, I don't want to get into a specific number. I mean, I think right now, we've already grown low single digits year-to-date. I don't think there's a ton of investor appetite for a large CapEx bump in something more than mid-single digits growth, but I think it's early. I think there's a lot of noise in the system and no one's really sure how this macro is going to unfold. And that's why I think we're keeping our cars kind of close to the vest here. coming out with a good forecast in Q1, and we'll see how the rest of the year unfolds. But just pulling investor appetite, I don't think there's a lot of appetite for something like the go-go days of 2017, 2018, we had multiple CapEx increases in a year and double-digit -- mid double-digit production growth. So we're going to keep it steady and capital efficient. And I think that's what we put out there today and kind of take this macro kind of quarter-by-quarter.

Got it. Okay. That's helpful. And then a follow-up for me would just be, is there any update on your surface position in light of maybe a new market entry in that regard, Curious if there's any update on the conversations you're having there?

Yes, Kaes alluded to it earlier as it relates to our power project, but we're still making pretty meaningful progress with our partners here and really view this power and data center opportunities is something that has a unique opportunity for us to use our natural gas in basin and advantaged pricing. I think once once we do get a project finalized, we'll be able to talk about it in more detail, but it continues to move forward. .

Our next call comes from the line of Charles Meade of Johnson Rice Charles.

As you and your team there. I'd like to go back to the -- I think the big question this morning of the acceleration of CapEx. Can you give us kind of an inside baseball account of how that how you came to that decision? And I can imagine it could be the case that your Board left with the set amount of latitude or alternatively, is this kind of thing where you kind of arranged in short order, maybe telephonic or Zoom Board meeting and you just had a quick in meeting where you made the case and then activate. I'm not so much interested in the sort of all tops of your decision, but I'm more trying to get some insight into how the dynamics for work for you guys as a fast mover in response in this volatile [indiscernible].

Yes. I mean that's actually a good question. There's a couple of things I'd say. I'd say our board is a very is a very nimble board for its size, right? We have 13 board members, but they are very responsive, and they move relatively quickly, particularly when the decision is very obvious. And second, I would say just some inside baseball. We've tried to -- I got some advice from Jamie Dimon last year, which was communicated with your Board often and tell them everything. And we just decided to overcommunicate with our Board through this crisis.

Obviously, the crisis kicked off just a week after earnings, right? We have set the budget, but I think we sent 3 or 4 notes to the Board in March just to update them on how we're thinking. And then it was a simple meeting to get together ahead of earnings to make this decision. And I think the Board was -- had resounding support for this plan. But that's all insight based on how Diamondback works with our Board.

Our next question comes from the line of Leo Mariani of Roth.

Everybody, there's been some discussion of some pretty weak Waha prices Wanted to get a sense whether or not you think that could be some short-term negative volume impact for the company? Are there some wells that have maybe a lower oil cut where you say, hey, maybe it's worth setting some of those wells in for a little period of time here, just given how bad the gas price is? Or just any color kind of around that dynamic, how you're thinking that would be helpful.

Yes. I mean, listen, at these NGL prices, we kind of think negative $3 Waha basically cuts out the value of your NGLs. And above that or worse than that, negative [ 4 and 5 negative 6]. You start to eat into the value of your oil production. Now oil is $100 a barrel, not $60, so it's a little different math on should you shut in oil barrels because of Waha pricing. But I do think that, that's happening throughout the basin, I think in an area like New Mexico with tighter restrictions on midstream development and flaring. That's probably a question for others, but it's probably something that's happening.

For us, if we go back to October of last year, Waha blew out due to some maintenance issues, we shut in 2,000 or 3,000 barrels a day of production for a period of time. And then Waha came back and we brought that production back. I would bet we're probably around somewhere in that range today with Waha as weak as it is. But it's not impeding new development, particularly with the amount of hedges that we have on the financial side.

Okay. That's helpful. It sounds like you still have flow assurance, this would be more of an economic decision for the company.

That's right. Every molecule we produced has moved, it's just moving at a negative price. .

Yes. Okay. And then just want to follow a little bit on what you got said on the growth part of it. Obviously, your guidance for the year on oil is a little bit open-ended with the 520,000-plus. Clearly, you guys did the 520,000 in [indiscernible]. It looks like your guys tell us we're getting 520,000, again, you did talk about a little growth. So I mean, if the oil environment holds here, people should be thinking about probably that plus and a little bit of growth here in the second half of the year. Is that kind of a fair way to look at it?

Yes, I think that's fair. Again, we're going to take it quarter-by-quarter. I think this is a year where the plan is if we're outperforming the plan, we're going to hold activity and produce more oil into a market that needs it. .

[Operator Instructions] Our next question comes from the line of Doug Legate of Wolfe Research.

Guys, I wonder if I could come back to one of the comments earlier about the balance sheet. Jere, is it is it inconceivable that when we look out with no variable dividend taken out of the capital return structure, but your net debt balance sheet could basically go to 0 over the next 2 or 3 years. Would you allow it to go to that level?

Yes, Doug, I mean, that would not be a good problem to have. I think generally, we're going to be transferring a lot of value from the debt side of the NAV to the equity side over this quarter, and who knows what happens after this as as we've kind of said, we're going to take this quarter by quarter.

This is -- we're early into this oil price environment should it persist and the stock continue to go up, then we'll allocate less capital to buybacks and continue to put cash on the balance sheet. But at the end of the day, we know this is a cyclical business. And in this highly cyclical business, we want to have the ability to pounce on opportunities when the cycle turns. And then those opportunities could be M&A that could be buying back a ton of stock. It could be leaning on your balance sheet to buy back stock.

So I think the key term here is flexibility, but also long-term value creation because at the end of the day, we want to get to 0 debt. We want to get to 1 share outstanding, and it's going to be a race between those 2 with free cash generation over the coming decades.

I appreciate that. My follow-up, Phil, is not so much about your growth than what you're seeing from your nonoperated positions. And I guess this is particularly, it might be a Viper question. But Obviously, we've seen some private add rigs, and there's a lot of nonoworking interest that basically can influence what happens to the growth story for you guys on a consolidated basis. How would you characterize that? What are you seeing on your non-op, I guess, request for [indiscernible]?

Yes. I mean, Diamondback carries very little not up, but Viper obviously sees half the wells in the basin round numbers. And I think we'll talk about it on the Viper call, but early signs are nothing major on permitting, but the discussions that we're hearing in the field in Midland are that rigs are getting picked up on the private side. I think if we had to give a rig count forecast for the Permian today, by the end of the year, we're probably up 25, 30 rigs from where we are today. .

Our next question comes from the line of James West of Melius Research.

I just wanted to -- I know everything is pretty fluid right now and your kind of quarter-by-quarter, but you have to be thinking about a market that's significantly changed in the last 60 days and an oil price that will be structurally higher. So understanding you've raised your guidance for this year, but how are you thinking about the out years and how you want to set up the company to either continue to grow at this mid-single-digit rate or not, '27, '28, '29, I'm not looking for guidance, but just kind of how your longer-term thinking is evolving.

Yes. Obviously, we have to think about the long term. And I do think if we aren't a higher for longer world, an advantaged company with advantaged inventory like Diamondback should answer the call for production growth in that higher for longer world. So I think that's we don't live in a vacuum that's static, but if we did, I think, some sort of organic growth in the story moving this business from a steady-state kind of bonds like free cash generator to a free cash flow per share growth generator over the next few years into the into the decade. So long as it maintains capital efficiency, I think that's something that investors would support.

So Again, it's early. We'll see what the macro holds. But certainly, it feels like the world changed a lot since our last conference call.

Absolutely. That's very helpful. And then as you think about your inventory depth versus your peers, you guys are obviously in a leading position, but what would you consider your or how would you kind of phrase it your position versus probably the peers in the market today given the huge longevity we think you have?

Yes, we're very fortunate. We have an incredible inventory quality and duration. But I'll say that within Diamondback, we're always looking for that next stick, right, whether it's organic generation and Arnet development, Upper Spraberry development over the last few years or inorganic, this machine is built to do significant transactions like Endeavor, but also I don't want 1 unit in the Midland Basin trading hands without Diamondback knowing that, that unit could be in our hands. So we're set up to do the sub-$20 million deals, and the teams actually do a really good job at those, but also not so small that we're not in the picture for every other deal that transacts in this basin.

Thank you very much. I'm showing no more questions at this time. I would now like to turn it back to Kaes Van Hoff for closing remarks.

Thank you, everybody, for your interest. We're always available to answer any questions, just reach out to the number or e-mail on the notices.

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

Good day, and thank you for standing by. Welcome to the Diamondback Energy's Fourth Quarter 2025 Conference Call. [Operator Instructions] Please be advised that today's conference call is being recorded. I would now like to hand the conference over to your first speaker today, Adam Lawlis. Please go ahead.

Thank you, Cory. Good morning, and welcome to Diamondback Energy's Fourth Quarter 2025 Conference Call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback's website. Representing Diamondback today are Kaes Van't Hof, CEO; Danny Wesson, COO; Jere Thompson, CFO; and Al Barkmann, Chief Engineer.

During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.

I'll now turn the call over to Kaes.

Thanks, Adam. Welcome, everyone, to the fourth quarter earnings call. As usual, we will open up the line for questions. I hope everybody read the letter last night, a lot of good detail in there, and we look forward to discussing. So operator, please open the line for questions.

[Operator Instructions] Our first question comes from Neil Mehta of Goldman Sachs.

And no surprise, the area we want to dig into here is the Barnett case. And just talk about what you think the opportunity set is you are deploying more capital here in 2026. And how you think about the potential returns associated with it and just the mix as well between oil and gas?

Yes, Neil, I'll give you some high-level thoughts, and then turn it over to Al, but it's a pretty exciting reveal of our position in the Barnett. That's a position that was essentially almost 0 acres a couple of years ago. We were able to grow that position without cap raises or press releases or buying the next private equity backed entity. So I think overall, being able to build a position in our backyard that we understand very, very well is going to be very good for our shareholders long term and good for corporate returns long term. We're not having to pay $3 million, $4 million, $5 million, $6 million of stick to build this position.

And that's a testament to the team, having belief in the rock. And now that we've put the drill bit in the rock, we found that returns look very good from a productivity standpoint. The next step is we have to get the cost down. We haven't really moved to full field development. that's going to start here in the second half of 2026 in earnest and pick up in the coming years. So I think it's a good time for us to reveal what we have. We're not done yet but I wanted to show our investors what we've been up to. And that resource expansion is an important part of our overall story.

I'm going to turn it over to Al for some details on what he's found from a technical perspective.

Yes, Neil, I think if you look at Slide 12 here in the deck, you can see we've shown the performance of our 2025 Barnett plan here relative to our core development plan. And I think the performance really stands out, speaks for itself. And I think when we're able to get the cost down 20% kind of from where we are with our delineation wells here. We think these returns are going to be competitive. So we're pretty excited about the potential here, 900 gross locations and I think we'll be allocating capital to the plan more going forward.

Yes. And that's a good follow-up, which is just talk about the product mix here on Slide 12. You show that there is more gas that comes out of the Barnett. But actually, there's potentially more oil as well. So it's probably a little oilier than some of us would have thought. Just talk about how you're thinking about making sure that you're maximizing the liquids cut out of these barrels.

Yes. I think just looking at the absolute oil production you can see that's even differential rate, and that's what we've got in applied. The initial GORs are higher, right? So kind of in the [ 30,000 ] range. I think kind of what's striking when you compare the 6-month oil and BOEs to the 12 months kind of see a flatter GOR profile, right, through the year, especially relative to the core. So the DOR profile in the core zone kind of ramps up a little faster. And we're seeing a much flatter GOR profile through the 12-month period. So where your core zones like 80% oil for that first 6 months it goes down to about 75% oil. The Barnett plan that we're showing here is 67%, basically flat for the first 12 months. So a little different profile on the product mix. But overall, I think the oil productivity speaks for itself and is very competitive once we get the returns where we see them going.

Yes. Neil, one thing I'd add is whether the timing is planned or not, we do have a Permian Basin that's going to have a lot of gas takeaway coming on in the 2027 to 2030 time frame. We're going to have to drill a lot of Barnett wells over that time period. The Barnett's a different type of lease. It's not held by vertical production or production in the core zone. So we got a lot of drilling to do. But getting a good price for our gas and our liquids is going to be a benefit to returns in the 2027 plus time frame.

Our next call comes from the line of [ Gabriel Cerney ] of William Blair Equity Research.

Sticking with the Barnett, can you talk about the well economics there versus the Midland Basin? I guess what I'm getting at is I'm looking at Slide 12, it shows that your Barnett wells, you're talking about kind of a 36 MBoe per 1,000 foot, 12-month versus 22 for the core Midland yet you have the -- you talked about maybe the $100 per lateral foot Barnett versus what are you down to, I think, 5 or 550 for the Midland cost. So curious how you're thinking about total returns, Barnett versus the Midland average.

Yes. Why don't I get the high level and let Danny talk about how we're going to get the cost down. High level, our core Midland development, which I would put is everything except the Wolfcamp D is close to about [ $510, $520 ] a foot. If we can get -- in the Barnett today is at $1,000 a foot. If we can get the Barnett down to $800 a foot. And the Barnett oil production is 60% better on a first-year [ cume ] than the core then the returns start to get competitive. And I think we're fortunate that the rock has been proven first and then the costs will need to come down. But Danny has a few examples of how we're going to do that.

Yes. I mean I think a lot of the cost reductions we're targeting are really just a decision to move to the kind of development mode and apply the techniques we've learned over the years developing what we call the Midland core with multi PUD development -- multi-well PUD development, simulfrac and those things are really just a decision to go to that full-scale development and see those cost savings accrue to that to the Barnett development as well. .

On the drilling side, we've been pretty conservative in the drilling plan we've laid out in the delineation wells, really just targeting successful wellbores. We have a lot of things we think we can apply in the drilling plans that we can cut a lot of cost out of the drilling part of the well. And also, we think the Barnett, the leasehold we've established in the Barnett set itself up well for extended lateral development. So we're kind of targeting 15,000-foot laterals in the Barnett. It won't be everywhere. But we hope the majority of the wells that we drill in that zone will be extended laterals 15,000-plus foot, which will also help drive down that per foot cost.

Good details. And then just secondly, Kaes, my second is on inventory. And by the way, thanks for disclosing I don't think versus any other companies have this kind of similar details around that. But I'm wondering, could you just address maybe talk about inventory replenishment and reinvestment in your existing asset base? Is it appears when you add the Barnett to your total drilled feet year-over-year only decreased minimally. So I'm just wondering how you're thinking about inventory replenishment and reinvesting going forward?

Yes. I mean listen, we're in a depleting business, right? And we think about inventory every day. Diamondback was a company that went public with very little inventory and had to work for every stick that we added over the last 15 years. So something that's top of mind for me, for the team. If you look at the inventory disclosure we put out, the team did a very good job increasing average lateral lengths last year, up by about 600 lateral feet on average, which is a -- that's a big number on a big company. And I think we're going to continue to try to add inventory where we can.

If you notice, like I said earlier, all this inventory was added and put in the plan without needing outside capital or press releases, all while still returning a ton of cash back to shareholders. So I think you should expect that to continue. I think we kind of have a philosophy here that no deal on inventory in the Midland Basin should leave Midland or leave Diamondback without us taking a look at it. So we're highly focused on continuing to replenish our inventory. We recognize that it's not infinite, but I think we have a plan to continue to grow it.

Our next call comes from the line of Jeoffrey Lambujon of TPH & Co.

My first one means to hit on the implications from some of the Barnett disclosure we're also still keeping in mind legacy Midland Core operations, we took note of the strong oil cumes from both data sets in the slide, as you guys have spoken to already. And obviously, the productivity for the Barnett looks strong as well on an absolute basis. So as you think about that, we were hoping you could speak to your outlook for corporate oil mix over time as you continue to develop your Midland Basin core inventory and work in more Barnett [indiscernible] as well.

Yes. It's funny, Jeoff. We have a $3.75 billion budget and $150 million is allocated to the Barnett, but it's getting all the airtime. But that's the market we live in. I think that means that investors trust the inventory that we have in the core and they trust that we have enough of it. But at the end of the day, what the teams are doing on the core inventory the vast majority of our budget is very, very impressive. Lateral lengths up year-over-year productivity. In a world where productivity is being questioned on a per foot basis. .

In many basins, the team was able to increase productivity in 2025 versus 2024 on the oil side. And that just means we're continuing to test things in terms of stage length, stage designs, where we're putting the drill bit, spacing, all the zones that we're developing and the results kind of speak for themselves. I think, generally, with the Barnett becoming a bigger piece of the capital pie, oil mix will go down over time, which is why we tried to focus more and more on our gas marketing strategy and getting better realizations on that front because I think it can really help overall free cash and corporate returns kind of after these pipes come on in the back half of 2026.

Perfect. That's very helpful. And then for my second question, I actually wanted to revisit something that's also not yet factored super meaningfully into guidance at least for now, but it's also exciting to think about, which is the hyperscaler and data center opportunity you've spoken to in past quarters and on past calls and how Diamondback really offers the full suite of what a counterparty there would be looking for in terms of the surface acreage you have last year. The water supply potential, especially thinking about Deep Blue and of course, gas or power from the upstream business. So I wonder if you could just get a refresh on how discussions are progressing there and how you're thinking about those opportunities in general.

Jere, you can take that one.

Yes. Jeff, you're exactly right. I mean we continue to be excited about the opportunity as we feel we have all the pieces for a very compelling project and we're making progress on bringing data centers onto our service position. I think as you think about Diamondback specifically, the biggest benefit here is our ability to structure a power purchase agreement that provides for material uplift to nat gas pricing. So just another creative tool in the toolbox for us as we are thinking about improving natural gas realizations which we obviously highlighted in the deck and Kaes alluded to earlier. So a new meaningful in brace and egress solution for us. So we continue to make progress. We're excited about the opportunity and when we have more to discuss publicly, we'll definitely do so.

Yes, I'd say the only thing I'd add there, Jeoff, is we're not going to announce anything until it's completely binding, and we can talk to our investors about what it means for them. There's been a lot of noise in this space. I still continue to believe given our size and scale and expertise in the basin, we offer the full package and conversations have improved, but we're not going to talk about it in detail until we have those details. But it's a great question.

Our next call comes from the line of Phillip Jungwirth from BMO.

Yes, thanks. I'll also give the Barnett more air time here, and I appreciate you bringing resource expansion back to the [ E&P ] sector. But -- so the Midland Basin, it's obviously a large area. I was just hoping you could talk about how you see Barnett variability across either your or other operator wells across the northwestern side of the basin versus Southeast? And why do you think your Barnett well productivity has outperformed the industry to such an extent?

Yes. I think the big distinction that we kind of see when you look at the map on Slide 12 here, the wells that are to the western side of the basin and actually up on the Central Basin platform, which is really where the play began back in kind of the late 2000-teens that has lower maturity, so more within the oil window, and -- but that comes along with lower bottom hole pressures and -- so what we've seen in terms of 30-day IPs and 6-month cumes the well performance in that area where the play kind of kicked off is not as strong and robust is when you kind of move down into the basin and you've got higher bottom hole pressures, you've got more gas in the system. So you're getting higher initial rates.

And I think the variability in GOR, we're still kind of delineating around the basin, especially as you move to the east into the south. And so there is going to be variability in GOR. But I think one of the things that we really focused on from a technical standpoint is where can we find the best resource, the biggest resource and then the potential to drain potentially the Barnett and the Woodford reservoirs with a single wellbore. And we believe we put together a really strong position in the best resource quality within the basin.

That's great. And then you called out Diamondback having nearly 2 decades of inventory at its 2026 pace. Last year, there was a lot of talk about peak Permian, who has inventory to grow, who doesn't. But for Diamondback, assuming a green light scenario, just how do you think about a sustainable growth rate that can be achieved for the company over a multiyear period given the depth of resource you have?

Yes. I mean listen, I think that's highly dependent on the macro. But in general, it feels like investors over time, want some form of growth. Now we've done it on a per share basis for the last few years. At some point, organic growth is going to come into the equation. Unfortunately, we're still stuck in this yellow light and the stop light analogy that we can't shake yet. But I think there's probably a world where if we can efficiently allocate capital and growth becomes kind of the output that's probably a good decision.

I think for 2026, we're starting the year here still in this kind of quasi yellow light, where oil production is the input and then CapEx will be reduced if things go well and then help steady if things go as planned. But it could be a world where we hold CapEx flat and see what growth comes out of it. But that day is not today, but there will be a time, and that's why every day, we think about inventory, inventory duration, inventory growth and things like the Barnett which is getting a lot of airtime today are accretive to that long-term duration story.

Our next question comes from the line of Arun Jayaram from JPMorgan Securities.

I also have a follow-up on the Barnett. Yes, just a follow-up on the Barnett. Looking at the 12-month cume plot on Slide 12, it looks like the average well is delivering just under 50% more oil [ pets ] or mix over the first 12 months of the well. I just wanted to see if you could comment on your thoughts on what the Barnett would do for your oil in terms of oil growth over time because that's been just a question we've been getting just because there is a little bit higher gas you're getting, but the oil cut is higher than that. And if we could maybe translate that into an oil EUR for an average well based on your test so far?

I'll let Al give the EUR commentary. I think the one thing I would say, if you start to run these wells at $800 a foot or close to it, the rate of return relative to the base plan looks very comparable, but the PV is significantly larger. So we look at both of those things, PV and rate of return and try to find a nice balance there. But the key here is getting these costs down makes the returns competitive, particularly in areas with Viper minerals. But then the PV impact is huge. So from an NAV perspective, that's very positive.

Now I'll turn it over to Al for some type curve commentary.

Yes, Arun. So that 50% uplift that you kind of see as the 12-month time frame that roughly equates to [indiscernible] we see relative to the core zones on an EUR basis. So if you think about our core zones, those are about 50 [ bo ] a foot in the Midland Basin. So right now, in the Barnett. We think we're pretty close to about 75 [ bo ] a foot for the ultimate recovery for those wells.

That's helpful, Al. Just on my follow-up, I was wondering, Kaes, in your shareholder letter, you mentioned how the company was testing surfactants and just give us a sense of how those pilot projects are going? Are you using surfactants in terms of your base production management? Are you testing those in terms of new completion activity but give us a sense of what you're seeing thus far and how you're using those in terms of your development scheme?

Yes. It's early in the surfactant game, but it's exciting. We did a 60-well test in the second half of last year. Credit to the team to mobilize that quickly. This went from an idea in June to execution by December, and we got a lot of data coming in from those tests. We focused on the production side for now so that we can try to figure out which variables are working. I do think there's been some discussion about adding this to the front end on your completion, I think we're going to test that. We're also going to continue to test the production side of the business.

And from a high-level perspective, in my mind, this was something that no one talked about outside of papers, [ SPE ] papers 4 or 5 years ago, and now it's becoming something that can potentially be economic. And I think that is why we put in our last shareholder letter, never underestimate the American engineer because there's still a lot of oil in the ground in the Midland Basin and the Permian Basin that needs to be extracted, it just needs to be extracted economically. And that's what we're working on today. So Al, do you want to talk about the tests?

Yes. So like Kaes was saying, we trialed 60 treatments kind of in the back half of 2025, a lot of lab work and technical work going into designing the surfactant for the specific rock types and specific surfactant types that we're using. It's pretty early on in the results, but we've seen at least in a handful of the issues that we've applied that to some really exciting results. And so the team is taking that information and going back, refining the chemical makeup there and the design of the test and really trying to hone in on the variables that are driving the performance for the program.

Yes. I think this is all just [ grady ], right? This is all added production, added reserves to something that we didn't think was possible a few years ago. And I'd say this has been 1.0 in, right? This is what Wolfcamp B fracs look like in 2014. So I think we got -- look how far we've come in 10 years and again, this is a highly technical organization that's going to work to figure some of this stuff out.

Our next question comes from the line of Bob Brackett from Bernstein Research.

And I'm going to have to go back to the Barnett just because it seems to be the flavor of the day. If I compare your typical well, it's less than $600 a foot. You've got a path for the Barnett to get from $1,000 a foot to $800 a foot. But on the top of the Wolfcamp versus the top of the Barnett, that are a couple of thousand feet apart. So not a whole lot of vertical depth. What's [ in ] the drilling down there? Or is it on the completion side where those incremental costs are coming from? And what are some potential solutions?

Bob, thanks for asking. It's really just a different resource altogether, and we've got to set up a drilling program that's a little bit different than what we do in the Midland Basin core. The Barnett, we're using oil-based mud. There's an extra string of pipe in the vertical portion of the hole. And all that we've been doing, as I alluded to earlier, to derisk any kind of operational issue as we were delineating this play. And I expect we're going to continue to do -- to be a little bit more conservative as we roll into development mode on the drilling side, but we'll start doing things that we know through calculated risks we can do to cut costs out of those wellbores.

And on the completion side, too, there's some additional costs there. The jobs are a little bigger. We're targeting 4 wells a section in the Barnett. So we're pumping larger jobs to try and generate a larger simulated rock volume across those 4 wells. And we've been only on 1 or 2 well pads, so a lot of single well or zipper fracs. And as we move into development, we're going to move into full-scale 4-well PUD development or 8-well PUD development on the Barnett and utilize simulfrac continuous pumping, the things that we've learned from our development in the Midland Basin core over the years.

That's all very clear. Quick follow-up, if I could. One of your peers talked last week about international opportunities. I'm curious where do international opportunities sit on your list of strategic priorities?

Yes, Bob, I mean, it's certainly low from a strategic perspective. I would say a company of our size should start to understand what else is out there around the world and really for the main reason of what else around the world could push us out on the global cost curve. And we've spent a lot of time studying that. Obviously, there's different dynamics above ground and below ground around the world. And I think what that's taught us is we have a very, very good long-duration inventory in the Permian Basin. And now there's things like the Barnett and surfactants and all that kind of stuff that we're going to be talking about a lot over the next 3 to 5 years.

And that just kind of points me back towards stay in home and the Permian Basin has been very good to Diamondback, growing our position here we're basin experts. And there may be a good rock around the world, but there's a lot of other issues that come with that rock. So we've learned a lot about what's out there, but there's not a lot of action that we're focused on today.

Our next question comes from the line of John Freeman of Raymond James.

You all had a really nice improvement in your leading-edge completed feet per day at 4,500. Just maybe some thoughts on what's sort of embedded in the '26 plan? And just where you all see that potentially getting to by year-end?

John, thanks for asking, yes. I mean the core program still continues to really shine and Kaes put some commentary in his shareholder letter around some of the continued efficiency improvement we're seeing on the drilling side and the completion side. And on the completion side, the team has been working on implementing what they call continuous pumping across all of our simulfrac [ E fleets ] and really, what that means is we just don't shut down between swapping wells in the simulfrac PUD. And we've been averaging 4,500-ish feet a day on those continuous pumping fleets, but we've seen some results of above 5,500 feet per day. So we're encouraged by that. We think we still have opportunities to reduce our cycle times this year. And if that comes to reality, we're going to be able to get rid of some frac crews and be able to hopefully complete West wells in the year to achieve our production targets.

I think one thing I'd add, John, that we're kind of finding out, we're really starting to test different stage length, stage designs, frac designs and what continuous pumping does is it removes the biggest piece of nonproductive time to swapping between your stages. So we're going to test shorter stages, we're able to do that with less cost. I mean all these things are little wins that accrue to our shareholders and you think, hey, continuous pumping. It's one thing to do more lateral feet, but what are all the other tangential benefits that are now starting to show their face, and that's what's exciting there, too.

That's really helpful. And then just my follow-up, tariffs have been pretty topical of late. Have you all secured or maybe locked in the pricing on y'all steel related products for the '26 program?

The way our procurement agreements work on the casing side of things. It's kind of a repricing quarterly. With the tariff ruling that was just announced last week, we're not sure how much impact it's going to have on OCTG because that flows through a different law as far as the tariffs go, but we repriced our casing every quarter based on an index price with our supplier. And then on the tubular goods, we do procure those things out in longer lead times if we feel like we've got an opportunity to secure some at a beneficial price and we kind of watch that market and just make those decisions based on where we think the market is headed. But the tubing side things have been pretty sticky even through the tariff world. Really, the inflation we've seen has been on the casing side of things. And unless we get some other tariff relief on, I think it's Section 232 then we don't think those tariff-related inflationary impacts are going to go away. We're just really waiting on or looking to see what activity does in North America to drive casing prices one way or the other.

Our next question comes from the line of Derrick Whitfield of Texas Capital.

Congrats on a strong year-end. Wanted to start with surfactants, from my understanding, the capital efficiency on using surfactants and your workovers is quite exceptional. Could you perhaps elaborate on the degree of uplift you're seeing in production on average for dollars spent. And separately, on the new well side, I understand you guys are very early in the process, but maybe could you speak about it from the data you're seeing from Viper, that would suggest that you are seeing an uplift in EURs on new wells?

Yes, I don't know if we're seeing enough yet at Viper to make that distinction. We don't have all of the private data on designs and what got pumps. But I think we start to see overall productivity improvements from peers, we spend a lot of time trying to study that and say, what can we do better? The thing I would say about our surfactant tests tested 60 wells. They're fairly cheap jobs, about $0.5 million, and I think we can work those down. What we did was we did the jobs when we had to pull the ESP anyway. So you're having to -- you have some costs and then you just pumped some surfactant in water. And listen, we don't even know how much of the wellbore we're touching today. But some of the results are significant. I mean some of the multi hundreds of barrels a day uplift from a well that's producing a couple of hundred barrels a day.

I'd say, on average, we've seen about an average of about 100 barrels a day pop, which for $0.5 million is a high-returning project. I think we got to get smarter on it. We're going to keep testing it. And I think over time, as we refine that analysis, it's going to become a part of our overall development plan and life cycle of these wells. So that's how I see it today. I look forward to all of the advancements that the teams are going to make. We've made a lot in a short period of time. There's going to be a lot to come in the next couple of years.

Great. And maybe, [ stan ], on the resource expansion theme, but given you guys a breather on the Midland Basin side, there's been a lot of buzz from Ministry on both the Barnett and Woodford and the Delaware. I realize that [ EOG ] is chasing different Woodford concept in Pecos. I'd love your take on the view of that interval and your position over in Pecos.

I think generally, we've been following it. It's going to be more expensive than the Midland Basin, Barnett even. I kind of equate the Midland Basin Barnett to kind of core Delaware type costs, and this is below that. There's been people poking around Barnett and Woodford and the Delaware now for 7 or 8 years. I don't think we're ready to begin a big program in the Delaware on our position. But with the Viper map being as consolidated as it is on the Delaware side, we're going to learn a lot about it as people try to test it.

Our next question comes from the line of Kalei Akamine from Bank of America.

With respect to the '26 guide here, the disclosures have been simplified. Just kind of wondering if you can talk about the number of targeted drills until is expected this year. The DUC backlog that supports that program? And then what kind of conservatism has been baked into the volume noting that surfactants in Barnett or kind of new efforts here contributing?

Yes. Listen, we try to simplify our disclosures to say, here's the amount of lateral feet we completed or plan to complete and if we do better than midpoint or towards the low end, that means we have high capital efficiencies. So I think our transparency and disclosure is still best in class. We have -- certainly have a solid DUC backlog that we can closer pull on depending on the macro, but I think that's going to be a management decision. Right now, the base case is just kind of hold it flat.

One thing I'll say about 2026 CapEx guide, we're kind of guiding towards the lower end of that quarterly average in the first quarter. And I think we expect the same to be for the second quarter. As we get to the back half of the year, I think some of these things that we are talking about a lot today, the Barnett, surfactants, Barnett well costs. If those things start to trend our direction then I think there's a world where CapEx comes down this year. It's just not something I think given our history of conservatism, we want to put out as fact today. So I think there's some goals to be set for the teams, and we're already well on our way to achieving them. But I just don't think they're going to run through guidance yet.

I guess the follow-up there is just on the number of drills contemplated. And then the second question is just on the working interest in the Barnett. 64% is the lowest in your stack. Wondering if you can talk about any opportunities to increase that interest, whether that's organic leasing or maybe it's inorganic, understanding that the rights could be in somebody else's hands and whether that could be achieved via acreage swap, which contributed very meaningfully to the inventory update.

I mean, on the working interest side, we're always looking to increase working interest. We've built this position through a few partnerships where our working interest is lower than it traditionally has been, but that doesn't mean there's not opportunities to grow it. So I mean, the position had to be built organically, and that means usually after that's built, you start to work on swaps and trades and netting up and all buying minerals and all the things that we do to add value around the base business. .

On your second question, the model doesn't show us drawing or building a meaningful amount of DUCs this year, and I think we're still going to post how many wells we drill and complete every quarter. But I think if you think about last year, we ended up drilling more wells and completing less wells than we originally expected and what the DUC discussion became a discussion that got more airplay than it deserves.

Our next question comes from the line of Kevin MacCurdy from Pickering Energy Partners.

I guess for my first question, I'll just hit on OpEx. We saw lower OpEx was a partial driver of the EBITDA beat in 4Q, but guidance -- 2026 guidance is for a small increase for both LOE and [ GP&T ] and I wonder if you could address those. Is that just the water drop-down on LOE and gas transportation contracts on GP&T or is there anything else in there?

Yes, that's most of it, Kevin. We sold the [ EDS ] system to Deep Blue in fourth quarter, so you saw LOE tick up a little bit. I think we got a couple of things as headwinds this year on LOE, power prices in the basin have gone up. So we got some power that is now unhedged, that's going to be priced at a higher number. That's probably $1 or $ 2 of [ hert ]. And then we're continuing to spend more and more dollars on workovers, plugging and abandoning vertical wells, making sure our asset base is in good condition on that front. So those are a couple of headwinds. On the GPT side, most of that is your traditional escalators on CPI but also more barrels -- or sorry, more molecules being taken in kind and so you're shifting dollars from realizations to GPT.

Great. And maybe to ask one more clarification question on the Barnett. Will there be a separate rig dedicated to that program? And just to confirm, will those wells be geographically separate from your [ cube ] development?

It really just depends. I mean, there will be separate rig lines that we have dedicated to the Barnett. I think it probably makes sense that those rigs just focus on that type of development. But there's areas like Spanish Trail, where we have 100% of the minerals and high working interest that we're going to be in the same area as our shallow development, and then there's areas where we don't have it. I think overall, though, we're going to continue to build a position and try to share facilities wherever we can because that's the most efficient form of capital use.

Yes. I'll just add. I think we with the Barnett's depth and with some of the most properties and such that we'll be utilizing to drill those wells will probably be a different rig package that we're looking at. So we -- those rigs can certainly drill the Midland Basin core, but probably looking at a little bit upgraded rig package for those wells. So ideally, we'll have them all on separate rig lines that we may make sense on one of our Midland Basin core with. But if we can get days down in the Barnett drilling, we'll mix in more of our core development and probably have less Barnett directed rigs in particular, at the end of the year.

Our next call comes from the line of Doug Leggate from Wolfe Research.

I wonder if I could follow up on the last question about the mix of Barnett versus the base business. It seems obviously an HBP requirement here given the relatively new acreage. And I guess the core of my question is, the type curve you've shown for the Barnett is presumably a parent well versus the development type curve for the cube development elsewhere. So how do you expect that development type curve to evolve relative to the base business?

Yes. I mean I think we'll see, Doug, I think we're spacing these wells pretty wide. We have done a few 2-well payers, and we'll still see what a full section development looks like. But I think in general, the size of the job and the spacing that we're assuming should result in pretty consistent performance. Listen, I'm not going to tell you that every well has been the best well we've ever drilled, but there are a couple in that data set that are probably the highest 6-month cumes we ever had at Diamondback. So I think we're putting the bet on ourselves to continue to improve results and get costs down, and that's a good bet.

Well, obviously, it's early days, but thanks for the color. My follow-up is on the inventory question. I know there's no precision here, but I want to understand what your intention is in talking about 20 years, is that kind of consistent weighted average well quality? Is it maintaining production mix or more importantly, is it maintaining free cash flow? How are you -- do you want us to interpret that 20-year comment?

Listen, I think not all inventory is created equal, right? The best -- if we're doing our job right, we're drilling the best stuff first. And I think you see that throughout the space where productivity per foot, so we look at it as starting to degrade depending on the company. And our job is to have the best productivity per foot, the longest and I think you've seen us add in zones like the Upper Spraberry like the Wolfcamp D, even 5 years ago, the Middle Spraberry in Jo Mill, and you haven't seen significant degradation. In fact, 2025 results were above 2024.

So in a world of decreasing productivity, our ability to maintain that productivity consistently and longer is, I think, a winning proposition. So certainly, as we get further down our inventory, we're going to have lower productivity. I'd be lying to you if I said otherwise. But the teams continue to work on ways to reduce costs, drill better wells, better frac jobs, get better well performance out of areas that we thought were Tier 2, Tier 3, 3, 4, 5 years ago. So in general, it's about drilling the best stuff first and maintaining that sustaining free cash flow that you'd like to talk about. And I think we can do it longer than anybody.

Our next question comes from the line of Scott Hanold of RBC Capital Markets.

Yes. Kaes, if you can give us some color and context on your view of the Diamondback's position in the industry going forward. I mean, historically, you all have build your position through successful M&A. And obviously, this -- it feels like this quarter, there's been a little bit of a shift to more resource expansion organically. Can you just give us a sense of like what you're seeing in the landscape that sort of drives the shift from where Diamondback historically been?

Yes. I mean Scott, there's no doubt that there's been a ton of consolidation, both in the Permian and elsewhere around the U.S., and it's been top of mind. I mean your website, the RBC website continues to shrink in terms of the number of tickers. And I think generally, the things have moved towards basin champions. And I think in the Permian, there's going to be independent basin champions like Diamondback. There's going to be mineral champions like Viper, and there's going to be surface champions like some of the other companies out there.

So that natural consolidation has led us to say, hey, we have a ton of acreage and a ton of resource. We should probably start to spend some more dollars improving that existing resource. So we're not out of the M&A game. But as we said in the letter, the opportunities are fewer and further between. And therefore, we're going to be doing more things like the Barnett, more things like testing surfactants, but don't get it wrong. There's not a deal that happens in the basin without us knowing about it. It's just that there's not 10, 20, 30 deals left to do.

And my follow-up is on your reserve report. You all mentioned there some revisions to some of the numbers in there. And I know some of it is price related, but you did mention some performance-related revisions. Can you just give us a little bit of context behind that?

Yes. I mean the majority of the reserve revisions, and it's interesting that reserve reports are now becoming something people read in detail. And the majority of our revisions are due to price. The rest of the majority of our revisions are due to -- we call it PUD downgrades, but it really just means we're bringing in wells that we acquired or PUDs that we acquired and bringing those to the front of the development program. And in general, we try to keep a very low PUD balance.

We try to -- the SEC rule is 5 years of development in general, we're kind of averaging 3 years of development and what we put in our PUDs. And right now, Diamondback, from a booking perspective, we're 70% PDP, 30% PUDs. And I think as we do good deals like Double Eagle last year or Endeavor the year before, some of our existing PUDs get taken out and new PUDs get put in. But from a performance perspective or PDP performance perspective there have not been meaningful changes to the reserve report.

Okay. So the individual wells are still holding true. It's just a shift in the PUDs moving in. Is that right?

That's right. Just moving your best wells that you have remaining.

Our next call comes from Leo Mariani of ROTH.

I wanted to just revisit the Barnett here quickly. Can you give us a rough sense of the number of wells that you guys are going to be drilling or completing here in 2026? And can you just talk a little bit about what you kind of need to do to hold that position, say, over the next 5 years? Is there going to be a meaningful step-up in activity in '27, '28?

Yes. We expect that to ramp up kind of through the end of the year, like Kaes mentioned before, we expect to kind of allocate some activity to the plan in the back half of the year. So roughly, we're looking at drilling about 30 wells this year, popping probably closer to [ $10 ] and then that ramps up significantly in 2027. We're on a gross basis, we're probably looking at more like 100 wells for that program.

Got it. Okay. And I guess is that the type of pace that would kind of hold everything together over the next couple of years? Just any color you can provide around lease terms or anything like that on the outset?

Yes. That's a general pace so that we can do it in a capital-efficient manner.

Okay. Appreciate that. And then on continuous pumping, obviously, you talked about that. I think you're kind of increasing the amount of activity moving in that direction. You mentioned potentially being able to drop crews at some point down the road. Do you see that as a potential meaningful capital savings if you can get to the point where you are dropping crews at some point, say, later this year or next year?

Yes. I don't think that it's going to drive a ton of cost savings from our service providers. There's additional equipment requirements to be able to do so. There's a little bit of savings on some of the [ dun ] iron, there's the rentals that are out there as you increase cycle times. But the big benefit is really, as Kaes kind of mentioned is some of the stuff we can do to optimize the completion without adding additional costs from the additional well swaps and that kind of thing. . But also the increased cycle time -- or I'm sorry, the decreased cycle time that impacts your water out frequency and you're able to bring wells forward in the plan, which is only maybe a onetime effect, but really the water out frequency and the length of time that you're watering out offset pads is a pretty huge benefit to the full year cycle time.

Our next question comes from the line of Charles Meade of Johnson Rice.

I want to ask a question around nomenclature because in your -- we've been talking about the Barnett here in your presentation talking about the Barnett. But in your shareholder letter, you refer to it as the Barnett and the Woodford. And so I wonder if we could -- you could help me explore a bit how this play has evolved. If we go back to the late teens and when you guys had the Limelight Prospect, that was pretty clearly Barnett Mississippian target there. But it sounds like as you guys are going into the more the basin center here that it's Woodford and Barnett target. And it sounds like maybe you guys are landing in the Woodford and trying to frac up into the Barnett. I wonder if you could comment, is that directionally correct and more generally elaborate on how the play has evolved for you guys?

Yes. I think that's good commentary. So the Barnett and Woodford are distinct reservoirs right and have their own distinct properties the initial play, the Limelight play when you think back to the 2017 time frame, that was truly a Barnett play. There's some nuance across the basin with the zone that by the 2 reservoirs. So the Mississippian line is between the changes in thickness pretty materially as you move across the basin sort of north to south. And so up at the Limelight position, we had a pretty big midline section. And so those 2 reservoirs were separate and distinct and then as you move kind of into some of the areas where we've been delineating more recently, the midline is materially thinner and we're able to frac through it. But generally, we're targeting the lower bar at and able to drain the Woodford in some of these areas where you've got that thinner missed line section?

Got it. That is helpful. And then Kaes, this may be for you, if we go back to your stoplight metaphor, I think you -- and I appreciate you really made it clear that you thought that the red light scenario had -- seems like it's receded a bit. And I think the unspoken flip side of that is that the green light scenario is a little closer, but can you elaborate a little bit more on that? Does that mean that the green light scenario is closer than the red light? Or are you -- or is it closer than before, but you're still on balance, more likely to slow down? Just you fill out that metaphor.

Yes. It's a metaphor we can't seem to shake. But in general, I think it explains the situation pretty well. I'd just say I think there were periods of time over the last 6 months where we were all much closer to the red light scenario in terms of crude price. Now there's a lot of things impacting crude prices over the last few months. But in general, I think talking to our investors, they're very supportive of this plan to keep production flat and maximize free cash and wait for the green light scenario.

And I think just generally, we've been talking about this oversupply for -- some people have been talking about it for 2 years. And it just hasn't seemed to happen as aggressively as some expected. And I think as we turn to higher demand in the summer and driving season and trading the spring months in crude, people will start to find reasons to be less bearish. Now I could probably be wrong, but in general, we just feel more confident about the macro after a couple of big shocks last year on the supply side and the demand side.

[Operator Instructions] Our next question comes from the line of Paul Cheng from Scotiabank.

Gentlemen, 2 questions. One, in your D&C well cost now you've already done in your legacy operations, say, in Midland, [ 550 ] or so. So where is the biggest opportunity to drive that down further? Is it coming from further improvement in drilling or completion, I mean you're already extremely efficient over there? Or that is going to allow you that to have better maybe reduce downtime. And so just give us some idea that where should we see from there? That's the first question.

Yes. Good question, Paul. I think on the drilling side, it's -- we've really been able to show quarter-over-quarter efficiency gains. And I think it's just more of that. Getting more consistent in those ultrafast wells, right? We talk about in the letter, some wells that are sub 6 days, and we're still averaging over 8 days spud to TD. And so how do we get that average from 8.5, 9 days down to 7 days. And that drives meaningful cost savings on the drilling side.

And then on the completion side, it's -- we're continuing to go faster, and we talked a little bit earlier about continuous pumping and what that means for us. But it's also working on the supply chain on the completion side, what can we do around fuel, what can we do around other supporting services to get more efficient and drive some of the debt cost out of that business. And we're working on a lot of those things every day. These are not big chunks of dollars, but it's a lot of little things that add up to big chunks of dollars. So we're still grinding away on the core business. And like Diamondback is always done, we're not going to let up on that grind and I'd expect to see more dollars flow out of the core business as we go throughout this year.

Do you think over the next several years, you will be able to more than offset the inflation and drive that [ 550 ] number down, say, towards the [ 500 or 525 ] in the next, say, 3 or 4 years?

Well, the [ 550 ] is a mix of all of our Midland Basin zone. So that includes Wolfcamp B some of the deeper stuff in Barnett. And so yes, I think certainly, some of the deeper zones that are higher cost today, we're going to see some material cost reductions in them as we continue to deploy our best-in-class execution [ pales ] to those zones and learn about them more and put the bid in on more. So yes, I do believe we'll see the $550 million come down materially. But also in the older stuff that we're doing, the Spraberry [ shallower ] Wolfcamp zones, I don't know what inflation will do with -- it's really going to be largely driven on activity. But our goal every day is to continue to work to execute better and more efficiently and drive cost out of our supply chain through what we consume. And then the variable costs, if we can execute better than everybody else, we'll have better variable costs than everybody else. And that's always been our focus and will continue to be our focus going forward.

The second question is a quick one. I know the impairment charge is noncash price related primarily and also you have about 130 million barrels of the reserve revision due to the price. But $65 WTI [indiscernible] is really not that low. So still a bit surprising you have reserve write-down and also impairment charge. Is it driven from the order, is that all basically in the legacy Diamondback asset or is from Endeavor or from Double Eagle?

Yes, Paul. I mean, listen, fair value accounting is what it is. And fortunately, for us, the Endeavor deal was very well received and that deal was put on the books in September of 2024, at $80 oil and $4 Henry Hub. And I don't think there's an investor out there that would say, hey, that was a bad deal. So unfortunately, when you put something on the books at $80 and then you averaged $ 4 for a year. The market says you have to -- the accounting rules say you have to have a write-down. It's unfortunate, but at the end of the day, I think I stand with all of our investors that we're very excited and happy that we did the Endeavor deal and the accounting rules will be what they are.

At this time, I am showing no further questions. I would like to turn it back to Kaes Van't Hof for closing remarks.

Well, despite our prepared remarks and starting immediately, you guys all were able to ask 65 minutes worth of questions. We appreciate your interest, and thank you for the time today.

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

Good day, and thank you for standing by. Welcome to the Diamondback Energy Third Quarter 2025 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your first speaker today, Adam Lawlis, VP of Investor Relations. Please go ahead.

Thank you, Brianna. Good morning, and welcome to Diamondback Energy's Third Quarter 2025 Conference Call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback's website. Representing Diamondback today are Kaes Van't Hof, CEO; Danny Wesson, COO; and Jere Thompson, CFO. .

During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release yesterday afternoon.

I'll now turn the call over to Kaes.

Thanks, Adam, and I hope everybody read the letter last night as we've done in the past. We're just going to move straight into Q&A. So operator, let's open the line for questions, please.

[Operator Instructions] Our first question comes from Neal Dingmann of William Blair.

Nice quarter. Net-net, you back on. My first question is on activity. Specifically, while I know you guys continue to talk about the stop side scenario depending on the macro condition. It seemed like some other Permian operators who recently continue to accelerate even at these prices. So I'm just wondering, does sort of others, I guess, lack of capital discipline caused you to think about changing your plans given you all are a lower operator and I guess I'd say cash flows, cash flow.

Yes, Neal, I mean, I think we obviously track what everybody else is doing in the Permian. We have a lot of visibility into what's going on, but we also have a lot of conviction in where we stand and what our plan is, I think -- we can get into a game of who has the lowest cost structure reinvestment ratio, which we do. And on a year-to-date basis, we have a 36% reinvestment rate at mid-60s oil. I think that's something that would have been unheard of 6 or 7 years ago as investors pushed us to generate more free cash over cash flow. And I think that's the key point, right? We are focused on generating free cash flow per share, growing free cash flow per share over growing cash flow into a tenuous macro environment. Now when the assumptions change and the macro changes, we have the flexibility to change that. We're just going to do it with a much lower share count, lower net debt and off of a lower cost structure.

No, I'm glad to see that. I'm glad you're not changing the strides there. And then second question, I guess, more just generic, maybe Kaes for you or Danny, around Slide 8, specifically, continue to look at, I guess, I'd call it your development style versus others. And you continue to be lower. I'm just wondering specifically what differentiates your development style versus others? Is it larger projects? I mean does that factor in? Or what is the driver when I'm looking at this slide?

Yes. I mean, listen, I think Slide 8 is the most important slide in the deck. It explains a lot about what we've done to study development in the basin and improve our development over time. I think in our company history, Diamondback has been very well known to have the lowest cost structure and the best execution. But I think has been lost, not lost, but it hasn't been highlighted, which we're trying to highlight here is that not only are we drilling more wells per section, but the performance we have per well in that section, meaning the full section is developed in a more capital-efficient manner is resulting in a lot higher overall returns per section, right?

We famously moved to co-development in 2019. Now we're codeveloping all zones in the Midland Basin -- and instead of focusing on single well returns, we're really focused on what the return is per section and per DSU. And I'm really proud of what the 2 teams at Endeavor and Diamondback merged together and created the best of both worlds, right? You have the combination of the best inventory and the best cost structure resulting in the lowest reinvestment rate and the outputs you see on Slide 8. So I think it's a very important slide that I'd like investors pay a lot of attention to.

Our next question is from David Deckelbaum of TD Cowen.

Kaes, maybe you can talk about -- you guys talked about fourth quarter guidance and that sort of $925 million CapEx for 4Q as you kind of get back into more of a maintenance mode. Generally, I guess, are those -- is that a decent kind of run rate for goalpost for '26 to sort of hold that 505, 000 barrels a day of crude flat kind of pro forma for the Viper deal?

Yes, David, that's kind of the new baseline is 510 oil. We're going to sell some -- we announced the sale of some production at Viper, so we'll go down to 505,000 barrels a day kind of run rate in Q1. I think we decided to hold that production level flat, somewhere in the range of our Q4 CapEx is a good bogey to look at. And I'll kind of take you back to where we were in Q2. If you recall, our original budget this year for 2025 was $4 billion of CapEx that we cut by 10% immediately and then another $100 million after that. So CapEx was down $500 million from post liberation day moves that we made and we make those moves defensively thinking oil is going to get weaker a lot sooner. And as a result, production declined slightly.

So this year's number is a very good number. Anytime we slow down activity, CapEx is going to outperform the change in production. And now we're just kind of leveling off in this kind of, call it, $875 to $975 range to hold that new baseline of 510,000 barrels a day going down to 505,000 in Q1 of next year flat. So a lot of moving parts this year, but we felt like it was a year where we had to pivot midyear, given the concerns on both oversupply and the potential demand weakness. But overall, demand looks strong and supply is the hot debate now.

I appreciate that color. Considering it's the best slide in the deck, Slide 8, our most important slide, I feel compelled to ask a question on it. But when you look at those 3 graphs, as you move into more of the Endeavor acquired acreage in '26, should we anticipate any significant changes to those 3 graphs? Is it fair to assume that -- or can you talk to your confidence levels around well productivity as you kind of start harvesting and putting together these plans around some of the acquired pieces?

I'll let [ Al ] talk about the specifics, but I'll go back to the announcement when we merged with Endeavor. And we told our investors that are basically, if you took our pro forma average PV-10 per well and looked at it at the time of the deal, our next 5 years at the time of the deal was going to improve by almost 20%. And I think what you're seeing in Slide 8 is that synergy coming through because not only did we get bigger, but we got better when we did that deal. And Al, do you want to talk about '26?

Yes, David. I think if you look at the '25 well performance and compare that back to '23 and '24. It's very consistent. And as we look forward to '26, we expect that to be very consistent with the '24, '25 program.

Our next question is from Arun Jayaram of JPMorgan Securities LLC.

Kaes, I was wondering if you could start a little bit on the efficiency gains front and maybe elaborate a little bit on your further improvements on the drilling side and I'd love to get a little bit more insights on this continuous pumping design that you're now implementing on your houses fleets? And what could that do for your dollar per foot, which I think has been in that 550 to 580 range in the Midland Basin?

Yes, let me give you some high level and then pass it to Danny. But from a high-level perspective, this year, well costs have come down even in the face of steel tariffs hitting our business to the tune of about 20% of our steel cost. So it's a credit to the team that with the headwinds of something we can't control, steel tariffs hurting us, we've been able to find ways to increase efficiencies even without service costs kind of plummeting throughout the year.

So Danny, I don't know if you want to give some detail on continuous pumping and the drilling side.

Yes. On the drilling side, it's really been a story of getting more consistent with those kind of top 10% performance wells. And this quarter, we did about 1 out of every 10 wells was under 5 days, and we were talking about 1 or 2 wells in previous quarters that were under 5 days. So it's just getting more consistent, delivering this really, really impressive drilling results. And continue to drive down the average spud to TD days.

And on the completions front, the continuous pumping, we're really excited about while we're not modeling any material cost savings today. We do believe that getting 20% more lateral footage completed in a day pad level, we should see some savings flow through to that. It's just hard to model that today with the additional equipment and everything that we have to set up to get the crews all running on continuous pumping. But I do think the one thing that continues pumping and more lateral footage per day does for us is it improves the cycle times and get any production that we've watered out when we go in and frac in a continuous field, that production comes back online faster. And that's kind of one of the key benefits that will accrue to our shareholders over the long haul.

Super interesting. My follow-up is, Kaes, you brought back Slide 25, which is on power gen and some of the opportunities perhaps for Diamondback just given your surface acreage your natural gas output in West Texas as well as the fact that you do consume power for your own internal operations. I'm wondering thoughts on bringing back that side? And maybe just an update on your corporate development activities around this important topic at least for investors.

Yes. Jere is going to give you all the details. I would just say generally, we did that for a reason, and we're starting to get a lot more confidence in what could be an interesting story for Diamondback's development and gas pricing over the coming years.

Yes. Good observation, Arun. Last week, you may have seen that we committed up to 50 million a day of our nat gas to competitive power ventures for their new 1.3 gigawatt basin ranch power plant in Ward County. We expect this to be operational in 2029. This was done under a long-term supply agreement with pricing indexed to [ ERCOT ]. And we view it as a creative in-basin egress solution for our natural gas supply. And although in this particular scenario, it is low volumes. We feel it's a small piece and a much larger story for us, which is consciously moving away from Waha. And for reference there, by year-end 2026, we expect Waha exposure to be down to just over 40% of gas sales as compared to a little over 70% today. And additionally, we continue to work on other power projects that could potentially use cheap Diamondback gas and surface, deep blue water and near-term generation solutions to bring data centers to the Midland Basin. And as I mentioned last quarter, it's a long process, but we look forward to updating the market when we have a firm project to discuss.

Our next question is from Neil Mehta of Goldman Sachs & Co.

Yes. And Kaes, maybe to share your perspective on where we are with the macro. I think you indicated in the letter, you think we are at the yellow light right now. So maybe spend some time to think about how you're thinking about the moving pieces as we move into 2026?

Yes, Neil, I mean, we spent a lot of time, I think more time than ever this year on the macro. Unfortunately, we did have to put the yellow light in the release for the third time in a row. I would just say, generally, the outlook kind of remains murky. I think fortunately, it's a debate on the supply side. And it seems that, that debate will be resolved sometime in the next couple of quarters. But a couple of things, right? I would say our attitude is we don't control the price of the product we produce. And as an organization, we have 1,700 people focused on producing more well with less cost every day, and that's what they've done, right? We've been able to generate more free cash this year, 15% more per share despite oil prices being down 14%. So I can't turn the tone from, hey, this isn't great to we're going to figure it out and find a way because I think the longer this kind of murky macro last, the better things will be on the other end. And Diamondback in my mind, is going to be one of the long-term winners of whatever the macro presents to us.

And then the follow-up is just on M&A, and there's, I guess, 2 components to it. One, you guys have done a great job selling noncore assets. So just your perspective of -- are there other opportunities within the portfolio? And I think last quarter, you got -- there was a lot of attention on some of the comments about not being the seller, but I think you clarified your perspective on that. So just on those 2 points comments would be great.

Yes. I think on the noncore sales, first off, a credit to Jere and the team, we sold $1.5 billion of primarily 90% non-E&P producing assets at higher multiples than we trade. And that, in my mind, accrues straight to the balance sheet, puts our debt load in a good position for whatever the next couple of quarters may hold. So I think we've exhausted the majority of it. Viper, as you might know, also executed a noncore, our non-Permian asset sale with a good number that we'll talk about in a couple of hours. But all in all, we feel really good about being able to execute on these in a challenging macro at good valuations. .

And then on the other side of the question, we get that question a lot on our position in the industry. And I think, generally, Diamondback has the most coveted asset base in North America. And that's a very privileged position to be in. But we didn't just fall into it, right, we had to earn it acre by acre, and so we take a lot of pride in our execution and our execution machine and what that means for long-term shareholder value.

Our next question is from Phillip Jungwirth of BMO.

Circling back on the macro, I mean, I haven't gotten more capital efficient this downturn. Maybe it takes until '27, but curious how you see a green light scenario playing out for the Permian broadly. Can you just talk about how less capital efficient it is to grow first stay and maintenance as we saw in 2022? And do you think the industry has the capacity to really accelerate is called upon?

Yes. Phil, good question. I mean we're pontificating here, but I certainly believe the industry has the capability to do it. It's just a matter of how capital efficient it is. And my thesis is when it is time for the green light, which feels like going back to more of that 70% to 80% range on crude, the capital that you're spending is going to be -- have a much higher rate of return than it does at $60 oil. And it's going to be spent on a balance sheet that's shrunk as well as the share count that shrunk. So that's kind of our thesis there. I mean we're certainly generating good returns at $60. But I think today, we're conscious of the fact that adding crude to a market that is clearly oversupplied, the debate is how oversupplied is not a prudent decision today.

Okay. Great. And then coming back to Slide 8 here in the deck. I mean we did note that you're relative ranking on well productivity improved versus the peers. The question is more when you look at benchmarking on average wells per section, how much of FANG's leadership do you think can be attributed to you guys just have more core acreage, maybe less power and less Southern Midland exposure where you have your peer zones. Or do you think peers are still leaving behind quite a bit of child wells targeting best zones, which you also have a unique perspective in given the Viper?

Yes. Listen, I think high level geology matters a lot, right? And it's a huge driver. As we develop our acreage, we have different patterns in different areas. And even across a couple of miles, things change very, very quickly. But I think the high-level takeaway, and I can let Al give some more details, though, the high-level takeaway is if you multiply wells per section times well productivity per well, you get more oil per section or per DSU at a lower cost structure. And I think that means more PV per acre, and we got a lot of acres to do that on.

Anything you want to add there, Al?

Yes, Phillip, I think generally, definitely agree with you there, Kaes. You look at geology, obviously matters on Diamondback's position within the basin is very favorable. But I think if you dig into the details there, you'll find differences in development styles between operators just within similar geology. And I think we feel like the Diamondback development style is differential and really optimizes the return for every DSU and every dollar that we're investing there.

Our next question is from Bob Brackett of Bernstein Research.

I'm going to return to the theme around traffic light. If I contrast the weeks where you wrote the 1Q shareholder letter around the weeks after Liberation Day versus you writing the shareholder letter now. The difference is Liberation day was new. It was very kind of unusual strange environment. And right now, we're just kind of in a normal typical oil down cycle and therefore, you have more confidence in taking that CapEx right? Is that CapEx up? Is that a fair assessment?

Yes, Bob, I think that's fair. I think naturally, we're not -- we don't want to change, right? We don't like sudden changes that are unexpected. And I think I wouldn't call it a liberation day at Black Swan event for our industry, but it was certainly a change versus expectations going into the year. And I think high level, we were also pretty concerned with the potential demand shock that the numbers on the page of Liberation Day implied. I don't think that's ended up happening in terms of trade and global trade, but the jury is still out. But overall, I think we ended up getting more comfortable with demand and not as much of a supply shock. And again, that's kind of why I kind of say the attitude said, this is what it is, and we're going to find a way to make more money despite macro headwinds.

And I think the -- one of the things, Bob, sorry to cut you off. The one other thing that I hope whenever we come out of this, whatever this is, is that our long-term shareholders and long-only shareholders say, what is Diamondback do through this down cycle, however bad it gets. And if they look back and say, they didn't compromise the balance sheet, they bought back shares, they paid a dividend and production held in there. I think that's a case study for this new business model of the low reinvestment rate, high free cash flow that our business will never be not volatile, but did we reduce some volatility by our actions through the cycle?

Very clear. On the follow-up, you guys are hitting a shade over 4 zones per well, and that's the workhorses are the Middle Spraberry, Lower Spraberry and the Wolfcamp A and B. Year-to-date, you've got 6% of your wells hitting other zones. Is that a development strategy or an exploration strategy if I can sort of crudely contrast? Like are you learning stuff? Or are you just folding in that sort of fifth zone in workhorse mode?

Yes. I mean, I can give some details. At a high level, most of that is moving into development. There are zones we've tested but zones like the Upper Spraberry and the Wolfcamp D starting to get more capital while seeing less impact on overall productivity, I think, is a good thing for inventory duration.

Yes. It's really a combination of both of those strategies. So as Kaes mentioned, the Upper Spraberry, Wolfcamp D where those zones are perspective, we're really allocating capital to those and codeveloping with the more traditional sort of co-development zones within the Midland Basin. I think the other piece of that is a resource expansion story and looking at some of the deeper zones like the Barnett and the Woodford and delineating those are around the basin. And I think we're really excited about the results of those 2 zones and have some really promising well performance that will be public coming pretty soon.

Our next question is from Scott Hanold of RBC Capital Markets.

Can you obviously mentioned you hit your target asset sales. At this point, how do you view the equity ownership of those various interests you have and maybe specifically on Deep Blue, where there are future capital calls, like strategically, does it make sense to own them? Is there a monetization opportunity there?

Yes. Listen, I think the strategy of Deep Blue is playing out very nicely. I think they've done an incredible job building the third-party business. That was not something that we were probably built to do if it was 100% owned by Diamondback. So I think at a high level, we're very happy with our 30% ownership. It seems that market attention has increased on water and water management throughout the basin, and I think that's good for valuations. And then I think lastly, I think there's some tangential opportunities for Deep Blue when it comes to water for power needs and some of the surface use management that we can do at Diamondback in conjunction with our partners. So I think high level, we're happy with 30% at some point that business will monetize or look different than a large private investment. But right now, they're creating a lot of value in the shadows.

Got it. And the capital range you generally get for maintenance, any kind of equity interest capital call would be sort of included that or would that be outside of that?

That'll be outside of that, but we haven't seen one of those in a long time.

Got it. Okay. And my follow-up question is just you talked a little bit about like targeting zones and what you're all doing. But like can you -- with 2026, is there any kind of a shift in activity allocation across both like acreage regionally within the Midland or even does the Delaware get attention and do zones such as like the Woodford and Barnett get a little bit more attention as well?

Yes. I think the high level of the Delaware is going to get less attention even than this year. We're pretty well held over there. And most of the development sits further down in our development stack. But I do think you'll continue to see -- like you can see on Slide 15, the average percentage by zone in the Midland Basin continue to evolve with new zones being added in. And the challenge for the team is continuing to improve well productivity despite adding what people perceive as lower quality zones. But I do think we also have some more Barnett look for tests, and we look forward to the full kind of asset update on that zone at some point next year.

Al, do you want add anything on testing those zones?

I think that's right. I mean I think you'll see us continue to delineate those zones around the Midland Basin. And for '26, I would expect that, that percentage to tick kind of like you've seen over the past couple of years is as we figure out where the best well performance is throughout the basin and allocate capital appropriately.

Our next question comes from Kalei Akamine of Bank of America.

I want to follow up on the topic of maintenance capital at $925 million per quarter. Wondering if you can put some definition around that because headline production has moved around quite a bit in the last 18 months. So what is the associated maintenance oil production level maybe on an operated basis associated with that? And then is this spend level inclusive of all the ratable non-D&C spend?

Yes, Kalei, I mean, high level, right, it's some range of Q4. We recognize that the company stays flat for the following year, which is maybe the base case today. We'll see what happens in the next couple of months. Recognize that The Street likes to take Q4 numbers and multiply them by 4. And that's kind of why we put capital out there where it is. I still think there's a lot of things that could go our way. Efficiencies, steel prices, et cetera, that we have no visibility into today. But high level, total DC&E plus non DC&E CapEx is going to be somewhere in that range of outcomes we put out for Q4 multiplied by 4.

And I think if you normalize to where we were going into the year, right, last year, we were going to spend $4 billion for nearly $500,000 barrels of oil a day, and now we're going to spend somewhere in the range of less than that for about 510,000 barrels of oil a day. And I think I put that capital efficiency up with anyone as well as any year outside of this year in Diamondback's history.

We definitely do like modeling by multiplying by 4. For my second question, I appreciate that there's a lot of uncertainty around the '26 oil macro but you guys do have a very large backlog that gives you a lot of flexibility to shape a range of production outcomes for next year. So can you give us an update on where you expect to be with that backlog at year-end? And then talk about activating that? Do you intend to reach into that bucket as you kind of reset the efficiency in your frac operations through what you guys are calling continuous drilling? Or do you actually need to add another fact to tap all those opportunities?

Well, I think on the continuous pumping thing, exciting thing is that you use 1 less crew, most likely half to 1 less crew on an annual basis. But on the DUC backlog I think what -- with oil prices being hanging in there all year and with the efficiencies where they are, we've actually drilled probably more wells than we originally expected in the year. And so we're still well positioned to pull that DUC lever if we need to. I think a lot goes on behind the scenes here to make sure we continue to execute flawlessly and hit numbers and make what looks easy on the outside is actually a lot harder on the inside. So I think maintaining that DUC backlog is a structural advantage for us, particularly with our size and scale, and we're putting pipe in the ground almost as cheap as the COVID era days, that's I think that's good capital to spend.

Our next question is from Kevin MacCurdy of Pickering Energy Partners.

Kaes, in your shareholder letter, you mentioned the benefits of the [ Sitio ] acquisition for Viper and the potential M&A market for minerals and royalties. I wonder if you could just kind of expand on the benefits you see to Fang beyond just the cash flow contributions for the minerals?

Yes. I think I won't say for the first time, but I do think there's a huge asset at Viper that pay dividends at bank that's not just royalty interest, and that's this private data, right? We have private well level data on half of the wells in the Permian. I mean probably every major development or every major change in development is something we can see on a private level. And I think for the engineers that allows us to study others faster than anybody else. It also allows us to change how we do things faster than everybody else. And I think as the basin evolves, companies are going to be testing different things, some riskier than others and some things are going to work and some things are and we can replicate that very quickly at scale at Diamondback.

Al, do you want to add anything to that?

I think it's a huge advantage, like Kaes is saying to have the private data and have -- be able to understand not only what other operators are doing from a development standpoint, but also the actual well level performance and returns. And that's really differential to any other data source out there.

I appreciate the details there. And then for my follow-up, you mentioned earlier that you had 70% of your current gas volumes going to Waha and you expect by the year-end 2026 down to be -- that would be down to 40%. And I wonder if you could just walk through the pieces of what you've disclosed on where that gas will go, if not going to Waha?

Yes. We're beyond 2 of the pipelines coming on next year. Right now, we have a good amount of space on Whistler and Blackcomb and then whether -- what's the WhiteWater one coming on next year?

Blackcomb.

Sorry, one Whistler, Matterhorn today, Blackcomb comes on next year, that's another probably 200, 250 a day. And then post energy transfer by WTG, which we were an investor in, we've decided to work with them and commit some gas to that [ Heinson ] pipeline going east. And I think we've also then saved some gas to potentially go West should one of those pipelines get built and we have an opportunity to put gas on it or contribute a good amount of gas to a power project. And I think our investors demand us to do better on our gas realizations and we've listened to them, and I think it's coming.

Our next question is from Doug Leggate of Wolfe Research.

I wanted to go back to the question about the core inventory and the co-development. Obviously, when you talk about core, I think we've touched on this a couple of years ago, and I just wanted to get an update. You talk about core, you're generally talking about your best inventory but in the co-development, you're obviously bringing in lower than Tier 1 locations, I guess. So when we think about the 10 years of code inventory, what does that look like on a development cadence? In other words, is it 14, 15? Or how do you think about it?

Yes. I mean I'll let Al talk about what we put in a section to deem it core. But high level, we're completing about 500 wells a year and have about 5,500 core locations, which, in my mind, is sub-40 type inventory. There's a lot of other inventory that opens up at higher oil prices, but that's the inventory we would model in an acquisition and that's the inventory that we're developing today.

Yes, I got. I think when we kind of are thinking about how we design a DSU for development, we're -- looking at the zones or the highest rate of return zones first and then looking at the zones that would we can codevelop and would interfere with those other zones. And so really holistically looking at the DSU thinking about optimizing the landing points and the zones that are being developed within that DSU so that we don't degrade the well performance of those maybe not [ sander ], but lower tier horizons when we develop the core zones, right? So really trying to optimize so that we don't leave children wells, we don't leave stranded wells that we would then have to come back to. They would be severely degraded from an economic standpoint.

Yes. It's a user loses situation given the tank nature of the Midland Basin. And I think as Danny would say, we drill every fourth well for free relative to peers, and that allows us to add those zones and developments where others are not.

So would that uplift to 10 years to a bigger number then? Or is that included in the $500 per year?

It's a dynamic number, right? I mean there's going to be more wells added to it next year. I think the Barnett and Woodford will probably given recent results, be, in my mind, a Tier 1 development zone. There needs to be more well control and proof, but that's what we're working on every day.

Okay. Kaes, my follow-up is on gas. I mean, obviously, you touched on some of the pipes that are coming online. You guys do, I guess, about 500 a year. I'm trying to understand if you have your own solution outside of just waiting on someone else, adding infrastructure, whether it be a power deal or something else. But I mean, at the end of the day, $500 million a year is pretty meaningful for you for every buck change in gas price and you're kind of giving it away right now. So I'm just curious what's going on in the background in terms of how you improve your gas utilizations.

Yes. I mean we kind of laid out the new pipes that we're going to be on when they come on in '26. I'll kind of take you back to the history of our company is unfortunately, whether we like it or not, we grew through acquisition. And as we grew through acquisition, most of the acreage that we bought was already dedicated sometimes to the sister midstream company of the upstream company. So we've been working through that. I think with Endeavor, we actually got a lot of -- we actually had a lot of molecules free to make decisions on to move further downstream, which has been helpful.

And we now have the size and scale to be able to contribute to these various pipes to get to different markets and I think it's going to move to making sure we have the right diversity of markets downstream versus here with the power ticker being something that's exciting as well. So I think it's -- over the long term, we're doing the right things. It's not great over the next 12 months. We protected that with hedges, knowing that we couldn't control the molecules further downstream, but that time is coming.

Our next question is from Geoff Jay of Daniel Energy Partners.

I just had a quick follow-up on the continuous pumping. Just wondering how many fleets it's deployed on today. And I think you're running 5 memory serves and sort of how many will be rolled out in the next couple of quarters as you get to full deployment.

Geoff, yes, we're running 2 today and planning on converting the additional fleets as soon as possible, as soon as we can get all the equipment lined out hopefully in the next quarter and anticipate that we'll probably kind of run 4 full-time fleets with the fifth fleet bouncing in and out as needed in a maintenance type scenario.

Excellent. And then one quick follow-up on sort of base production work that you guys talked about last quarter. Are there any updates there? Are you -- any changes to kind of what you're seeing? Any improvements?

Yes. We continue to allocate capital into working over wells, older wells and optimizing the PDP tail and been really excited about some of the stuff we've seen, some of the results we've seen out of our assetization, oxidation, stimulation work. We're also trialing some other chemistries that we're doing some stimulation work down hole with and seeing some encouraging results early on. We don't have enough data yet to really talk about anything. But we continue to focus on optimizing the tail and deploying capital there. And we feel like it's some of the highest return capital we can spend, albeit, be it not large numbers, but if we can do the work to delineate what's working, we can scale it and hopefully become a significant part of our capital deployment in forward years.

Yes. And I think that's also a huge potential upside is as some of this work gets done and developed, can you lower your reinvestment rate? Can you move more dollars from the D&C side to post completion work or production work and lower that capital need to replace your production every year. And I've kind of said something in the letter never underestimate the American engineer, and we got a lot of engineers here working on the tail end of our production as that becomes a much more important part of our plan here.

Our next question is from Leo Mariani of ROTH.

Yes, you guys laid out certainly the case for yellow light and certainly talk about a bit how you might get back to the green light. I was hoping you could provide maybe a little bit more commentary on what you would kind of view a red light scenario as you roll into 2026 at this point. In terms of kind of cost and oil prices, any kind of high-level sort of indications to help would be great.

Yes. Leo, it's really the oil price, right? And I think if we start to print months consecutively in the 50s and print a month of near $50 oil. I think it's -- I think everybody should be looking at their plan and say, "Should I defer capital here at these prices." I think fortunately, given where Diamondback's position today, we don't need to be the first person to look at that. I think we can look at it behind the scenes, but we're executing year-to-date at $63 oil with a 36%, 37% reinvestment ratio. That's a very, very solid place to be in. Our dividend is not in danger. In fact, it probably has room to grow. Balance sheet strong, maturities are getting handled and costs are at COVID lows. So I think we're doing all the things we need to do to be prepared for worse, but also shine when things get better.

Okay. And then obviously, the yellow light scenario you guys have detailed kind of a number of strategies wanted to kind of get a sense just given the low reinvestment rate obviously, kind of how other uses of capital may come into play here. The buybacks were very healthy this quarter, which is certainly nice to see. But also wanted to see if you think in the yellow light scenario, perhaps other type of acquisitions, bolt-ons or whatever may emerge. It also could benefit the company. So maybe just talk a little bit about M&A use of kind of free cash flow there. And it certainly seems like the buyback has continued to stay pretty healthy. Just wanted to confirm that.

Yes. I think the primary use of free cash is still the base dividend. Second is buying back in our minds, at least 1% of our public float per quarter, and that still leaves free cash to do other things. I think the primary use after that would be continuing to pay down debt. But we're still doing little bolt-on deals here and there. I think there's a lot of big trades that we've been working on that are not -- they're cashless, but they're very value accretive. So yes, we're not sitting still here. There's a lot of things for us left to do. We're fortunate to have a very high working interest in everything that we develop. Viper continues to grow its business. But in terms of big M&A, I think Diamondback is going to be more selective. You've seen a few deals happen without our name on it. And I think we're in a good position.

Our final question is from Cheng Paul of Scotiabank.

Team, just curious that if we're looking at your program today, what percentage of the well that you are in the 3 months or longer? And if we're looking at over the next several years, based on your existing land position, how that program may shift? Secondly, that one of your much larger person is talking about proprietary technology using a lightweight proponent and that will help them to improve their recovery rate may be by, say, up to 30% I want to see if you guys have looked at that, how the -- is there anything similar in the market you can deploy or test it or that this is truly proprietary that, that's really nothing out there that you guys will be able to deploy.

Yes, Al is going to take the longer laterals and talk about what we've been working on. I'll take the second one.

Well, yes, so looking at the '25 plan, 3-mile laterals and longer. It makes up about 20%, 25% of the total program and really, I think the exciting part is kind of pushing to those extended laterals, right? So about 6% of the total was actually 17,500 or 20,000.

Yes, I think we've done some things on the longer laterals with different casing designs and pumping plans to improve results on the longer laterals over time. And then on your second question, listen, I think it's great that there's a lot of technology being tested out in the basin. I wouldn't sleep in our ability to continue to test different technologies to not only improve recoveries on the front end, but also as wells deplete increasing those recoveries longer that Danny talked about later in the tail and maybe some other things that we're working on as a group that we look forward to updating the market on. But I'd just say, Paul, on Slide 8, the results speak for themselves, and we're very proud of what we do at the cost structure we execute at. And those are the decisions we make to maximize returns and NPV per section.

Great. And my first question, when you're saying that it's 20%, 25% of [indiscernible] passport 2025, over the next several years, how that progress is going to look like?

Yes. Paul, it continues to grow and we can continue to push lateral length. And I think one thing we continue to watch is how some peers in the basin are getting created with pushing lateral length in DSUs with term wells and [ J-Hook ] wells and how can we -- thinking about how we can leverage that and longer DSUs to push lateral length even further beyond 3 miles and they're doing it today to take a 5,000-foot DSU and make it a 10,000-foot DSU. But we're really contemplating can we take that and take a 10,000-foot DSU and make it a 20,000-foot DSU. And I think as operators continue to push the limits on this stuff, we're going to watch it and deploy that technology rapidly, we can do it successfully and continue to lower breakeven.

Do you think that you can get to, say, 50% over the next 5 years?

Never got us, but I think today, it's hard to see.

You have a lot of engineer.

Yes. But today, I think next year, we expect lower length to be up, and we're going to keep working on trades and other things to keep them as long as possible.

Thank you. I am showing no further questions at this time. I would now like to turn it back to Kaes Van’t Hof for closing remarks.

Thanks, everybody, for taking the time today. We're always available to answer any questions you might have, and we'll talk to you in a few quarters or next quarter.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.