Diamondback Energy, Inc. (FANG) Q4 2025 Earnings Report, Transcript and Summary

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, Corey. 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, and 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.

Thank you for jumping right into it. 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, 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 the 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 and 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, right? And that's what we've got in the plot. The initial GORs are higher, right? So kind of in the 3,000 range. I think kind of what's striking when you compare the 6-month cum 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 GOR profile in the core zones 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 zone is 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. And the only 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 [ Gabrielle Cerny ] of William Blair Equity Research.

It's Neal. Sticking with the Barnett, could 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 cum 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, $500 or $550 for the Midland cost. So curious how you're thinking about total returns, Barnett versus just the Barnett -- or the Midland average.

Yes. Why don't I hit the high level and let Danny talk about how we're going to get the cost down. We -- high level, our core Midland development, which I would put as everything except the Wolfcamp D is close to about $510, $520 a foot. If we can get -- and 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 cum 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 kind of development mode and apply the techniques we've learned over the years developing what we call the Midland core with multi-pad development -- multi-well pad development, simul-frac. And those things are really just a decision to go to that full-scale development and see those cost savings accrue 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 sets 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 that the majority of the wells that we drill in that zone will be extended length laterals, 15,000 foot plus foot, which will also help drive down that per foot cost.

Great details. And then just secondly, case, 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 as 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 it's something that's top of mind for me and for the team. And 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 -- 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 & Company.

My first one means to hit on the implications from some of the Barnett disclosure while also still keeping in mind legacy Midland core operations. We took note of the strong oil cums 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 Woodford over time as well.

Yes. It's funny, Jeff. 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've 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 is also exciting to think about, which is the hyperscaler and data center opportunity that 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 added last year, the water supply potential, especially thinking about deep loop and of course, gas or power from your 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.

Yes, Jere is going to 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 surface 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-basin 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 think the one thing I'd add there, Jeff, 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 a great question.

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

I'll also give the Barnett more airtime here. 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 cums is 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 and 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 and to 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've 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's 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 it's -- 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 this stoplight 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 held 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 cum plot on Slide 12, it looks like the average well is delivering just under 50% more oil cuts 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?

Yes. 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 at the 12-month time frame, that roughly equates to the uplift that we see relative to the core zones on an EUR basis. So 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, case, in your shareholder letter, you mentioned how the company was testing for 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, a 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 the 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 DSUs that we've applied this 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 gravy, 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 is B 1.0, Arun, right? This is what Wolfcamp B fracs look like in 2014. So I think we got -- you 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 the top of the Wolfcamp versus the top of the Barnett are a couple of thousand feet apart. So not a whole lot of vertical depth. what's timing the drilling down there? Or is it on the completion side where those incremental costs are coming from? And what are some potential solutions?

Yes. 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 risk, 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 doing 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 pad development or 8-well pad development on the Barnett and utilize simul-frac, continuous pumping, the things that we've learned from our development in the Midland Basin core over the years.

That's all very clear. A quick follow-up, if I could. One of your peers had 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 staying home. And the Permian Basin has been very good to Diamondback, growing our position here. We're basin experts. And there may be 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 simul-frac e-fleets. And really, what that means is we just don't shut down between swapping wells in the simul-frac pad. And we've been averaging 4,500-ish feet a day on those continuous pumping fleets, but we've seen some results above 5,500 feet per day. So we're encouraged by that. We think we still have opportunity 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 less 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 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 that's going to have on OCTG because that flows through a different law as far as the tariffs go. But we reprice 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 of 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. I wanted to start with surfactants. From my understanding, the capital efficiency on using surfactants in 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, understanding 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 pumped. But I think if 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 anyways. So you're having to -- you have some costs and then you just pump 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 the 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 staying on the resource expansion theme, but given you guys are breather on the Midland Basin side, there's been a lot of buzz from industry on both the Barnett and Woodford in the Delaware. While I realize that EOG is chasing a different Woodford concept than 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 and TILs expected this year, the DUC backlog that supports that program? And then what kind of conservatism has been baked into the volumes, noting that surfactants and Barnett are kind of new efforts are contributing?

Yes. Listen, we try to simplify our disclosure to just 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 efficiency. So I think our transparency and disclosure is still best-in-class. We have -- certainly have a solid DUC backlog that we can push or 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 the 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. That'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 drilled 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 could 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 this inventory update.

Yes. 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 deserved.

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 as 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 $0.10 or $0.20 of hurt. 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 the couple of headwinds. On the GPT side, most of that's 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 the position and try to share facilities wherever we can because that's the most efficient form of capital use.

Yes. And I'll just add, I think we -- with the Barnett depth and with some of the mud properties and such that we'll be utilizing to drill those wells, it will probably be a different rig package that we're looking at. So we -- those rigs can certainly drill the Midland Basin core, but we're 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 mix in some of our Midland Basin core with. But if we can get days down on 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 a 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 pairs, 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 cums we've ever had at Diamondback. So I think we're putting a bet on ourselves to continue to improve results and get cost down, and that's a good bet.

Well obviously, it's early days, but -- 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 a kind of consistent weighted average well quality? Is it maintaining production mix? Or more importantly, is it maintaining free cash flow? How do you want us to interpret that 20-year comment?

Listen, I think not all inventory is created equal, right? The best -- and 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, which how we look at it, is 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 and 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 you 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 doing 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.

Kaes, if you can give us some color and context on your view of Diamondback's position in the industry going forward. I mean, historically, you all have built 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 continues to shrink in terms of the number of tickers. And I think generally, there -- 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 were 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 again in detail. The majority of our revisions are due to price. The rest of the majority of our revisions are due to PUD, we call 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 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 up.

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, Leo. 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, where 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 asset?

Yes. That's a general pace, and 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 dumb iron, just 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 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 and in your presentation talk about the Barnett. But in your shareholder letter, you referred 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 a Barnett Mississippian target there. But it sounds like as you guys are going into the more of the basin center here that it's a 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 divides the 2 reservoirs. So the Mississippian Lime sits between them. It 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 thick Miss Lime 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 Miss lime is materially thinner, and we're able to frac through it. But generally, we're targeting the lower Barnett and able to drain the Woodford in some of these areas where you've got that thinner Miss lime 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 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 start to -- 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 or well cost now you're already down 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 talked 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 of 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 has always done, we're not going to lit 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 zones. So that includes Wolfcamp D and some of the deeper stuff that in Barnett. And so yes, I think certainly, some of those 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 prowess to those zones and learn about them more and put the bid in them more. So yes, I do believe we'll see the $550 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 cost, 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 barrel of the reserve revision due to the price. But $65 WTI last year is really not that low. So still a bit surprising you have reserve write-down and also impairment charge. Is it driven from the -- or 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 average $64 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'm showing no further questions. I would like to turn it back to Kaes Van’'t Hof for closing remarks.

Well, despite no 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.