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 Lawless. Please go ahead.

Operations, plans, objectives. 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. These factors can be found in the company's filing non-gap measures. Reconciliations with the appropriate gap measures can be found in our earnings. 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. Thank you. At this time, we will conduct the question and answer session. As a reminder, to ask a question, you'll 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.

Good morning, Case and team. 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, 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 that and just the mix as well between oil and gas.

You know, it was essentially almost zero acres a couple years ago. We were able to, you know, grow that position without, you know, cap raises or press or equity back to entity. So it's going to be very, you know, three, four, you know, the rock.

We think these returns are going to be pretty excited about the potential here, 900 gross locations.

Yeah, 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 barnet, but actually there's potentially more oil as well. So it's probably a little oilier than some of us would have thought. But just talk about how you're thinking about making sure that you're maximizing the liquids cut out of these barrels.

The 12-month period, you know, your core zone's like 80% oil for that first six months. It goes down to about 75% oil. The Barnett plan that we're showing here, I think the oil productivity speaks for itself

often is very competitive once we get the returns where we see them going. 2027 time period, the Barnett's a different type of, you know, vertical production or production in the core zone, so, 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 going to be a benefit to returns in the 2027 plus timeframe.

All right. Thanks, Keith. Thanks, Keith. Thank you very much. This call comes from the line of Gabrielle Cerny of William Blair Equity Research. Gabrielle, your line is open. Hey, Casey.

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 accum versus 22 for the core Midland. And yet, you know, you talked about maybe the $100 per lateral foot, Barnett, versus what are you down to, I think, $5.50 for the Midland cost. So curious how you're thinking about total returns, Barnett versus just the Midland average.

Yeah, why don't I hit the high level and let Danny talk about how we're going to get the cost down. You know, high level, our core Midland development, which I would put as, you know, everything except the Wolf Camp D is, you know, close to about 510, 520 a foot. If we can get, and 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, and the Barnett 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. You know, Danny has a few examples of how we're going to do that.

Yeah, I mean, I think a lot of the cost reductions we're targeting are really just a decision to move to the kind of development mode and apply the techniques we've, you know, learned over the years, developed a decision extendedly.

Great, good details. And then just secondly, Kay, 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? 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.

Yeah, I mean, listen, we're 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 average lateral lengths last year, you know, up by about 600 lateral feet on average, which is a continue to try to, you know, if you notice, leases all lost, you know, no deal on continuing to, 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 Jeffrey Lambujan of TPH and Company. Jeffrey, your line is open.

Good morning, Jason, 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 Corps operations. You know, we took note of the strong oil cubes 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-Widford over time as well.

Yeah, you know, the inventory that we have in the core, what the teams are doing on the core inventory, you know, the vast majority of our budget is very, very impressive. You know, lateral length, you know, in a world where productivity is being questioned on a per-foot basis, you know, increase product testing in terms of, you know, stage lengths, stage designs, where we're about spacing, you know, all the zones, results, you know, kind of speak for themselves, which is why we've tried to focus 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, kind of after these pipes.

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 over last year, the water supply potential, especially thinking about Deep Blue, and of course, gas or power from your upstream business. So 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, Jerry's thinking about, you know, about the opportunity to discuss publicly. Yeah, I'd say the one thing I'd add there, Jeff, is, you know, 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. You know, there's been a lot of noise 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. But, you know, we're not going to talk about it in detail until we have those details. But it's a great question.

Perfect. Appreciate that. Thank you. Our next call comes from the line of Philip Jungworth from BNMU. Philip, your line is open.

Yeah, thanks. I'll also give the Barnett more airtime here. Appreciate you bringing resource expansion back to the NP 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?

Move down into the basin and you've got more gas in the system, especially as you move into the south. And so there is going to be variability in geo. I think one of the things that we really is where can we find the best resource, the biggest resource, and then the potential to drain potentially the Barnaz wars with a single well bore. And we believe we put together a really strong position in the best resource quality within the basin.

That's great. And then you called out Diamondback having nearly two decades of inventory at a 2026 pace. Last year, there was a lot of talk about Pete 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 multi-year period, given the depth of resource you have?

Allocate capital and growth becomes kind of the output. You know, that's probably a good decision. I think, you know, we're starting the year here, you know, still in this kind of, you know, oil production is the input and then CapEx will be, you know, reduced if things go well. And inventory duration of things like the Barnett, a lot of airtime today, you know, are accretive to that long-term duration story.

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

Good morning, gentlemen. uh i also have a follow-up on the on the barnet uh yeah just a follow-up on the barnet looking at the 12-month cune plot on slide 12 it looks like the the average well is delivering just under 50 more oil uh cuts or a mix um over the the first 12 months of the 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 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 your test so far yeah i'll let i'll

I'll give the EUR commentary, you know, if you start to run these wells at $800 a foot or close

to it, you know, the rate of return basis, those are about 50 VO. 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 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 yeah you know this 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. I do think, you know, we're going to continue to test. It just needs to be extracted economically, and that's what we're using.

It's pretty early on in the results. The issues 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 variable driving the performance.

Yeah, and 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 V1.0, Arun, right? this is what Wolf Camp B perhaps looked like in 2014. So, you know, I think we got, you know, look how far we've come in 10 years. And, again, you know, this is a highly technical organization that's going to work to figure some of this stuff out.

Thanks, Jason, team.

Thank you. Our next question comes from the line of Bob Brackett from Bernstein Research. Bob, your line is open.

good morning and and i'm gonna have to go back to the barnet uh just because it seems to be the flavor of the day if i compare your typical well it's less than 600 bucks a foot you're you've got a path for the barnet to get from a thousand bucks a foot to 800 bucks a foot uh but you know the top of the wolf camp versus the top of the barnet are a couple thousand feet apart so not a whole lot of vertical depth what's stymieing the drilling down there or is it as on the completion side where that those incremental costs are coming from and what are some potential

solutions? Resource all together and and all that we've been doing you know to de-risk 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 that we know through calculated risks we can do to 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 and the barnet so we're pumping you know larger jobs to try and generate a larger simulated rock volume across those four wells and uh and you know we've been only on doing one or two well pads so a lot of single well or zipper fracks and as we move into development we're going to move into you know full scale barnet and utilize final frack continuous pumping the things that we've learned in the midland basin core that's all very clear

quick follow-up if i could one of your peers uh talked last week about uh international opportunities i'm curious where do international opportunities sit on your list of strategic

priorities yeah bob i mean it's you know a company of our size should start you know what out five years and you know that just can basin has been in addition here um you know we're basin experts There are issues that, you know, that come with that rock. So, you know, we've learned a lot about, you know, there's not a lot of action.

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. Y'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. Hey, John.

Efficiency improvement we're seeing on the drilling side and the completion side. And on the completion side, the team's been working on eFleets and really what that means is we just don't shut down between – we're encouraged by that. think uh this year and and you know if that if that comes to hey continuous pumping the other

tangential benefit starting to um to show their face and that's what's exciting there too that's

really helpful uh and then just my my follow-up you know tariffs have been pretty topical of late um have you all secured or maybe locked in the the pricing on y'all's steel related products for

for the 26 program. On the casing side of things, literally, with the tariff ruling that was just announced last week, we're not sure how much impact it's gonna have on OCTG because that flows through a different law as far as tariffs go, but we reprice our casing every quarter based on an index price. You know, on the tubular goods, we do, if we feel like we've got, you know, an opportunity to secure some at a, the sticky, $2.32, then we don't think those.

Thanks, guys. I appreciate it.

Thank you very much. Our next question comes from the line of Derek Whitfield of Texas Capital. Derek, your line is open.

Thanks. Good morning, all, and 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 the URs on new wells?

What can we do better? You know, we did the we're touching today, but some of the results are significant. I mean, some of the, you know, multi-hundreds of barrels a day producing a couple hundred barrels. 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've got to get smarter on it. We're going to keep testing it. That analysis, it's going to become a part of our, you know, overall these wells. So that's how I see it today. You know, I look forward to all of the advancements that the teams are going to make. You know, 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 giving you guys a breather on the Midland Basin side, there's been a lot of buzz from ministry 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.

Core Delaware. There's been people poking around to begin a bigger position, but, you know, with on the Delaware side, we're going to learn a lot. Great update. Thanks for your time.

Thank you very much. Our next question comes from the line of Kaylee Akamain from Bank of America.

Kaylee, your line's open. Hey, good morning, guys. With respect to the 26th guide here, The disclosures have been simplified. Just kind of wondering if you can talk about the number of targeted drills until it's expected this year, the duck backlog that supports that program, and then what kind of conservatism has been baked into the volume, noting that surfactants and barnets are kind of new efforts you're contributing.

Yeah, listen, you know, we try to, you know, push, you know. I guess the follow-up there is just on the number of drills contemplated.

And then the second question is just on the working interest in the barnet, At 64%, it's the lowest in your stack. I'm wondering if you can talk about any opportunities to increase that interest, whether that's organic leasing or maybe it's inorganic, understanding that the rights could be in somebody else's hands and whether that could be achieved via acreage swap, which contributes very meaningfully to this inventory update.

Yeah, I mean, on the working interest that we do to add value, you know, That's very helpful.

Thank you, Case.

Thank you very much. Our next question comes from the line of Kevin McCurdy 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 EBIT and 4Q, but guidance, you know, 2026 guidance is for a small increase for both LOE and GP&T. And 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 the basin have gone up um so we got some you know price that you know plugging and abandoning vertical wells you know making sure our asset base is um condition on on that front on cpi but all being taken in kind and so you're shifting relations to uh to gpt

great and maybe um to ask one more clarification question on the barnet um will there be a separate rig dedicated to that program and and just to confirm will those wells be geographically separate

from you know your cube development lines that we have dedicated to the barnet i think it probably makes sense that those rigs just focus on you know there's areas you know we're going to be we don't have it continue to build a position and um try to you know share facilities wherever we can because that's the most efficient uh form of capital use yeah i'll just add i think you know

So we, you know, the mud properties and such that we'll be utilizing to drill those probably be a different rig package that we're looking at. So, you know, we can get days down. We'll mix in more of our core development and, you know, probably have less.

Appreciate it.

Thanks, guys. Our next call comes from the line of Doug Leggett from Wolf Research. Doug, your line is open.

Good morning, guys. I wonder if I could follow up on the last question about the mix of Barnett versus the base business. It seems there's 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 qubit development elsewhere. So how do you expect that development type curve to evolve relative to the base business?

What a full section development looks like. But I think in general, you know, the size of the job we're assuming, you know, should, you know, probably the high.

Well, obviously it's early days, but thanks for the color. My follow-up is on the inventory question. I know there's no precision here, but I want to understand what your intention is in talking about 20 years. Is that 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?

Thanks, Casey. I appreciate the answers.

Thank you. Our next question comes from the line of Scott Hanelt of RBC Capital Markets. Scott, your line is open.

Yeah, thanks. You know, Cade, if you can give us some color and context on your view of the, you know, Dimebeck'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 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 has been?

Yeah, I mean, you know, generally they're champions. And I think, you know, 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, you know, surface champions like some of the other companies out there. So, you know, 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, some more dollars improving that existing resource. So, you know, as we said in the letter, the opportunities are fewer and further between, and therefore, you know, we're going to be doing more things like Barnett, more things like testing surfactants. But 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. And 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 is now becoming something people will read again in detail. You know, the majority of our revision to, you know, putt, we call it putt downgrades, but it really just means, you know, we're bringing in front of the development program. And, you know, in general, we try to keep a very low, 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 PUDs. In perspective, we're 70% PDP, 30% PUDs. And, you know, I think, you know, as we do deals like Double Eagle last year or Endeavor the year before, you know, some of our existing PUDs get taken out and new PUDs get put in. But, you know, from a performance perspective or PDP performance perspective, there have not been, you know, 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?

Thank you. Our next call comes from Leo Mariani of Roth. Leo, your line is open.

All right, 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 going to be, you know, drilling or completing here in 2026? And can you just talk a little about what you kind of need to do to hold that position, you know, say over the next five years? Is there going to be a meaningful

step up in activity in 27, 28? Yeah, we're looking at drilling more like 100 wells. I guess it's

that type of pace that would kind of hold everything together over the next, you know, a couple years, just any color you can provide around lease terms or anything like that on the asset.

Yeah, that is it.

Okay, appreciate that. And then 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, the big benefit is really, as Casey kind of mentioned, what we can do to optimize the completion from the additional well swaps and that kind of thing, but also the increased cycle time, or I'm sorry, the decreased cycle time that impacts your water out frequency and you're able to bring the length of time to your, 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 case you and your team

i want to ask a question around uh nomenclature because in your we've been talking about the barnet here uh in your presentation talk about the barnet but in your shareholder letter you refer to it as the the barnet and the woodford And so I wonder if you could help me explore a bit how this play has evolved. If we go back to the late teens and, you know, 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, you know, the base and 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 and more generally elaborate on how the play has evolved for you guys?

To some of the areas where we've been delineating. Recently, the mislime is materially thinner, targeting the lower Barnett and able to drain the Woodford in some of these areas where you've got that thinner mislime section.

Got it. That is helpful. And then, Case, 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. 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, you know, on balance, more likely to slow down? Just, you know, fill out that metaphor.

Yeah, in terms of crude price, I think, you know, talking to our investors, they're very supportive of this plan to keep, you know, the green light scenario. Some people have been talking about it for two years, and it just hasn't seemed to, in the summer and driving season and trading the spring months in crude, people will start to find reasons to be less bearish. Now, I could probably be wrong, but in general, we just feel more confident about the macro after a couple big shocks last year on the supply side and the demand side.

That's great. Coler, thanks, Case.

Thank you. As a reminder to ask a question, please press star 11 on your telephone. our next question comes from the line of Paul Chang from Scotiabank all your line

is open all right thank you gentlemen two questions one in your DNC or well course now you're ready down in your legacy operation say in Midland 550 or so so where's the biggest opportunity to drive that down further is it coming from further improvement in drilling or completion and you're already extremely efficient over there or that is going to allow you that to have better uh maybe reduced downtime uh and so just give us some idea that uh where should we seen from there that's the first question yeah a good question

the core business and like uh diamondbacks always done we're gonging off and 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 innovation and drive that 550 number down, say, towards the 500 or 525 in the next, say, three or four years?

Well, the 550 is a mix of all of our, you know, Midland Basin zones. So that includes Wolf Camp D, you know, some of the deeper stuff that we're doing in Barnett. And so, yeah, I think, you know, certainly some of the deeper zones that are higher cost today, we're going to see, you know, 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, you know, yeah, I do believe we'll see the 550 come down materially. But also in the older stuff that we're doing, you know, the spray berry shower wolf camp zones execute, you know, better and more efficiently and drive costs out of our supply chain through what, you know, we consume. And then the variable costs, you know, if we can execute better than everybody else, we'll use everybody else. And that's always been our focus and it will continue to be our focus going forward.

Thank you. The second question is a quick one. I know the impairment charges on cash price related primary and also you have about 130 million barrel of the reserve revision due to the price but $65 WTI NRC is really not that low so still a bit surprising you have reserve right down and also impairment charges it driven from the order is that all basically in the legacy diamondback asset or is it from Endiva or from Double Eagle? Thank you.

Yeah, Paul, I mean, listen, you know, fair value account, fortunately for us, the Endeavor deal was very...

Thank you. Thank you. At this time, I am showing no further questions. I would like to turn it back to Case Van Hoff for closing remarks.

We appreciate your...

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