Good day, and thank you for standing by. Welcome to the Diamondback Energy's fourth quarter 2025 conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star one one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. 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, welcome everyone, to the fourth quarter earnings call. As usual, we will open up the line for questions. Hope everybody read the letter last night. A lot of good detail in there, and we look forward to discussing. Operator, please open the line for questions. Thank you. At this time, we will conduct a question-and-answer session. As a reminder, to ask a question, you will need to press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster. Our first question comes from Neil Mehta of Goldman Sachs. Neil, your line is open. Yeah, good morning, Kaes and team. Thank you for jumping right into it. No surprise that the area we want to dig into here is the Barnett, Kaes, and just talk about, you know, what you think the opportunity set is. You are deploying more capital here in 2026. You know, how you think about the potential returns associated with it and just the mix as well between oil and gas. Yeah, Neil, I'll give you some high-level thoughts and then turn it over to Al. You know, it's a pretty exciting reveal of, you know, our position in the Barnett. You know, that's a position that, you know, was essentially almost zero acres a couple of years ago. We were able to, you know, grow that position without, you know, cap raises or press releases or buying the next, you know, private equity-backed entity. You know, I think overall, you know, being able to build a position in our backyard that we understand very, very well, is going to be very, you know, good for our shareholders long term and good for corporate returns long term. You know, we're not having to pay, you know, $3 million, $4 million, $5 million, $6 million a stick to build this position. You know, that's a testament to the team having belief in, you know, the rock. Now that we've put the drill bit in the rock, you know, we found that, you know, the returns, you know, look very good from a productivity standpoint. The next step is we have to get the cost down. You know, we haven't really moved to full field development. You know, that's gonna start here in the second half of 2026 in earnest and pick up in the coming years. I think it's a good time for us to reveal what we have. We're not done yet, but, you know, wanted to show our investors, you know, what we've been up to. You know, that resource expansion is an important part of our overall story. I'm gonna turn it over to Al for some details and what he's found from a technical perspective. Yeah, 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. The, I think the performance really stands out and speaks for itself. You know, I think when we're able to get the cost down, you know, 20%, kind of from where we are with our delineation wells here, we think these returns are gonna be competitive. We're pretty excited about the potential here, 900 gross locations. You know, I think we'll be allocating capital to the plan more going forward. Yeah, 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. 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. Yeah, I think just looking at the absolute oil production, you know, you can see that's even differential, right? That's what we've got in the plot. The initial GORs are higher, right? You know, kind of in the 3,000 range. I think kind of what's striking when you compare the six-month cume oil and BOEs to the 12-month, kind of see a flatter GOR profile, right? Through the year, especially relative to the core. 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. Core zones like 80% oil, for that 1st six months, it goes down to about 75% oil. The Barnett plan that we're showing here, is set 67%, basically flat for the 1st 12 months. 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. Yeah, Neil, you know, one thing I'd add is, you know, whether the timing is planned or not, you know, we do have a Permian Basin that's gonna have a lot of gas takeaway coming on in the 2027-2030 time frame. You know, we're gonna 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, you know, vertical production or production in the core zone. You know, we got a lot of drilling to do, but, you know, getting a good price for our gas and our liquids, you know, is gonna be a benefit to returns in the 2027+ time frame. All right. Thanks, Kaes. Thanks, Danny. Thanks, Neil. Thank you very much. Our next call comes from the line of Gabrielle Cerny of William Blair Equity Research. Gabrielle, your line is open. Hey, Kaes, it's Neil. Hey, Gabrielle. Hey, sticking with the Barnett, can you talk about the well economics there versus the Midland Basin? I guess what I'm getting at is, I'm looking at Slide 12, it shows that your Barnett wells, you're talking about kind of a 36 MBOE per 1,000 foot, 12-month CUM versus 22 for the core Midland, yet, you know, you talked about maybe that $100 per lateral foot Barnett versus what are you down to? I think $550 for the Midland cost. Curious how you're thinking about total returns, Barnett versus the Midland average. Why don't I hit the high level and let Danny talk about how we're gonna get the cost down? You know, we, you know, high level, our core Midland development, which I would put as, you know, everything except the Wolfcamp D, is, you know, close to about $5.10-$5.20 a foot. If we can get. The Barnett, you know, today is at $1,000 a foot. If we can get the Barnett down to $800 a foot, and, you know, the Barnett, you know, oil production is 60% better on a first year CUM than the core, then the returns start to get competitive. I think we're fortunate that the rock has been proven first, and then the costs will need to come down. You know, Danny has a few examples of how we're gonna do that. Yeah, 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, you know, learned over the years, developing the what we call the Midland core, with, you know, multi-pad development, multi-well pad development, simul-frac. Those things are really just a decision to go to that full-scale development and see those cost savings accrue to that, to the Barnett development as well. On the drilling side, you know, 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, you know, cut a lot of cost out of the drilling part of the well. Also we think, you know, the Barnett, the leasehold we've established in the Barnett sets itself up well for extended lateral development. We're kind of targeting, you know, 15,000 foot laterals in the Barnett. You know, it won't be everywhere, but we hope the majority of the wells that we drill in that, in that zone will be extended link laterals, 15,000 foot plus foot, which will also help drive down that per foot cost. Great. Good details. Just secondly, Kaes, my second is on inventory. By the way, thanks for disclosing. I don't think versus any other companies have this kind of similar details around that. I'm wondering, could you just address, maybe, talk about inventory replenishment and reinvestment in your existing asset base? Is it, you know, appears when you add the Barnett to your total drilled feet, year-over-year, only decreased minimally. I'm just wondering how you're thinking about inventory replenishment and reinvesting going forward. Yeah, I mean, listen, we're in a depleting business, right? You know, we think about inventory every day. Diamondback was a company that went public with, you know, very little inventory and had to work for every stick that we added over the last 15 years. Something that's top of mind for me, for the team. If you look at, you know, the inventory disclosure we put out, you know, the team did a very good job increasing our average lateral lengths last year, you know, up by about 600 lateral feet on average, which that's a big number on a big company. You know, I think, you know, we're gonna continue to try to add inventory where we can. You know, if you notice, like I said earlier, you know, all this inventory was added and, you know, put in the plan without, you know, needing outside capital or press releases, all while still returning a ton of cash back to shareholders. I think, you know, you should expect that to continue. I think we kind of have a philosophy here that, you know, no deal on inventory in the Midland Basin should leave Midland or leave Diamondback without us taking a look at it. You know, we're highly focused on continuing to replenish our inventory. We recognize that it's not infinite, but I think, you know, we have a plan to continue to grow it. Perfect. Thanks, buddy. Thank you very much. Our next call comes from the line of Jeoffrey Lambujon, Jeff of TPH & Co. Jeoffrey, your line is open. Good morning, Kaes and team, and thanks for taking my questions. My first one means to hit on the implications from some of the Barnett disclosure, while also still keeping in mind, legacy Midland Basin core operations. You know, we took note of the strong oil cumes from both data sets in the slide, as you guys have spoken to already, and obviously, the productivity for the Barnett looks strong as well on an absolute basis. 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. you know, it's funny, Jeff, you know, we have a $3.75 billion budget, and $150 is, you know, allocated to the Barnett, but it's getting all the airtime. you know, 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, you know, we have enough of it. you know, at the end of the day, you know, what the teams are doing on the core inventory, you know, the vast majority of our budget is very impressive. You know, lateral lengths, up year-over-year, productivity, you know, in a world where productivity is being questioned on a per foot basis. In many basins, you know, the team was able to, you know, increase productivity in 2025 versus 2024 on the oil side. That, you know, that just means we're continuing to test things in terms of, you know, stage lengths, stage designs, where we're putting the drill bit, spacing, you know, all the zones that we're developing. You know, the results, you know, kind of speak for themselves. You know, I think generally, with the Barnett becoming a bigger piece of the capital pie, oil mix, you know, will go down over time, which is why we've tried to focus more and more on our gas marketing strategy and getting, you know, better realizations on that front, because I think it can really help, you know, overall free cash and corporate returns, you know, kinda after these pipes come on in the back half of 2026. Perfect. That's very helpful. 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 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 over last year, you know, the water supply potential, especially thinking about Deep Blue and of course, you know, gas or power from the upstream business. I wonder if we could just get a refresh on how discussions are progressing there and how you're thinking about those opportunities in general. Yeah, Jere, yeah, take that one. Yeah. Morning, 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. We're making progress on bringing data centers, you know, onto our surface position. You know, 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. Just another creative tool in the toolbox for us as we are thinking about, you know, improving natural gas realizations, which we obviously highlighted in the deck and Kaes alluded to earlier. A new meaningful in-basin and egress solution for us. We continue to make progress. We're excited about the opportunity, and when we have more to discuss publicly, we'll definitely do so. I'd say the only thing I'd add there, Jeff, is, you know, we're not gonna announce anything until it's completely binding, and we can talk to our investors about what it means for them. You know, there's been a lot of noise in this, in this space. I still continue to believe, you know, given our size and scale and expertise in the basin, we offer the full package, and conversations have improved. You know, we're not gonna talk about it in detail until we have, until we have those details. A great question. Perfect. Appreciate that. Thank you. Our next call comes from the line of Phillip Jungwirth from BMO. Phillip, your line is open. Yeah, thanks. I'll also give the Barnett more airtime here. Appreciate you bringing resource expansion back to the E&P sector. The Midland Basin, it's obviously a large area. 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? Yeah, you know, I think the big distinction that we kinda 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 2010s, that has lower maturity, so more within the oil window. That comes along with lower bottom hole pressures. What we've seen in terms of, you know, 30-day IPs and six-month cumes is the well performance in that area where the play kinda kicked off, is not as strong and robust as 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, you're getting higher initial rates. we're still kind of delineating around, the basin, especially as you move to the east, and to the south. So there is gonna 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 thickest resource, and then the potential, to drain potentially the Barnett and the Woodford reservoirs with a single wellbore. We believe we've put together a really strong position, in the best resource quality within the basin. That's great. You called out Diamondback having nearly two decades of inventory at its 2026 pace. last year, there was a lot of talk about peak Permian, who has inventory to grow, who doesn't. 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? I mean, listen, I think that's highly dependent on the macro. You know, in general, it feels like investors, you know, over time, you know, want some form of growth. We've done it on a per share basis for the last few years. At some point, you know, organic growth is gonna come into the equation. You know, unfortunately, we're still stuck in this yellow light, in this stoplight analogy that we can't shake yet. You know, I think there's probably a world where if we can efficiently allocate capital and growth becomes kind of the output, you know, that's probably a good decision. I think, for 2026, you know, we're starting the year here, you know, still in this kind of quasi yellow light, where, you know, oil production is the input, and then CapEx will be, you know, reduced if things go well, and then held steady if things, you know, go as planned. There could be a world where we hold CapEx flat and see what growth, you know, comes out of it. That day is not today, but there will be a time, and that's why, you know, every day we think about inventory duration, inventory growth, and, you know, things like the Barnett, which is getting a lot of airtime today, you know, are accretive to that long-term duration story. Thanks, Kaes. Thank you. Thank you very much. Our next question comes from the line of Arun Jayaram from J.P. Morgan Securities. Arun, your line is open. Good morning, gentlemen. I also have a follow-up on the Barnett. Yeah, just to 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, you know, in terms of oil growth over time, 'cause 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. If we could maybe translate that into an oil EUR for an average well based on your tests so far. Yeah, I'll let Al give the EUR commentary. I think the one thing I would say, you know, if you start to run these wells at $800 a foot or close to it, you know, the rate of return relative to the base plan looks very comparable, but the PV is significantly larger. You know, we look at both of those things, PV and rate of return, and try to find a nice balance there. You know, the key here is getting these costs down. It makes the returns competitive, particularly in areas with Viper minerals, but then, you know, the PV impact is huge. From an NAV perspective, that's very positive. Now, I'll turn it over to Al for some type curve commentary. Yeah, Arun, you know, that 50% uplift that you kind of see at the 12-month timeframe, that roughly equates to the uplift that we see relative to the core zones on a EUR basis. You think about our core zones, those are about 50 BO a foot in the Midland Basin. Right now, in the Barnett, we think we're pretty close to about 75 BO a foot for the ultimate recovery for those wells. That's helpful, Al. Just on my follow-up, I was wondering, Kaes, in your shareholder letter, you mentioned how the company was testing for surfactants. 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 activities? Give us a sense of what you're seeing thus far and how you're using those in terms of your development scheme? Yeah, you know, it's early in the surfactant game, but it's exciting. We did a 60-well test in the second half of last year. You know, credit to the team to mobilize that quickly. You know, this went from an idea in June to execution by December, and we got a lot of data coming in, you know, from those tests. You know, we focused on the production side for now, so that we can, you know, try to figure out which variables are working. I do think, you know, there's been some discussion about adding this to the front end on your completion. I think we're gonna test that, but we're also gonna continue to test, you know, the production side of the business. From a high-level perspective, you know, in my mind, this was something that no one talked about outside of, you know, papers, SPE papers four or five years ago, and now it's becoming something that can potentially be economic. I think that is why we put in our last shareholder letter, you know, never underestimate the American engineer, because there's still a lot of oil in the ground in the Midland Basin and in the Permian Basin that needs to be extracted. It just needs to be extracted economically, and that's what we're working on today. Al, you wanna talk about the tests? Yeah. Like, like Kaes was saying, we trialed 60 treatments, kinda in the back half of 2025. A lot of lab work and technical work going into, you know, designing the surfactant for the specific rock types and the specific surfactant types that we're using. It's, it's pretty early on in the results, but, you know, we've seen, at least in a handful of the DSU that we've applied this to, some really exciting results. The team is taking that information and going back, refining the chemical makeup there and the design of the test, and, you know, really trying to hone in on the variables that are driving the performance for the program. You know, I think this is all Grady, right? This is all added production, added reserves to something that, you know, we didn't think was possible a few years ago. I'd say this is V 1.0, Arun, right? This is what Wolfcamp B fracs looked like in 2014. You look how far we've come in 10 years, and again, you know, this is a highly technical organization that's gonna work to figure some of this stuff out. Great. Thanks, Kaes and team. Thanks, Arun. Thank you. Our next question comes from the line of Bob Brackett from Bernstein Research. Bob, your line is open. Good morning, I'm gonna 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. You know, the top of the Wolfcamp versus the top of the Barnett are a couple thousand feet apart, so not a whole lot of vertical depth. What's stymieing the drilling down there? Is it on the completion side, where those incremental costs are coming from? What are some potential solutions? Yeah. Hey, Bob, thanks for asking. You know, it's really just a different resource altogether, and, you know, we've got to set up a drilling program that's, you know, a little bit different than what we do in the Midland Basin core. You know, 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, you know, as I alluded to earlier, to de-risk any kind of operational issue as we were delineating this play. I don't know, I expect we're gonna continue to be a little bit more conservative as we roll into development mode on the drilling side, but we'll start doing things that we know, through calculated risks we can do to cut costs out of those wellbores. On the completion side, too, you know, there's some additional costs there. The jobs are a little bigger. We're targeting four wells a section in the Barnett, so we're pumping, you know, larger jobs to try and generate a larger simulated rock volume across those four wells. You know, we've been only on doing one or two well pads, so a lot of single well or zipper fracs. As we move into development, we're gonna move into, you know, full scale, four well pad development or eight 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. Quick follow-up, if I could. One of your peers talked last week about international opportunities. I'm curious, where do international opportunities sit on your list of strategic priorities? Yeah, Bob, I mean, it's certainly low from a strategic perspective. I would say, you know, a company of our size should start to understand what else is out there around the world, and really, for the main reason of, you know, what else around the world could push us out on the, on the global cost curve. You know, we've spent a lot of time studying that. Obviously, there's different dynamics above ground and below ground around the world. I think what's, you know, what that's taught us is, you know, we have a very, very good long-duration inventory in the Permian Basin. You know, now there's things like the Barnett and surfactants and all that kind of stuff that, uh, you know, we're gonna be talking about a lot over the next three to five years. You know, that just kind of points me back towards staying home. The Permian Basin has been very good to Diamondback, you know, growing our position here. You know, we're basin experts, you know, there may be good rock around the world, but there's a lot of, a lot of other issues that, you know, that come with that rock. You know, we've learned a lot about what's out there, but, you know, there's not a lot of action that we're focused on today. Very clear. Thanks. Thank you. Our next question comes from the line of John Freeman of Raymond James. John, your line is open. Good morning. Thank you. 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 2026 plan and just where you all see that potentially getting to by year-end? Hey, John, thanks for asking. Yeah, I mean, the core program still continues to really shine, and Kaes put some commentary in his shareholder letter around, you know, some of the continued efficiency improvement we're seeing on the drilling side and the completion side. You know, on the completion side, the team's been working on implementing what they call continuous pumping across all of our simul-frac e-fleets. You know, really what that means is we just don't shut down between swapping wells in the simul-frac pad. You know, we've been averaging 4,500-ish feet a day on those continuous pumping fleets, but we've seen some results of above 5,500 feet per day. You know, we're encouraged by that. We think, we still have opportunities to reduce our cycle times this year. You know, if that comes to reality, we're gonna be able to, you know, get rid of some frac crews and be able to, you know, hopefully complete less wells in the year to achieve, you know, our production targets. You know, I think one thing I'd add, John, that we're kind of finding out, you know, we're really starting to test different stage lengths, stage designs, frac designs, and what continuous pumping does is it removes the biggest piece of non-productive time to swapping between your stages. You know, we're gonna test shorter stages. We're able to do that with, you know, less cost. I mean, all these things are little wins that, you know, accrue to our shareholders. You know, 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? That's what's exciting there too. That's really helpful. Then just my follow-up, you know, tariffs have been pretty topical of late. Have you all secured or maybe locked in the pricing on y'all's steel-related products for the 26 program? The way our, our procurement agreements work on the, you know, casing side of things, it's kind of a repricing quarterly. You know, with the tariff ruling that was just announced last week, we're not sure how much impact that's gonna have on the CTG, because that's, that flows through a different, a different, you know, law as far as the tariffs go. You know, we reprice our casing every quarter based on an index price with our supplier. You know, on the tubular goods, we do procure those things out in longer lead times if we feel like we've got, you know, an opportunity to secure some at a beneficial price. You know, we kind of watch that market and just make those decisions based on where we think the market's headed. You know, 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. 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 gonna 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. Thanks, guys. I appreciate it. Thanks, John. Thank you very much. Our next question comes from the line of Derrick Whitfield of Texas Capital. Derrick, your line is open. Thanks. Good morning, all, and congrats on a strong year-end. Hey, Derrick. 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? 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 the URAs on new wells? Yeah, I don't know if we're seeing enough yet at Viper to make that distinction. You know, we don't have all of the, you know, private data on designs and what, you know, what got pumped. You know, I think if we start to see overall productivity improvements from peers, you know, 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, you know, tested 60 wells, you know, they're fairly cheap jobs, about a half a million dollars, and I think we can work those down. You know, what we did was we did the jobs when we had to pull the ESP anyways. You're having to, you have some sunk costs, and then you just pump some surfactant and water. 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, you know, multi-hundreds of barrels a day uplift from a well that's producing a couple hundred barrels a day. I'd say, you know, on average, you know, we've seen about an average of about 100 barrels a day pop, you know, which for half a million dollars is a high-returning project. You know, I think we gotta get smarter on it. We're gonna keep testing it. I think. Over time, as we refine that analysis, it's going to become a part of our, you know, overall development plan and life cycle of these wells. That's how I see it today. I, you know, I look forward to you know all of the advancements that the teams are gonna make. You know, we've made a lot in a short period of time. There's gonna be a lot to come in the next couple of years. Great. Maybe staying on the resource expansion theme, but giving you guys a 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 in Pecos, I'd love your take on the view of that interval and your position over in Pecos. I think generally, you know, we've been following it. It's gonna be more expensive than, you know, than the Midland Basin, Barnett, even. You know, I kind of equate the Midland Basin Barnett to kinda core Delaware-type costs, this is below that. You know, there's been people poking around Barnett and Woodford and the Delaware now for seven or eight years. You know, I don't think we're ready to begin a big program in the Delaware on our position, you know, with the Viper map being as consolidated as it is on the Delaware side, we're gonna learn a lot about it as people try to test it. Great update. Thanks for your time. Thanks, Derrick. Thank you very much. Our next question comes from the line of Kalei Akamine from Bank of America. Kalei, your line's open. Hey, good morning, guys. Hey, Kalei. 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 fills expected this year, the DUC backlog that supports that program, and then what kind of conservatism has been baked into the volume, noting that surfactants and Barnett are kind of new efforts here contributing? Listen, you know, we try to simplify our disclosure to just say, you know, here's the amount of lateral feet we completed or plan to complete. If we, you know, do better than midpoint or towards the low end, that means we have, you know, high capital efficiency. I think our transparency and disclosure is still best in class. You know, certainly have a solid DUC backlog that we can, you know, push or pull on, depending on the macro, I think that's gonna be a management decision. You know, right now, the base case is just kinda hold it flat. You know, one thing I'll say about the 2026 CapEx guide, you know, 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. You know, 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, you know, if those things start to trend our direction, then I think, you know, there's a world where, you know, CapEx comes down this year. That's just not something I think, you know, given our history of conservatism, we want to, you know, put out as fact today. You know, 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 gonna run through guidance yet. I guess the follow-up there is just on the number of drills contemplated. 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? Yeah, I mean, on the working interest side, we're always looking to increase working interest. You know, 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. I mean, you know, 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. You know, buying minerals and all the things that we do to add value around the base business. You know, on your second question, you know, the model doesn't show us, you know, drawing or building a meaningful amount of DUCs this year. You know, I think we're still gonna post how many wells we drill and complete every quarter. I think, you know, if you think about last year, we ended up drilling more wells and completing less wells than we originally expected. You know, what, the DUC discussion became a discussion that, you know, got more airplay than it deserves. That's very helpful. Thank you, Kaes. Thank you very much. Our next question comes from the line of Kevin MacCurdy from Pickering Energy Partners. Kevin, your line is open. Hey, good morning. 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, you know, 2026 guidance is for a small increase for both LOE and GP&T. I wonder if you could address those. You know, is that just the water drop down on LOE and gas transportation contracts on GP&T, or is there anything else in there? That's most of it, Kevin. You know, we sold the EDS system to Deep Blue in fourth quarter, so you saw LOE tick up a little bit. I think, you know, we got a couple things as headwinds this year on LOE. You You know, power prices in the basin have gone up. We got some power that is now unhedged. That's going to be, you know, priced at a higher number. That's, you know, probably a dime or two of hurt. You know, we're continuing to spend more and more dollars on workovers, you know, plugging and abandoning vertical wells, you know, making sure our asset base is, you know, in good condition on that front. Those are the couple of headwinds. On the GPT side, you know, most of that's your traditional escalators on CPI, but also, you know, more barrels, or sorry, more molecules being taken in kind. You're shifting dollars from realizations to 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, you know, 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. You know, there's areas like Spanish Trail, where we have 100% of the minerals and high working interest that, you know, we're going to be, you know, in the same area as our shallow development. Then there's areas where we don't have it. I think, you know, overall, though, we're going to continue to build a position and try to, you know, share facilities wherever we can, you know, because that's the most efficient form of capital use. Yeah, I'll just add, I think, you know, we with the Barnett's depth and with some of the, you know, the mud properties and such that we'll be utilizing to drill those wells, it'll probably be a different rig package that we're looking at. You know, we those rigs can certainly drill the Midland Basin core, but probably looking at, you know, a little bit upgraded rig package for those wells. Ideally, we'll have them all on separate rig lines that we may mix in some of our Midland Basin core with. If we can get days down, you know, on the Barnett drilling, we'll mix in more of our core development and, you know, probably have less Barnett-directed rigs in particular at the end of the year. Appreciate it. Thanks, guys. Thanks, guys. Thank you. Our next call comes from the line of Doug Leggate from Wolfe Research. Doug, your line is open. Good morning, guys. I wonder if I could follow up on the last question about the, you know, the mix of Barnett versus the base business. It seems there's obviously an HBP requirement here, given the relatively new acreage. 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, you know, the cube development elsewhere. How do you expect that development type curve to evolve relative to the base business? Yeah, I mean, I think we'll see, Doug. You know, I think we're spacing these wells pretty wide. You know, we have done a few 2 well pairs and, you know, we'll still see what a full section development looks like. I think in general, you know, the size of the job, you know, and the, and the spacing that we're assuming, you know, should result in, you know, pretty consistent performance. You know, 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, you know, probably the highest six-month cumes we've ever had at Diamondback. I think we're putting the bet on ourselves to continue to improve results and get costs down, and that's a good bet. Obviously, it's early days, thanks for the color. My follow-up is on the inventory question. I know there's no precision here, I want to understand what your intention is in talking about 20 years. Is that a, you know, a kind of consistent, weighted average well quality? Is it maintaining production mix, or more importantly, is it maintaining free cash flow? How would you, do you want us to interpret that 20-year comment? Listen, I think, you know, not all inventory is created equal, right? If we're doing our job right, we're drilling the best stuff first. You know, I think you see that throughout the space where, you know, productivity per foot, which how we look at it, you know, is starting to degrade depending on the company. You know, our job is to have the best productivity per foot, the longest. You know, I think you've seen us add in zones like the Upper Spraberry, like the Wolfcamp D, you know, even five years ago, the Middle Spraberry and Jo Mill, and you haven't seen significant degradation. In fact, you know, 2025 results were above 2024. In a world of decreasing productivity, our ability to maintain that productivity consistently and longer, you know, is, I think, a winning proposition. you know, certainly as you get further down our inventory, you know, we're going to have lower productivity. I'd be lying to you if I said otherwise. The teams continue to work on ways to reduce costs, drill better wells, better frac jobs, get better well performance out of areas that, you know, we thought were tier two, tier three, you know, three, four, five years ago. In general, it's about drilling the best stuff first and maintaining that sustaining free cash flow that you'd like to talk about. you know, I think we can do it longer than anybody. Great. Thanks, Keith. I appreciate the answers. Thanks, Doug. Thank you. Our next question comes from the line of Scott Hanold of RBC Capital Markets. Scott, your line is open. Yeah, thanks. you know, Kaes, if you can give some color and context on your view of, the, you know, Diamondback's position in the industry going forward. I mean, historically, you all have, you know, built your position through successful M&A, and, you know, obviously, 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 had been? Yeah, I mean, you know, Scott, there's no doubt that there's been a ton of consolidation, you know, both in the Permian and elsewhere around the US. I mean, you know, it's been top of mind. I mean, you know, your website, the RBC website, continues to shrink in terms of the number of tickers. I think, you know, generally there, things have moved towards basin champions. I think, you know, in the Permian, there's gonna be independent basin champions like Diamondback. There's gonna be mineral champions like Viper, and there's gonna be, you know, surface champions, like some of the other companies out there. That natural consolidation has led us to say, "Hey, we have a ton of, you know, we have a ton of acreage and a ton of resource. We should probably start to spend some more $ improving that existing resource." You know, we're not out of the M&A game, but, you know, as we said in the letter, the opportunities are fewer and further between, and therefore, you know, we're gonna be doing more things like the Barnett, more things like testing surfactants. You know, 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, you know, 10, 20, 30 deals left to do. Thanks for that. My follow-up is on your reserve report. You all mentioned there were some revisions to, you know, some of the numbers in there, and I know some of it's price related, but you did mention some performance-related revisions. Can you just give us a little bit of context behind that? Yeah, I mean, the majority of the reserve revisions, and, you know, it's interesting that reserve reports are now becoming something people read again in detail. The majority of our revisions are due to price. You know, the rest of the majority of our revisions are due to, you know, we call them pod downgrades, but it really just means, you know, we're bringing in wells that we acquired or pods that we acquired, and bringing those to the front of the development program. You know, in general, we try to keep a very low pod balance. You know, the SEC rule is five years of development. In general, we're kind of averaging three years of development in what we put in our pods. Right now, Diamondback, from a booking perspective, we're 70% PDP, 30% pods. You know, I think, you know, as we do big deals like Double Eagle last year or Endeavor the year before, you know, some of our existing pods get taken out and new pods get put in. You know, from a performance perspective or PDP performance perspective, there have not been, you know, meaningful changes to the reserve report. Okay, the individual wells are still holding true. It's just a shift in the pods moving in. Is that right? That's right. Just moving your best wells that you have remaining up. Thanks. Thanks, Scott. Thank you. Our next call comes from Leo Mariani of ROTH. Leo, your line is open. Hi, I wanted to just revisit the Barnett, you know, here quickly. Can you give us a rough sense of the number of wells that you guys are gonna be, you know, drilling or completing here in 2026? Can you just talk about what you kind of need to do to hold that position, you know, say, over the next five years? Is there gonna be a meaningful step-up in activity in 2027, 2028? Yeah, 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. Roughly, you know, we're looking at drilling about 30 wells this year, popping probably closer to 10, and then that ramps up significantly in 2027. We're on a growth basis. We're probably looking at more like 100 wells for that program. Got it. Okay. I guess, is that the type of pace that would kind of hold everything together over the next, you know, couple of years? Just any color you can provide around lease terms or anything like that, on the asset? Yeah, that's a general pace so that we can do it, you know, in a capital efficient manner. Okay, appreciate that. On continuous pumping, obviously, you talked about that. I think you're kind of increasing, you know, 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? Yeah, I don't, I don't think that it's gonna drive a ton of cost savings from our service providers. There's additional equipment requirements to be able to do so. You know, there's a little bit of savings on, you know, some of the dumb iron, the, you know, just the rentals that are out there as you increase cycle times. The big benefit is really, as Kaes, you know, kind of mentioned, is some of the stuff we can do to optimize the completion without it adding additional costs from the from the, you know, additional well swaps and that kind of thing. Also the increased cycle time, or sorry, the decreased cycle time, you know, that impacts your water out frequency. You know, you're able to bring wells forward in the plan, which, you know, is only maybe a one-time 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. Okay, thank you. Thank you very much. Our next question comes from the line of Charles Meade of Johnson Rice. Charles, your line is open. Good morning, Kaes, to you and your team. Hey, Charles. I want to ask a question around nomenclature, because we've been talking about the Barnett here, and in your presentation, talking about the Barnett, but in your shareholder letter, you refer to it as the Barnett and the Woodford. I wonder if you could help me explore a bit how this play has evolved. If we, if we go back to the late teens and, you know, when you guys had that, the Limelight prospect, that was pretty clearly a Barnett Mississippian target there. It sounds like as you guys are going into the more the, you know, 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 frack up into the Barnett. I wonder if you could comment, is that directionally correct? More generally, elaborate on how the play has evolved for you guys. I think that's good commentary. 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 timeframe, that was truly a Barnett play. There's some nuance across the basin with the zone that divides the two reservoirs. The Mississippian lime sits between them. It changes in thickness pretty materially as you move across the basin, sort of north to south. Up at the Limelight position, we had a pretty thick Mississippian lime section, and so those two reservoirs were separate and distinct. Then as you move kind of into some of the areas where we've been delineating more recently, the Mississippian lime is materially thinner, and we're able to frack through it. generally, we're targeting the lower Barnett, and able to drain the Woodford in some of these areas where you've got that thinner Mississippian lime section. Got it. That is helpful. 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 seems like it's receded a bit. You know, I think the unspoken flip side of that is that the green light scenario is a little closer. 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, you know, on balance, more likely to slow down? Just you just, you know, fill out that metaphor. Yeah, it's a metaphor we can't seem to shake, but, in general, I think it explains the situation pretty well. I just say, you know, I think, you know, there were periods of time over the last six months, where, you know, we were all much closer to the red light scenario in terms of crude price. There's a lot of things impacting crude prices, you know, over the last few months. In general, I think, you know, talking to our investors, they're very supportive of this plan to keep, you know, production flat and maximize free cash and wait for, you know, the green light scenario. I think just generally, you know, we've been talking about this oversupply for, you know, some people have been talking about it for two years, it just hasn't seemed to happen as aggressively as some expected. I think, you know, as we turn to higher demand in the summer and driving season and, you know, trading the spring months in crude, people will start to find reasons to be less bearish. I could probably be wrong, but in general, we just feel more confident about the macro after, you know, a couple big shocks last year on the supply side and the demand side. Got it. It's great color. Thanks, Kaes. Thanks, Charles. Thank you. As a reminder to ask a question, please press star one one on your telephone. Our next question comes from the line of Paul Cheng from Scotiabank. Paul, your line is open. Hi, thank you. gentlemen, 2 questions. One, in your D&C or well cost, now you're already down in your legacy operation, say in Midland, $550 or so. Where's 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. That is going to allow you that to have better, maybe reduced downtime? Just give us some idea that where should we be seeing from there? That's the first question. Yeah, good question, Paul. You know, I think on the drilling side, it's, you know, 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 ultra-fast wells, right? We talk about in the letter, you know, some wells that are sub six days, and we're still averaging over eight days, you know, spud to TD. How do we get, you know, that average from eight point five, nine days down to, you know, seven days? That drives meaningful cost savings on the drilling side. On the completion side, You know, it's, you know, we're continuing to go faster, and we talked a little bit earlier about continuous pumping and what that means for us. It's also, you know, working on the supply chain of the completion side. You know, what can we do around fuel? What can we do around other supporting services to get more efficient and drive some of the, you know, dead costs out of that business? You know, we're working on a lot of those things every day. These are not, you know, big chunks of dollars, but it's a lot of little things that add up to big chunks of dollars. We're still, you know, grinding away on the core business. Like Diamondback's always done, we're not gonna let up on that grind, and I'd expect to see more dollars flow out of the core business as we go throughout this year. Do you think over the next several years, you will be able to more than offset the inflation and drive that, 550 number down, say, towards the 500 or 525 in the next, say, three or four years? The 550 is a mix of all of our, you know, Midland Basin zones. That includes Wolfcamp D, you know, some of the deeper stuff. Barnett. Barnett. Yeah, I think, you know, certainly some of those deeper zones that are higher cost today, we're gonna see, you know, some material cost reductions in them as we, as we continue to deploy our best-in-class execution prowess to those zones and learn about them more and put the bid on them more. You know, yeah, I do believe we'll see the $550 come down materially. Also in the, in the older stuff that we're doing, the, you know, the Spraberry, shallower Wolfcamp zones, you know, I, I don't know what inflation will do with, you know. It's really gonna be largely driven on activity. You know, our goal every day is to continue to work to execute, you know, better and more efficiently, and drive costs out of our supply chain through what, you know, we consume. The variable costs, you know, 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. Thank you. This second question is a quick one. I know the impairment charges on cash are price related, primarily, and also you have about 130 million barrel of the reserve revision due to the price. $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 legacy Diamondback asset, or is from Endeavor or from Eagle, from Double Eagle? Thank you. Yeah, Paul. I mean, listen, you know, fair value accounting is what it is. You know, fortunately for us, the Endeavor deal was very well received, and that deal was put on the books, you know, in September of 2024 at $80 oil and $4 Henry Hub. You know, I don't think there's an investor out there that would say, "Hey, that was a bad deal." Unfortunately, when you put something on the books at $80 and then you average $64 for a year, the market says the accounting rules say you have to have a write-down. It's unfortunate. 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. The accounting rules will be what they are. Thank you. Thanks, Paul. Thank you. 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 the 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.