Diamondback Energy, Inc.

Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Adam Lawless, VP of Investor Relations. Please go ahead.

Thank you, Brianna. Good morning and welcome to Diamondback Energy's second quarter 2025 conference call. During our call today, we will reference an updated investor presentation letter to stockholders, which can be found on our website. Representing Diamondback today are Case Van Tolf's CEO, Danny Wesson, COO, and Jerry Thompson, CFO. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance, and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with SEC. In addition, we will make reference to certain on-gap measures. The reconciliation with the appropriate gap measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Case.

Great. Thank you, Adam. And good morning, everyone, and thanks for taking the time to listen to our earnings call. We're in our conference room in Midland, Texas, with no air conditioning, and truly valuing the importance of American energy this morning with no air conditioning in this office. So we'll get it started. I hope you read our letter and invest your presentation and release last night, and we're going to go straight into Q&A.

Thank you. At this time, we will conduct the question-answer session. Our first question comes from Arun Jayaram of JP Morgan Securities, LLC. Your line is now open.

Good morning. Sorry about the AC situation. I hope you have a couple fans, because it can get hot in Midland in the middle of the summer. Get the gear again. Yep. Hopefully, this is not part of, Case, your thoughts on reducing costs at the company, because AC is pretty important. Yeah, but let me shift gears a little bit. Case, I want to hit this one kind of head on. There's been a lot of consolidation talk in the industry, particularly from some of your big cap peers who've highlighted some of the benefits they've received from Synergy Capture for previous deals. I was wondering if you could comment on how you think about the consolidation roadmap and the permeant and FANG's role within the industry and just overall M&A thoughts.

Yeah, good question, Arun. I think first and foremost, we have to remind everybody that our job is to maximize shareholder value. I think we've done that very successfully at Diamondback over the last 15 years. What I think investors would agree is it has been an extremely tough tape. Generating alpha and creating value in a tough tape is what we've done. We've done that via an acquire and exploit strategy in the permeant where we've been able to cut costs and execute better than anybody else on the assets we acquired. I think that ability to integrate acquisitions and not have any issues executing post doing it, the most recent example is Endeavor, almost doubled the size of the company. Outside to investors, it looked like we didn't skip a beat. Listen, we've got a young team executing at the highest level in the prime of all of our careers and we're only getting better quarter in, quarter out as proven with the results today. I think the way we see it is we should naturally be the consolidator of choice as we execute at a lower cost and better overall development strategies, some slides we put in the deck today that are pretty interesting. Until someone else can prove they can do it better than us and we lose our edge, then we should be the consolidator of choice. That's what I spend my time thinking about. I think it's interesting to see larger peers get bigger in the basin and talk about M&A, but I think we're singularly focused on continuing to execute at the highest level and we exhibit as that today.

Great, Kase, my follow-up, you announced some non-core, non-op Delaware basin property sales in the quarter. I was wondering if you could maybe give us some thoughts on the broader asset sale target of $1.5 billion, in particular maybe an update on the Endeavor water drop.

Yeah, so we announced a $1.5 billion non-core asset sale target with the Double Eagle transaction that closed early in the second quarter. We're a small way through it with two small sales, a non-op sale and the Bengal sale, getting us to about $250, $260 of cash in the door coming in this quarter. The other two big pieces of non-core assets that we see on the block are our Epic pipeline stake, which we've increased to .5% of that pipe. It's a pretty valuable pipe now with the last remaining expansion out of the basin. And then the other piece being our Endeavor water assets that we feel make a ton of sense in our deep blue JV. So we're working on both of those projects imminently. It's hard for us to put too much detail when we don't have binding documents done, but we are working on binding documents for both of those. So expect to have a very fulsome update for our shareholders at some point in the next quarter or two on hitting that target and getting that cash in the door.

Great. I'll turn it over. Thanks.

Thanks,

Arun.

Thank you. Our next question comes from David Dekelbaum of TD Cohen. Your line is now open.

Thanks for taking my questions, guys. I'll keep it short in the interest of comfort. I'm wondering if you can contextualize a bit more case the opportunity to address some of the production downtime and focus on the production tail. Can you quantify the size of that opportunity that you think can be addressed over the next couple of years?

Yeah, I'll give it a high level. This commentary is kind of new to us, right? I mean, if you look back at the development of Shale or Dynambak, it used to be 80% of our spend was on capital and 20% was on off-costs. And now here we are at the size that we are, capital 65% or so of our spend, off-costs are 35%. And we think it's going to 50-50. And I think there's a lot of things to work on on the tail of our production, some of which came over from ideas the Endeavor team had. And we're seeing some interesting results on some of our, we call them HCL jobs. But I think if we can get a lot of little wins on the production side of the business, reduce downtime by a percent here, a percent there, do some of these work over jobs that bring some of the old wells back to life, so to speak, that kind of adds up over a very large program. So I don't know, Danny or Chad, do you want to add anything that we've been doing on that and are focused on that, but that's the highlights?

Yeah, I mean, we've really leaned in a little bit more to our work over program this year. You know, the non-DC and e-spend budget line item is a little larger this year than it has been in years past, and really to allocate some more capital to working over older wells and trying to optimize the tail. And we've seen some really encouraging stuff out of that program. We don't have anything we can really quantify today, but we're going to continue to work that and get some data around it so we can talk to it in the future. But I think some of these wells that are three, four, or five years old that have been impacted by offset cracks and whatnot, when we go into them and clean them out and put some acid or some other chemical optimization into the reservoir or stimulation into the reservoir, we're seeing almost 20 to 50 to 100% improvement in production on lower production volumes. But it was very encouraging what we're seeing on some of the work we're doing on the tail end of the production curve.

Thanks for the call there, Danny. Maybe Kay's just following up on just to run the comments with some of the non-core sales, you know, targeted for perhaps the back half of this year. How do you think about managing that cash coming in the door versus some of your debt targets by the end of the year and some shareholder returns?

Yeah, I mean, I think getting the cash in the door will help pay down our two-year term loan that we took out with the Double Eagle deal. You know, that's really our big piece of debt that's due in 2027. We have another note due in 2026, but it's 3% interest, so we'll just build cash to be able to take that out and enjoy that 3% interest for the last year that we have it. You know, I think overall we have some nice tail ends here in Q3, you know, a little lower capex production, you know, strong, a pretty big cash tax tail end with, you know, the one big beautiful bill flowing through. And so that should create more free cash or significantly more free cash in Q3, some of which can be used to pay down debt, but a combination of that plus non-core asset sales probably gets us into a really good spot where we think, you know, we could lean in on repurchases should things weaken further from here.

Thanks, guys.

Thank you. Our next call is from Neil Mehta of Goldman Sachs & Co. Your line is now open.

Yeah, thanks, Kacen team. If you can provide an update to the stoplight analogy, you know, it sounds like you still think we're at yellow here, but your perspective on the macro and how that informs your activity decisions, there's, you know, there's some bifurcation in the industry about how they want, how players want to approach the back half of the year, and you guys have definitely taken a more guarded position here. So talk about the top-down view that informs how you're approaching your activity.

Yeah, Neil, good question. You know, I think the stoplight, it unveiled itself last quarter, and I don't think it's going anywhere anytime soon. You know, unfortunately, we still think we're in the yellow situation, but if you go back to kind of May 5th, May 4th when we released Q1 earnings, you know, there's probably still more uncertainty then than there is today. And, you know, basically we said we're prepared to go red if needed back then, and I think we're still ready to do that, but I think it seems that the double whammy of a demand shock and a supply shock has dissipated for now. You know, there's still a lot of firms, you know, yours included, that, you know, see oil prices as much lower next year. I don't know if I believe that they're going to be that low, but it's certainly hard for me to get extremely bullish today, and that's why I think 2025 for us is a year of, you know, debt reduction and share count reduction, you know, waiting for that spring to coil when commodity prices do rally at some point.

And then, Kasey, that kind of ties into the M&A in relation to, you know, last quarter I think your message was double eagle represented an opportunity for you guys to pause because at that point you had consolidated a lot of the higher quality positions in the permeating. You wanted to stay a pure play, and then, you know, incremental M&A if it's done or would probably be done from a Viper energy perspective where you view that as a roll-up story. Is that still the framework or are you suggesting a different posture here today?

No, that's still our base case. I mean, I think it's diving back, you know, we're very fortunate to have the inventory quality and depth that we have today. You know, there certainly is more consolidation to happen in the Permian. I think for Diamondback we need to be a lot more selective than we've been in the past because there's not a lot of inventory out there that competes for capital in our top quartile that we have today. And, you know, that's why, you know, we were so aggressive on double eagle. And, you know, unfortunately the timing wasn't great as that it closed right before Liberation Day, but we still feel very happy about the assets we acquired there, the sub-40 breakeven inventory we acquired there, and we really don't see that much sub-40 breakeven inventory in hands of, you know, potential targets. So I think we have to be a lot more selective. Now, you know, Viper on the other hand, we can talk about that on the Viper call, has had a great year consolidating and building that business, but I think your analysis is correct that Diamondback is going to be more patient and Viper is going to keep growing its business.

Great. We'll talk on the Viper call.

It'll be hotter than in this room.

Thank you. Our next question comes from Scott Hanold of RBC Capital Markets. Your line is now open.

Yeah, good morning all. Hey, you all every quarter seem to find ways of squeezing out more efficiency, getting drill days down and etc. You know, look, how many more things, you know, can you do? I mean, drilling days can't go to zero, but like, do you have a line of sight on how you can continue to improve efficiencies or you get to a point where you're more at the optimal level? And maybe if we understand what the leading edge kind of, you know,

Hey, Scott. Yeah, thanks for the question. I'd love to talk about the ops guys and, you know, the nice reprieve from some of the stuff we talked about on these calls. So I think the, you know, the drilling guys in particular have done a phenomenal job of really chasing that leading edge well and getting that leading edge well more consistently. I think we've hit these, you know, four and five day wells that we talk about, you know, kind of sporadically throughout quarters in the past, but they're getting to where they're hitting them more consistently. And I think that's the real efficiency driver is how do we become more consistent and chasing those really record wells? You know, we continue to push lateral links longer. We put in our letter, I highlighted a well that, you know, we drilled 30 plus thousand feet, I think is a record well in Texas. And so, you know, we're really pushing the limits of what we've known to be capable to do on the drilling side. And I really don't know where the threshold limits going to take us there. But, you know, the guys have done a really good job of just consistently eliminating, you know, the downtime out of the operation and chasing that leading edge well in every section of the drilling well. And on the completion side, you know, they continue to do the same thing. They're just chasing that simulfrac efficiency, you know, continuing to get better pad after pad. And, you know, you see that in the results of the aggregate, you know, lateral footage per day, pushing 4,000 foot per day on the simulfrac crews. And look, I think there's opportunities to do some different things in the simulfrac world where we can grow that efficiency, you know, 15 to 20% more on top of that. So, you know, we're not done chasing those things. I think, you know, we'll continue to try and lead the pack and the Permian with regards to drilling completion efficiency. And, you know, I think at some point in time we will reach a plateau, but we don't see it here in the near future.

All right. That's good to hear. And my follow-up question is, you know, you all had a bit stronger gas production this quarter. And, you know, it sounds like it came from more gas capture and processing improvements. Can you tell us how much more of that is yet to come? And is that something where your midstream partners are investing more capital to improve it? Are you, you know, doing things differently with them? Or give us a little bit of color behind what really drove that and how much more can we see from that perspective?

Yeah, Scott, I mean, the back story there is, you know, a business that we invested in, WTG, West Texas Gas, sold to Energy Transfer a year ago. WTG has been spending a lot of capital adding plants and capacity to a very high-growth area, you know, Martin County, of which we were the largest producer on the system. You know, with that growth, there was, you know, some growing pains and some power issues that, you know, took both WTG and Energy Transfer some time to work through. But now we've started to see that, you know, those plants operate a lot more efficiently. And, you know, the big increase was, you know, to our liquids yields. We've added 33,000 barrels a day of NGLs to our production in Q2 over Q1, like the snap of a finger. And, you know, I think that's very positive for, you know, long-term cash flow and as well as, you know, the production in that area makes it more economic. So big wins from the Energy Transfer team. That's why we put them in the letter. But we continue to do things on our side, too. I mean, our flaring was down, I don't know, 75 bips or 100 bips in the second quarter versus the first quarter. That ties to the gas capture side. So, you know, really trying to get all three molecules generating as much revenue as possible for Diamond back here.

Thank you.

Thank you. Our next question is from John Freeman of Raymond James. Your line is now open.

Good morning, guys. Hey, John. One of the majors has recently sort of highlighted some pretty ambitious targets for kind of dramatically improving kind of oil recovery rates in the Permian. Just sort of your thoughts on that side of the equation. Obviously, you've done a fantastic job on the cost side and just anything that you all are looking at on the recovery rate side of things.

Yeah, I mean, listen, we're always trying to drill better wells, right? We added an interesting slide this quarter, slide nine, about our development strategy where, you know, we talk about how many zones per section, how many wells per section we're drilling. You know, I think it's well known that Diamondback is a cost leader in the basin, but I think it's less understood that we're also a technical leader in the basin, you know, in terms of drilling, maximizing both returns and resource, right? With our cost structure, we're able to put another couple wells in every section, and if we're getting the same production per well, then peers that are spacing wider than ours, then we're naturally generating better returns and more recoveries for our shareholders. And, you know, I think with respect to, you know, your comments on the ambitious goals, you know, I think that's amazing. I'm not going to knock technology developments in the basin because Diamondback's naturally going to be a beneficiary of that, and, you know, I think it's positive all around. So I hope it all works. We're going to continue to look across the fence line and try to drill the best wells possible, which I think we've done over the last 10 years, and, you know, maybe some technology will help us combine with our low-cost structure over the next 10 years.

Great. And then just one housekeeping item for me. Was there a production associated with the Delaware basin non-optimist?

Yeah, there was a little bit, John, a little bit over 1,000 barrels a day of net oil production, a little bit more on the BOEs, but we just, you know, we've just added it to the guidance going the back half of the year.

Got it. Thanks a lot, Keith. Thanks, John. Thank

you. Our next question comes from Philip Jungworth of BMO. Your line is now open.

Thanks. Good morning. Good morning. Wondering how you're viewing the cost to capital advantage right now for Viper versus Fang and how this shapes capital allocation decisions at the parent level. Looks like based on the decks, both stocks are yielding around 10% free cash right now at 70, but I know you guys look at it in a lot more detail.

Yeah, I mean, listen, I think there's some technical things going on at Viper right now. We're stuck trying to get a public merger closed, and that limits, you know, some of the things we can do in terms of repurchases, but also I think brings in a different kind of investor for the period of time between sign and close. I think I look forward to the window opening at the Viper level and being able to repurchase some shares aggressively, as I think it is a very unique investment in the space. Also, another thing I'll note, from a debt cost to capital perspective, Viper just did its first investment grade deal that priced basically at or inside some very large peers of ours, showing that there is a lot of investor support for that business, but I think there's some things on the equity side that are temporary that need to work themselves out.

Okay, great. And then maybe more from a macro perspective, but can you talk about typical cycle times right now in the Permian, just considering efficiency gains, larger pad sizes, longer laterals, and we're really just trying to understand how long it takes to start to see the production impact from some of the reduced activity rig and track that we've seen in the basin.

Yeah, I mean, if you think about, you know, kind of you could look at slot nine in our deck actually, and we highlight some of the average, you know, wells per section from ourselves and some peers, and if you look at, you know, kind of 15 to 25-ish wells a section, call it 20 on average, you know, 10 days a well, you're looking at, you know, 200 days of drilling time to cycle off that pad. So, you know, somewhere in the neighborhood of six to nine months is a typical pad development or DSU development that may be broken down into multiple pads, but, you know, so it's really the projects are not as short cycle as I think they're often referred to as because, you know, to properly develop the whole DSU, it does take, you know, quite a bit of time, and the completion coming in following on, you know, that much lateral footage, it can be a month or two of completion timing. So, yeah, I like to think of these things as kind of 12-month cycles on a full DSU timeframe, you know, with a lot of flexibility in there if you see volatility and, you know, you know, you're not going to bring in rigs at certain times or fractories at certain times, but these are not as short cycle as I think we regard them in the public markets.

Yeah, but I think from a macro perspective, you know, you can't take 60 rigs out of the Permian in three months and 20 to 30 frac spreads out of the Permian in three months and not see, eventually see a production response. So, you know, I think we, you know, we kind of doubled down on our commentary. I think we're going to see U.S. production roll a bit here at these prices, you know, it is taking a little bit longer than we all expected, but maybe that was the price reprieve we had in June, but it's just there's just too much activity being taken out of the U.S.

basins. Great, thanks.

Thank you. Our next question comes from Scott Gruger of Citigroup. Your line is now open.

Yes, good morning. Morning, Scott. Another question on your excess duck balance. You know, how big would that be at the end of the year and what's the strategy kind of going into 26 with the excess duck? You know, if oil is weak, would you pull it down because there's less incremental spend per well or would you like to maintain it, you know, for some quick to respond barrels in case oil moves higher?

Yeah, good question, Scott. It seems the duck balance has gotten a little more attention than we expected, but, you know, we're listening. We're completing 500 to 550 wells a year. It's good to have 250 to 300 in the hopper, you know, especially with this large pad development, waiting for completions. You know, I think we'd be comfortable going as low as, you know, high 100s to 200 ducks, but would still like to maintain flexibility in that range. I think what's happened this year is, you know, drilling efficiencies and well costs are very low, and what we decided was, you know, given that we're still definitively in this yellow light analogy, you know, we wanted to maintain that flexibility later through this year, and that, as you mentioned, gives us two options, right? If things are weak, we can slow down a bit. If things are strong, we can accelerate pretty quickly. So we've built a lot of flexibility into our entire plan, which is why our results are, you know, always consistent and best in class, and that's why, you know, you expect us to do that. Our investors expect us to do that. So we're going to maintain that flexibility later in the year. There's certainly some drawdown coming in Q3 and Q4, but these drilling guys keep drilling wells in four days. We might not have any duck drawdown by the end of the year.

I got it. And then on cash taxes, you know, you guys realize a good bit of savings this year following the one big, beautiful bill. I think some of that is kind of a make-up in the second half. How do you think about 2026 and beyond from a cash tax rate perspective?

Yes, Scott, this is Jerry. 2026, we expect cash tax rate to kind of level out at 18 to 20 percent of pre-tax income. You know, when we look at 2025, we're expecting a 15 to 18 percent cash tax rate down from roughly 19 to 22 percent. So a reduction of roughly 300 million in total, about 200 million of this is one-time benefits. Two components of the 200 million here in 2025, the vast majority is related to the accelerated recovery of remaining unamortized R&E expenditures that were capitalized over the last three years. And then the remaining is related to the full expensing of depreciable equipment, primarily related to LWE we acquired earlier this year in the Double Eagle transaction.

Got it. I appreciate the call. Thank you.

Thank you. Our next question is from Betty Jiang of Barclays. Your line is now open.

Hi. Good morning. Thank you for taking my question. I want to ask about the development mix. If I look at the development mix provided in the back of the slide, there's an increase in other zones and also Wolf can be. But yet at the same time, you're able to maintain performance, if not better performance, which is quite impressive. So how do you see development mix evolving over time? And if you could just talk about what you're seeing in the other zone development performance wise versus the traditional zones. Thanks.

Yeah, Betty, that's a great question. You know, we've we've focused on delineating some of these upside zones over the past couple of years. And on the slide that you're talking about in the back of the deck there, you can see sort of that mix changing over time. I would expect that to increase over time as we sort

of delineate and rationalize where the highest returning areas are for those zones in upper Sprayberry and

in the Barnett and some of the deeper zones like the Wolf can be. So, yeah, I would expect that to continue as

we progress through the

year and then going

into twenty twenty six. Yeah, I think I think also on top of that, you know, endeavor, endeavor, acreage probably had some better Wolf Camp D than than our legacy acreage and probably better overall Wolf Camp B, you know, further south and in the Midland Basin. So that's that's driving it a little bit. But as I mentioned, you know, being able to add these zones into the mix and not see productivity degradation as a company is a very impressive feat.

Yeah, thank you. Thank you for that color. My follow up is on power. We started to see some gas power deals in the base and can just give us an update on what you're seeing along the front. Where do you see the value opportunities for Diamondback?

Yeah, buddy. I mean, I think the two big values. This is Jerry. The two big value drivers for Diamondback are one, you know, finding an in base in base and egress solution for our natural gas molecules and then two lower power. And then we're exploring what we view is probably the most inflationary piece of our cash cost structure on a go forward basis, which is electricity costs that you find within .O.E. So I think when you PB those two items, you know, that's where you're seeing the greatest benefit to Diamondback. If we could lock in a behind the meter solution here for power gen, you know, we're not going to go out and build anything on spec here. We've continued to look at various opportunities on potentially advancing power gen within the basin. It's just taken a little longer. And, you know, I think there's going to be opportunities over the next five to ten years. We're just being patient.

Yeah, I think there's some other little things we can do, you know, on our existing asset base. We don't do, you know, large, a large power trade. I mean, just just using the example today, right, our NGL yield and gas capture went up in Martin County because the gas plants had a better power solution in place. So it just shows that there's power issues all throughout the basin with or without, you know, hyperscalers or data centers coming into the basin.

Got it. That makes sense. Thank you.

Thank you. Our next question is from Derek Whitfield of Texas Capital. Your line is now open.

Thanks and good morning all.

Morning Derek.

Morning. I wanted to ask you about the discussion on your comments from the one key reporting cycle, both supportive and non-supportive, as you've highlighted. How would you characterize the support from your peers out of basin and the pushback within the basin?

Well, I'll say those were all Travis's, so, you know, but moving on, you know, we, I would say most of the industry either reached out and was supportive of what we were saying at the time. I think there's been pushback, you know, and I also say most investors agreed with what we said in Q1 at the time. It's interesting to hear the pushback, you know, come from, and we're okay accepting pushback, come from some within the industry, some at, you know, different companies in the basin. And I think that's just natural competition and we welcome that. But, you know, I think what we said in terms of activity has been spot on, right? I mean, we said 15% of the rigs out of the Permian and Q2 and that number was, you know, has been exceeded, right? 60 rigs are out, 20, 25 SPRAC spreads are out. And, you know, I just think we know what's going on in the ground in the Permian and in the U.S. And it's inevitable that that much activity being taken out of the plan results in production declines because of the natural high decline nature of this business. So, you know, I wasn't trying to be all doom and gloom, but I think what we're trying to say is how sensitive shale has become to prices at probably a higher level than everybody expected three or four years ago when we were all burning through capital at $50 oil. I think the messaging and the demands of our shareholders have changed over that period of time.

Yeah, completely fair. And then maybe shifting to operations, I wanted to lean in on Scott's earlier question on your four-day spud to 2-day record. If you were to compare the segment performance of the four versus the average of the eight, where do you guys see the greatest differences in performance? And more broadly, do most of your wells fall within a day or so of the eight average?

Yeah, I mean, I think the four-day well is, you know, it's in the top decile of our performance for sure. I mean, I think we had 30-something wells, you know, we had 30-something wells that we've spud in less than – I mean, spud the TD in less than five days, you know, not in this quarter, but since, you know, in company history. And so, you know, the eight days where, you know, all most of our wells are within a day or two of the eight-day average. You know, but again, I'll echo the point I made earlier with Scott that, look, the drilling team has done a phenomenal job of really chasing the consistency and trying to, you know, consistently deliver that top-tier well, and they're getting better at it. And so, I think that's going to be the story in efficiency going forward is, hey, how do we continue to grab that four- and five-day well and work the things that cause us to go to eight days out of the system? A lot of times it's an extra trip or, you know, some kind of, you know, bid selection or BHA selection optimization. And as we get more data and we're able to go back into the areas and optimize, we're going to see more consistent delivery of those ultra-fast spud to TD times.

That's great. I'll turn it back to the operator.

Thank you. Our next question comes from Kevin McCurdy of Pickering Energy Partners. Your line is now open.

Hey, good morning. Kase, your letter warns of 25% casing cost inflation from tariffs. Can you remind us if you have any of that locked in and how much of that inflation is baked into your 550 to 580-foot wall cost guidance?

We've got, we've taken about 15% inflation since Liberation Day was announced on casing. So I think, you know, we're anticipating a little bit more of that to come. You know, we have a procurement agreement with a casing supplier, but the pricing, it kind of floats with regards to market pricing formulaically. So we're not necessarily locked into a casing price except on a quarterly basis. And so, you know, if the market increases because of tariffs, we will follow along with that with a little bit of discount to what we can get at

the spot market. Yeah, I think it'll be interesting, Kevin, to see how the push-pull of a lower rate count and lower steel use in the industry compares to steel costs. It seems that steel costs are winning today, but we'll see. We'll see what happens over the next year or so.

I appreciate that detail. And as a follow-up, I mean, it looks like lower OPEX is certainly, you know, beneficial to your 2Q financials. Can you walk through the moving parts of your changes to guidance in LOE and GP&T?

Yeah, I'll take GPT really quickly. You know, really the GPT moves between when we're taking in kind or not taking in kind on the gas side. And so we've flipped some contracts to take in kind, and that number goes up. On the LOE side, you know, generally the team's had a really good first half of the year. You know, we expect kind of run-rate LOE to be, you know, somewhere in the kind of 560 to 580 range on a normalized basis. But I think we've generally been surprised, you know, to start to see some of those smaller synergies in the field between the Endeavor and Diamondback teams kind of come through on the LOE side. I think, you know, long-term, you know, should we get a water sale done to our JV partner at Deep Blue, LOE will go up slightly. But there's a lot of things going on on the LOE side, you know, work. Danny talked about work over expense and management, production management. So, you know, not all LOE is low return. Some of it can be very high return.

Thanks for the answers and good luck with the AC situation over there.

It's getting hotter, Kevin.

Thank you. Our next question comes from Jof J of Daniel Energy Partners. Your line is now open.

Hey, guys. It's kind of a follow-up to Neil's question from earlier, but I'm curious about the calculus around lowering activity. You know, we've had some companies tell us that, you know, with service cost declines and efficiency gains, that returns are even in lower tier acreage are pretty strong here. And obviously, you have super high quality acreage and very low cost. So I'm just kind of thinking about like what metric you're looking at to kind of make the decision to lower even here.

Yeah, I mean, I wouldn't say we're lowering much from here, right? We actually increased well count. Drilled wells are up 30 wells this quarter versus last for the full year. Completed wells are down a little bit, but that's just because volumes are performing. You know, I think, you know, going back to three months ago, again, you know, there was a concern that, you know, we were lower headed, you know, going lower headed lower. You know, the calls for 50 and $40 oil were rampant and we were prepared to, you know, reduce further if needed. And I think as the price pressures have eased over the last three months, we decided that, hey, you know, I think we can hold production here at 490. You know, I think all of our investors have been supportive of our decision. We've always tried to make the right capital allocation decision. And I think I think I flip that question back to you, Jeff, to ask the higher cost operators why why they're maintaining activity levels when the lowest cost operator, you know, is is doing the right thing and waiting for a better day.

Yeah, and that's fair. And then I guess my second question to you is, you know, when you do get the green light situation, is there any concern that you may lose some of the efficiencies at least for a short period of time as you kind of add activity back?

Not at all. That's not an excuse that is allowed inside the halls of Diamondback. I mean, I think I think anybody using the efficiency excuse for why they're maintaining activity is is not is not looking at their business and the right amount of detail. We we we change things every day. Right. I think Danny uses a really good analogy that the Diamondback activity plan looks like a duck on a on a pond. The pond is calm and the duck looks calm above the water. But below the water, there's a lot going on and we change out drilling rigs on an annual basis. We change out frac spreads on an annual basis. We increase activity, lower activity within quarters to make sure that what you see on the outside is flawless execution. But that takes a lot of work from top to bottom in this organization.

Great. Thanks, guys.

Thanks,

Jeff. Thanks, Jeff.

Thank you. Our next question is from Callie Akamai of Bank of America. Your line is now open.

Hey, good morning, guys. Two real quick ones for me. Number one, just kind of looking at your hedge book for twenty twenty six, you look rather exposed on the oil side. Does that marry up with your outlook for twenty six oil prices?

No, it's really just just patience on on adding puts. You know, we've been buying buying puts, but twenty twenty six puts are are expensive today. Right. So, you know, I think we're going to continue to slowly build that position. I think we're really well protected in the second half of this year and starting to build twenty six. But we really don't want to pay too much per barrel for the deferred premium puts. And I also think as balance sheet improves and non-core acid cells get in, proceeds come in, the need to hedge reduces or the need to, you know, we could lower that hedge price to pay less for the puts. You know, I think the base dividends protected today is thirty seven, thirty eight dollars a barrel at maintenance cap X. You know, I think we're we're due for a dividend review in the beginning of the year next year. But as as the balance sheet shrinks and the share account shrinks and the breakeven stays low, you know, the need for hedging reduces over time.

That makes sense. My second one is on maybe operations post the water sale. So the endeavor asked it will effectively flow out into a bigger system. Does that create opportunities to improve your own operations with respect to water, i.e. being able to move more water to the right places or being able to move more water to different places that you currently don't have access to today?

Not a meaningful way. I think, you know, I think we've set up we set up the deals with our partners at Deep Blue to be able to simulfrac or use to simulfrac across our our position. So I don't think much of that changes. I do think, you know, getting a deal done and getting these two systems together will create some synergies. But you probably won't see it at the diamond back level.

Got it. I appreciate the answers.

Thank you.

Thank you. Our next question is from Charles Mead of Johnson Rice. Your line is now open.

Good morning, case to you and your companions in the sweat lodge.

Good

morning, Charles. It sounds like you guys are holding up well. Really, just just just one question from me, case and you touched on this, but I just want to try to go go right at it. Can you give us an update on what the green light conditions would be in your metaphor, you know, to to reaccelerate? And have there been any changes to that in light of a lot of the dynamics that you've been talking about here today, whether, you know, casing costs up service pricing, you know, efficiencies higher service pricing down and also, you know, arguably there's a, you know, with the impending decline of U.S. oil volume, that that's a that's a nascent bullish indicator, I think. So can you just give us, you know, a reminder of where you are and how that's changed?

Yeah, that's a good question, Charles. I mean, I think we're certainly closer to the second half of the year when when a perceived supply wave is coming our way. You know, we'll see what actually happens. You know, we've now unwound or OPEC has unwound their initial cuts. And and I think they're moving to a world where instead of, you know, with the discussion around who was cheating on their quota, it's who can hit their quota. I think that's a huge, huge difference in messaging. Right. If, you know, production at OPEC, you know, hangs in there and you see U.S. production start to struggle a little bit and then, you know, then the curve is going to have to react. And when the curve reacts, you know, that's probably our biggest signal. You know, I think just generally the tone over the last four months has been, you know, a lot of companies running, you know, fifty and sixty dollar scenarios versus the traditional last kind of three years, you know, sixty, seventy and eighty dollar scenarios. So I think, you know, I think when you start to see some changes in U.S. production, plus, you know, all of the OPEC barrels back, you start to look at what is a normalized market look like. And I think that that resolves itself sooner rather than later in a commodity based market. So I'm cautiously optimistic on twenty six. But right now, for the rest of twenty five, we're hunkering down and maintaining our flexibility for for next year.

Yeah. Emphasis on caution. Thanks a lot, Casey.

Thank you, Charles.

Thank you. Our next question is from Doug Legate of Wolf Research. Your line is now open.

Thanks. Good morning, guys. Case, I wonder if I could ask the I guess it's been asked multiple times to return to growth question, but maybe ask it a little more pointedly. It seemed under Travis, it was pretty clear that Diamondback would essentially be X growth given, for one of a better expression, a subsidized oil market. Listening to you this morning, reading the letter, it sounds like there is a case where growth would make sense. Is that a change of stance under case versus under Travis?

I wouldn't say it's a change of stance, Doug. I think I think we're closer to discussing it again. You know, I think if you go back to, you know, why you as shale or the big publics went kind of X growth, it was coming out of twenty twenty. And, you know, we went through a near extinction event as an industry and the shareholders said time out. Time to, you know, give us our money back. We gave you a lot of money over the last ten years to grow your business. And now we expect a return. And, you know, the risk of that return almost went away in twenty twenty. And, you know, coming out of that, a lot of the companies decided to, you know, exert capital discipline and spend less and return cash to shareholders. And I think that's been in general a positive outcome for our shareholders. So, you know, I think I don't think we're talking about going to spending all of our dollars, you know, growing the business. But I do think at some point that, you know, outside of a, you know, your words on mine, subsidized oil market, there's going to be an unsubsidized oil market that's going to call for growth from companies like Diamondback. And we're going to be there to answer that call. We're going to answer it cautiously and with high capital efficiency. But that call is coming at some point over the next couple of years.

That's very clear. Well, I guess my follow up is related to that because although a lot of people might say, well, there'll be a come a time to grow and not everybody can because of inventory. So I want to be careful how I ask this, but you've talked about eight to ten years of tier one inventory. But as you and I have talked about before, you don't just develop tier one when you're doing a cube or whatever. So from a practical development stance, meaning tier one plus the other benches that you might develop alongside that, what would you say today is the consumption rate of your inventory? Not eight to ten years. What's the real number?

Yeah, I mean, I think it's a little higher than that, Doug. But I think we're fortunate that a lot of these secondary zones are pretty economic today before we have to get to kind of true, you know, tier two, tier three zones. I mean, I think we need to move away from individual well IRRs or break evens and really start to look at, you know, when we do this internally, looking at pad level break evens or section level break evens because you're really developing half a section or a section at a time. And that's really the, you know, the rate of return you're achieving on that project.

That's very clear. Thanks, guys. I appreciate you getting me on.

Thanks, Doug. Thank you. Our next question is from Leo Mariani of Roth. Your line is now open.

Yeah. Hi, guys. I wanted to ask a little about sort of the red light scenario, a lot of focus on the green light scenario, but what causes you folks to maybe slow down and consider shrinking a bit? Obviously, you know, oil price key thing, but what else would you be looking at kind of apart from oil price here?

Yeah, it's really just oil price, Leo. I mean, I think if we're if we're printing a month in the low 50s, you know, full month, then I think we have to have a discussion. But, you know, I think we kind of did our part and cut a ton of capex out of the plan this year to generate more free cash and shrink the balance sheet and shrink the share count. But, you know, I'm not in a camp of being the first hit the red light if that comes because we've done our part here.

Okay. That makes sense. And then just with respect to kind of targeted debt levels, for Venom, you guys kind of came out with a new target today of $1.5 billion in net debt, at which point you guys would increase returns to shareholders. Can you provide any kind of similar, you know, methodology at the FAANG level in terms of how you're thinking about that to maybe boost some of the shareholder returns?

Yeah, I think I think at the FAANG level, you know, having more flexibility is important. Right. And, you know, right now we're committed to at least at least 50 percent of free cash going to equity combination of the base dividend and share repurchases. So I think if, you know, if there's share price weakness, that number should go higher than 50 percent. But if, you know, things are strong, then it should stay around 50 percent. You know, I think at the E&P level, you have all the capex that's associated with the business. And so it's hard to, you know, put an exact number on where you'd like debt because I think at Diamondback we'd like to have, you know, lower debt but also cash on the balance sheet for flexibility when, you know, the cycles do move against you.

Thank you.

Thank you. Our final question is from Paul Cheng of Scotiabank. Your line is now open.

Hi, good morning. I just want to look at the business on a longer term basis. I mean, since the formation, you guys have been always doing very good at the growth through acquisition. And as you say, until you prove that you are not a good consort data, you should continue to be the preferred one. But at the same time, you also say that the asset available in midland where is your focus is getting a scarcity. And so from that standpoint, I mean, how the longer term your business model needs to be evolved over the next five to 10 years?

Yes, good question, Paul. I mean, listen, I think we've obviously done a ton of consolidation particularly in the last two years, you know, endeavor and double-legal both very large trades, you know, relative to the other trades we've done in our company's history. And so I think, you know, I think we're in really good shape right now. So I think over the next five to 10 years I think there's going to be opportunities that present themselves but they have to be presented at a value that's, you know, obvious by inspection to shareholders because, you know, as we, as you know, as you said, there aren't, you know, 15 private equity companies with 20,000 acres of tier one rock available to be consolidated. So I think for us that means continue to explore in our existing asset base, which we've done with some of these secondary zones, starting to get more attention and perform well as well as continue to trade and block up and do all the little things to wait for opportunities when they present themselves. But I think patience is going to be the key for us versus, you know, where we've been the last, you know, 10 years or so.

Do you think that you will need to move outside Midland into some of your peers? Or do you think that we talk about international opportunities or that you think that you would just focus in Midland?

I think we're very focused on Midland and the Permian in general today and going to continue to be so. I think there's still a lot of resource left to explore within our asset base and around the Permian. And that's where we're committed from a GNA perspective today, Paul.

OK, our second question real quick. 2026, I know you're still a little bit early, but if we assume your program would be relatively flat on the number of drilling rigs or flat crew or number of wells coming on stream, what's the plus and minuses that on the CAPEX program may look like in terms of the inflation or efficiency gain? Can you give us some idea that how that different factor will move that number compared to this year's

number? Yeah, I mean, I think, you know, CAPEX has moved around a lot throughout the quarters this year with Q3 being the low and Q4 coming back up a little bit. But, you know, I think we can generally hold our oil production, you know, 490,000 barrels a day, plus or minus, you know, with about $900 million a quarter going forward, maybe a little bit lower than that if things go our way. So, you know, it's still that's still a really good best in class capital efficiency on the oil side. And also, you know, we have the flexibility to go higher or lower, depending what the macro tells us.

In case that's already including the TELUS impact, right?

It's already included in what impact?

The TELUS.

Yes.

Okay. Thank you.

Thanks, Paul.

Thank you. This now concludes the question and answer session. I would now like to turn it back to Kay Spantoff for closing remarks.

Well, I'm proud of all the analysts for still going a full hour despite the temperature rising 20 degrees in that hour in this office. But thank you for your interest in diving back. And we look forward to discussing any questions anyone might have offline. Thank you.

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