Q3 2025 Earnings Call Transcript

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, Briana. 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 issued 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. Nice to be back on. My first question is on activity. Specifically, while I know you guys continue to talk about the stop sign scenario depending on the macro condition, it seemed like some other Permian operators here recently continue to accelerate even at these prices.

So I'm just wondering, does this -- does sort of others, I guess, lack of capital discipline cause you to think about changing your plans given you all are a lower operator and I guess I'd say cash flow is 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. Glad you're not changing the stripes 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 styles versus others, and you continue to be lower. I'm just wondering specifically what differentiates your development style versus others?

Is it the 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.

What I think has been lost -- not lost, but hasn't been highlighted, which we're trying to highlight here is that not only are we doing -- 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 two teams at Endeavor and Diamondback have 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 to 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 -- the new baseline is 510 mbo/d 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 made 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.

Any time 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 million to $975 million 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, or most important slide, I feel compelled to ask a question on it. But when you look at those three graphs, as you move into more of the Endeavor acquired Acreage in '26, should we anticipate any significant changes to those three graphs? Is it fair to assume that, 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?

Yes, 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 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 and '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 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% on our steel costs. 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 those 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 on a 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 continuous pumping and more lateral footage per day does for us is it improves the cycle times and gets any production that we've watered out when we go in and frac in a contiguous 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. Wondering thoughts on bringing back that slide 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, Arun. 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 and Co.

And Kaes, maybe I get you 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 thinking 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 oil 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 kind of 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 lasts, 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 the follow-up is just on M&A, and there's, I guess, two 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 tension on some of the comments about not being a seller, but I think you clarified your perspective on that.

So just on those two points, comments would be great.

Yes. I think on the noncore sales, first off, 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 or non-Permian asset sale with a good number that we'll talk about in a couple of hours. But all-in-all, I 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 everyone's 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 if 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 a 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 your 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, less Southern Midland exposure where you have peer zones?

Or do you think peers are still leaving behind quite a bit of child wells targeting best zones, which you also have unique perspective in given the Viper?

Yes, actually listen, I think high level, geology matters a lot, right? And is 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're getting more oil per section or per DSU at a lower cost structure. 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 and 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 lights. 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 like change, right? We don't like sudden changes that are unexpected. And I think I wouldn't call Liberation Day a 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 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 said 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, one other thing, Bob, sorry to cut you off. But 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 did Diamondback do through this down cycle, however bad it gets. And if they look back and say, they didn't fully -- 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 Al can give some details. At 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, Bob, it's really a combination of both of those strategies, like Kaes mentioned, the Upper Spraberry, Wolfcamp D, where those zones are prospective, we're really allocating capital to those and co-developing them 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 around the basin. And, yes, I think we're really excited about the results of those two 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.

Kaes, 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 at 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 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 the 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 in 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 at the high level, 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 and Woodford tests and we look forward to a full kind of asset update on that zone at some point next year. Al, do you want to add anything on testing those zones?

No, 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 percentage to tick up kind of like you've seen over the past couple of years 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 if 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. We recognize that the Street likes to take Q4 numbers and multiply them by four. 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 four. 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 four. 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 DUC 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 frac to tap all those opportunities?

Well, I think on the continuous pumping thing, the exciting thing is that you use one less crew, most likely half to one 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 pays dividends at FANG 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 aren't, and we can replicate that very quickly at scale at Diamondback. Al, do you want to add anything to that?

No, 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 of where that gas will go, if not going to Waha.

Yes. Yes. We're going to be on two of the pipelines coming on next year. Right now, we have a good amount of space on Whistler and Blackcomb and then whatever -- what's the WhiteWater one coming on next year?

Blackcomb.

Blackcomb. Sorry, one Whistler, Matterhorn today. Blackcomb comes on next year, that's another probably 200, 250 a day. And then post Energy Transfer buying WTG, which we were an investor in, we've decided to work with them and commit some gas to that Hugh Brinson 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 realization 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. When 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 core 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 5,000 -- 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, Doug, I think when we kind of are thinking about how we design a DSU for development, we're looking at the zones, they are the highest rate of return -- have 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 in the zones that are being developed within that DSU so that we don't degrade the well performance of those, maybe not secondary, 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 use it or lose it situation like 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 the 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.

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 wells 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, $1 -- $500 million a year is pretty meaningful for you for every $1 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 realizations?

Yes. I mean we kind of laid out the new pipes that we're going to be on when they come on at the end of '26. I'll kind of take you back to the history of our company, 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 kicker 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 five if 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 two today and planning on converting the additional fleets as soon as possible, as soon as we can get all the equipment lined out. So hopefully, in the next quarter. And anticipate that we'll probably kind of run four 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 acidization, oxidation, stimulation work. We're also trialing some other chemistries that we're doing some stimulation work downhole 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 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, I think that's also 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 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.

You guys laid out certainly the case for yellow light and certainly talked 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 costs and oil prices, any kind of high-level sort of indications to help would be great.

Yes, Leo, it's really just oil price, right? And I think if we start to print months consecutively in the 50s and print a month 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 is positioned 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 is 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. I 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 that 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 is going to continue to stay pretty healthy. I 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 needs free cash to do other things. I think the primary use after that would be continuing to pay down debt.

But yes, we're still doing a 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.

Kaes, just curious that if we're looking at your program today, what percentage of the well that you are in the 3 miles or longer? And if we're looking at over the next several years based on your existing land position, how that program may shift? Second is that one of your much larger person is talking about their proprietary technology using a lightweight proponent and that will help them to improve their recovery rate maybe by, say, up to 30%. I want to see if you guys have looked at that out there?

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 can take the longer laterals and talk about what we've been working on. I'll take the second one.

Paul, 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 is 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 on 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, in 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 on my first question, when you're saying that it's 20%, 25% of 3-mile plus for 2025 over the next several years that how that progress is going to look like?

Yes, it, Paul, continues to grow, and we continue to push lateral length. And I think one thing we continue to watch is how some peers in the basin are getting creative with pushing lateral length in DSUs with U-turn wells and J-hook wells and how can we -- think about how we can leverage that in 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 if we can do it successfully and continue to lower breakevens.

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

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

You have a lot of [ front engineers. ]

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

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 in a quarter.

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