Diamondback Energy, Inc (NASDAQ: FANG) Q2 2025 Earnings Call dated Aug. 05, 2025
Corporate Participants:
Adam T. Lawlis — Vice President of Investor Relations
Kaes Van’t Hof — Chief Executive Officer
Daniel N. Wesson — Chief Operating Officer
Jere W. Thompson — Chief Financial Officer
Derrick Whitfield — Analyst
Analysts:
Arun Jayaram — Analyst
David Deckelbaum — Analyst
Neil Mehta — Analyst
Scott Hanold — Analyst
John Freeman — Analyst
Phillip Jungwirth — Analyst
Scott Gruber — Analyst
Betty Jiang — Analyst
Kevin MacCurdy — Analyst
Josh Jayne — Analyst
Kalei Akamine — Analyst
Charles Meade — Analyst
Doug Leggate — Analyst
Leo Mariani — Analyst
Paul Cheng — Analyst
Presentation:
Operator
Good day, and thank you for standing-by. Welcome to the Diamondback Energy Second Quarter 2025 Earnings Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star 1-1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1-1 again. 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.
Adam T. Lawlis — Vice President of Investor Relations
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 and letter to stockholders, which can be found on our website. Representing Diamondback today are Case, CEO; Danny Weston, 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 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 Kate.
Kaes Van’t Hof — Chief Executive Officer
Great. Thank you, Adam, and good morning, everyone, and thanks for taking the time to listen into our earnings call. We’re in our conference room in Midland, Texas with no air-conditioning you know, truly valuing the importance of American energy this morning with no air-conditioning in its office. So we’ll get it started. I hope you read our letter and investor presentation and release last night, and we’re going to go straight into Q&A.
Questions and Answers:
Operator
Thank you. At this time, we will conduct the question-and-answer session. Our first question comes from Arun Jayaram of JPMorgan Securities LLC. Your line is now open.
Arun Jayaram
Good morning. Sorry about the AC situation hope you have a couple fans because it can get hot in middland in the middle of the summer. Hopefully this is not part of the case, your thoughts on reducing costs at the company because they see 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 from previous deals. I was wondering if you could comment on how you think about the consolidation roadmap in the Permian and Fang’s role within the industry and just overall M&A thoughts.
Kaes Van’t Hof
Yeah. Good question, Arun. I mean I think first and foremost, we have to remind everybody that our job is to maximize shareholder value. And I think we’ve done that very successfully at Diamondback over the last 15 years and what I think and I think investors would agree is a extremely — has been an extremely tough tape. So generating alpha and creating value in a tough tape is what we’ve done. And we’ve done that via an acquire and exploit strategy in the Permian where we’ve been able to cut costs and execute better than anybody else on the assets we acquired.
And 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. And outside to investors, it looked like we didn’t skip a beat. So listen, we 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. So I think the way we see it is we’re — we should naturally be the consolidator of choice as we execute at a lower-cost and a better overall development strategy, some slides we put in the deck today that are pretty interesting.
And until someone else can prove they can do it better than us, then and we lose our edge, then we should be, you know, the consolidator of choice. So 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 exhibited that today.
Arun Jayaram
Great case. 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?
Kaes Van’t Hof
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 smooth — two small sales, non-op sale and the Bengal sale getting us to about $250 million, $260 of cash-in the door coming in this quarter. The other two big pieces of non-core assets that we see as on the block are our Epic pipeline stake, which we’ve increased to 27.5% 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 Endeavour 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 and 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.
Arun Jayaram
Great. I’ll turn it over. Thanks.
Kaes Van’t Hof
Thanks, Arun.
Operator
Thank you. Our next question comes from David Deckelbaum of TD Cowen. Your line is now open.
David Deckelbaum
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. Now can you quantify the size of that opportunity that you think can be addressed over the next couple of years?
Kaes Van’t Hof
Yeah, I’ll give you the high-level. This commentary is kind of new to us, right? I mean, if you look-back at the development of shale or Diamondback, it used to be 80% of our spend was on capital and 20% was on op costs. And now here we are at the size that we are, capital is 65% or so of our spend, op costs are 35% and we think it’s going to 50-50. And I think there’s a lot of things to work 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 1% here, a percent there, do some of these workover 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, you want to add anything that we’ve been doing on that and our focus on that, but that’s the highlights.
Daniel N. Wesson
Yeah. I mean we’ve really leaned in a little bit more to our workover program this year. The spend, the non-DC&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 I think some of these wells that you know are three, four, five years-old that have been impacted by offset fracs and whatnot. When we go into them and clean them out and put some acid or some other chemical optimization into the reservoir simulation into the reservoir, we’re seeing almost 20% to 50% to 100% you 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.
David Deckelbaum
Thanks for the color, Danny. And maybe,, just following-up on just Arun’s comments with some of the non-core sales targeted for perhaps the back-half of this year. How do you think about managing that cash coming in door versus some of your debt targets by the end-of-the year and some shareholder returns.
Kaes Van’t Hof
Yeah. I mean, I think 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. That’s really our big — 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. I think overall, we have some nice tailwinds here in Q3, a little lower capex, production strong, a pretty big cash tax tailwind with 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 debt, but a combination of that plus non-core asset sales probably gets us into a really good spot where we think we could lean-in on repurchases should things — should things weaken further from here?
David Deckelbaum
Thanks guys.
Operator
Thank you. Our next call is from Neil Mehta of Goldman Sachs and Co. Your line is now open.
Neil Mehta
Yeah. Thanks, Case and team. If you can provide an update to the stoplight analogy, it sounds like you still think we’re at yellow here, but your perspective on the macro and how that informs your activity decisions as there’s — 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.
Kaes Van’t Hof
Yeah, Neil, good question. I think the stop life, it unveiled itself last quarter, and I don’t think it’s going anywhere anytime soon. Unfortunately, we still think we’re in the yellow situation. But if you go back to kind of May 5, May 4, when we released Q1 earnings, there’s probably still more uncertainty then than there is today. And basically, we said we’re prepared to go to go red if needed back then. And I think we’re still ready to do that, but — but I think it seems that the double whammy of a demand shock and a supply shock has dissipated for now. There’s still a lot of a lot of firms, yours included that sea 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 debt reduction and share count reduction waiting for that spring to coil when commodity prices do rally in the — at some point.
Neil Mehta
And in case that kind of ties into the M&A in relation to — last quarter, I think your message was Double Eagle represent an opportunity for you guys to pause because at that point, you had consolidated a lot of the higher-quality positions in the Permian and you wanted to stay a pure-play and then incremental M&A if it’s done, it would probably be done from a Viper Energy perspective where you view that as a roll-up story. Is that still the still the framework or are you suggesting a different posture year-to-date?
Kaes Van’t Hof
No, that’s still our base-case. I mean, I think diving back, we’re very fortunate to have the inventory quality and depth that we have today. 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 that’s why we were so aggressive on Double Eagle. And unfortunately, the timing wasn’t great is 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 potential targets. And so I think we have to be a lot more selective. Now 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 think your analysis is correct that is going to be more patient and Viper is going to keep growing its business.
Neil Mehta
Right? We’re talking to Viper call.
Kaes Van’t Hof
It’ll be hotter then in this room.
Operator
Thank. Our next question comes from Scott Hanold of RBC Capital Markets. Your line is now open.
Scott Hanold
Yeah, good morning, all. I think you all every quarter seem to find ways of squeezing out more efficiency, getting drilled aids down and et-cetera. Look, how much — how many more things 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 getting to a point where you’re more at the optimal level. And maybe if we understand what the leading-edge kind of metrics right now are versus averages, that would be helpful.
Kaes Van’t Hof
Hey, Scott. Yeah, thanks for the question. Love to talk about the guys and it’s a nice and 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 to that leading-edge well more consistently. I think we’ve hit these 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 in chasing those really record wells. We continue to push lateral links longer. We put in our letter of — I highlighted a well that we drilled 30-plus 1,000 feet, I think it’s a record well in Texas. And so 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 — where the threshold limit is going to take us there. But the guys have done a really good job of just consistently eliminating the downtime out-of-the operation and chasing that leading-edge well in every section of the — of the drilling well.
And on the completion side, they continue to do the same thing. They’re just chasing that simul frac efficiency, continuing to get better pad after pad. And you see that in the results of the aggregate lateral footage per day pushing 4,000 foot per day-on the frac cruise. And look, I think there’s opportunities to do some different things in the frac world where we can we can grow that efficiency 15% to 20% more on-top of that. So we’re not done chasing those things. I think, you know we’ll continue to try and lead the pack in the Permian with regards to drilling completion efficiency. And I think at some point in time, we will reach a plateau, but we don’t see it here in the near-future.
Scott Hanold
All right. That’s good to hear. And my follow-up question is, you all had a bit stronger gas production this quarter and 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 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?
Kaes Van’t Hof
Yes, Scott, the backstory there is 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, Martin County, of which we were the largest producer on the system. I mean, with that growth, there was some growing pains and some power issues that 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 the big increase was 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 I think that’s very positive for long-term cash-flow and as well as 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 in the letter. But we continue to do things on our side too. I mean, our flaring was down, I don’t know, 75 bps or 100 bps in the second-quarter versus the first-quarter and that ties to the gas capture side. So really trying to get all three molecules generating as much revenue as possible for Diamondback here.
Scott Hanold
Thank you
Operator
Thank you. Our next question is from John Freeman of Raymond James. Your line is now open.
John Freeman
Good morning, guys.
Kaes Van’t Hof
Hey, John.
John Freeman
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?
Kaes Van’t Hof
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 we talk about how many zones per section, how many wells per section we’re — we’re drilling. 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 of drilling, maximizing both returns and resource, right? With our cost structure, we’re able to put another couple of wells in every section. And if we’re getting the same production per well than peers that are spacing wider than ours, then we’re naturally generating better returns and more recoveries for our shareholders. And I think with respect to your comments on the ambitious goals, I think that’s — I think that’s amazing. I’m not going to knock technology developments in the basin because Dynavax is naturally going to be a beneficiary of that. And you know it’s — I think it’s positive all-around. So I hope it all works. We’re going to be — 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 maybe some technology will help us combined with our low-cost structure over the next 10 years.
John Freeman
Gary. And then just one housekeeping item for me. Was there a production associated with the Delaware Basin non-op divestiture?
Kaes Van’t Hof
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 — we’ve just added it to the to the guidance going the back-half of the year.
John Freeman
Got it. Thanks a lot, Keith.
Kaes Van’t Hof
Thanks, John.
Operator
Thank you. Our next question comes from Philip Jungworth of BMO. Your line is now open.
Phillip Jungwirth
Thank you. Thanks. Good morning. All right. Wondering how you’re viewing the cost-of-capital advantage right now for Viper versus Fang and how this shapes capital allocation decisions at the parent level. It looks like based on the decks, both — 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.
Kaes Van’t Hof
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 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. So 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. And also another thing I’ll note, from a debt cost capital perspective, Viper just did its first investment-grade deal that price 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?
Phillip Jungwirth
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 frac that we’ve seen in the basin.
Kaes Van’t Hof
Yeah. I mean, if you think about kind of you could look at Slide 9 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 kind of 15 to 25-ish wells a section, Call-IT, 20 on average 10 days of well, you’re looking at 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 — these projects are not as short-cycle as I think they’re often referred to as because to properly develop the whole DSU, it does take quite a bit of time. And the completion coming in following-on you know that much lateral footage, it can — 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 time-frame. There’s a lot of flexibility in there if you see volatility and bring in rigs at certain times or factories 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 can’t — 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 I think we — we kind of doubled down on our commentary. I think we’re going to see US production roll a bit here at these prices. It has taken 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 US basins.
Phillip Jungwirth
Great. Thanks.
Operator
Thank you. Our next question comes from Scott Gruger of Citigroup. Your line is now open.
Scott Gruber
Yes, good morning.
Kaes Van’t Hof
Good morning, Scott.
Scott Gruber
I had a question on your excess to DUC balance. How big will that be at the end-of-the year? And what’s the strategy kind of going into ’26 with the excess ducts if oil is weak, would you pull it down because there’s less incremental spend per well or would you like to maintain it for some quick-to-respond barrels in case soil moves higher.
Kaes Van’t Hof
Yeah, good question, Scott. It seems the duck balance has gotten a little more attention than we expected. But we’re — listen, we’re completing 500 to 550 wells a year. It’s good to have 250 to 300 in the hopper, especially with this large pad development waiting for — waiting for completions. I think we’d be comfortable going as low as high 100 to 200 ducks, but would still like to maintain flexibility in that range. I think what’s happened this year is, drilling efficiencies and well costs are very low and what we decided was given that we’re still definitively in this yellow light analogy, 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 always consistent and best-in-class and that’s why 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.
Scott Gruber
I got it. And then on cash taxes, you guys realized a good bit of savings this year following the one big beautiful bill. I think some of that is kind of a makeup in the second-half. How do you think about ’26 and beyond from a cash tax-rate perspective?
Jere W. Thompson
Yeah, Scott, this is Jerry. 2026, we expect cash tax-rate to kind of level out at 18% to 20% of pre-tax income. When we look at 2025, we’re expecting a 15% to 18% cash tax-rate, down from roughly 19% to 22%. 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&D 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.
Scott Gruber
Got it. I appreciate the color. Thank you.
Operator
Thank you. Our next question is from Betty Jiang of Barclays. Your line is now open.
Betty Jiang
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 — there is an increase in other zones and also Wolfcamp B, 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.
Kaes Van’t Hof
Yeah, Meh, it’s a great question. You know, we focus 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 the upper Spraberry and in the Barnett and some of the deeper deeper zones like the Wolfcamp D. So yeah, I would expect that to continue as we progress through the year and then going into 2026. Yeah. I mean I think also on-top of that, Endeavor — endeavour Acreage probably had some better Wolfcamp D than our legacy acreage and probably better overall Wolfcamp B further south in the Midland Basin. So that’s driving it a little bit. But as Al 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.
Betty Jiang
Yeah, thank you. Thank you for that color. My follow-up is on power. We started to see some gas power deals in the basin. Can you just give us an update on what you’re seeing along that front? Where do you see the value-add opportunities for?
Jere W. Thompson
Yeah, Betty. I mean, I think the two big values — this is Jerry. The two big value drivers for Diamondback are one, finding an in-base — in-basin egress solution for our natural gas molecules. And then two, lowering what we view as probably the most inflationary piece of our cash cost structure on a go-forward basis, which is electricity costs that you find within LOE. So I think when you PV those two items, that’s where you’re seeing the greatest benefit to Diamondback if we could lock-in a behind-the-meter solution here for PowerGen. 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 I think there’s going to be opportunities over the next five to 10 years. We’re just being patient.
Kaes Van’t Hof
Yeah. I think there’s some other little things we can do on our existing asset-base, we don’t do a large — a large power trade. I mean, 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 hyperscalers or data centers coming into the basin.
Betty Jiang
Got it. That makes sense. Thank you.
Operator
Thank you. Our next question is from Derrick Whitfield of Texas Capital. Your line is now open.
Derrick Whitfield
Thanks, and good morning all.
Kaes Van’t Hof
Good morning, Derek.
Jere W. Thompson
Good morning.
Derrick Whitfield
Yes, there’s been a lot of industry discussion on your comments from the 1Q 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?
Kaes Van’t Hof
Well, I’ll say those are all Travis’ so moving on. 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 a pushback — and I also say most investors agreed with what we said in Q1 at the time. It’s interesting to hear the pushback come from — and we’re okay accepting pushback come from some within the industry, some at different companies in the basin and I think that’s just natural competition and we welcome that. But 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 in Q2 and that number was — has been exceeded, right? 60 rigs are out, 2025 scrap spreads are out. And I just think we know what’s going on in the ground in the Permian and in the US and it’s inevitable that much activity being taken out-of-the — out-of-the plan results in-production declines because of the natural high decline nature of this business.
So 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.
Derrick Whitfield
Yeah, absolutely fair. And then maybe shifting to operations. I wanted to lean-in on Scott’s earlier question on your four-day spot to TD 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, did most of your wells fall within a day or so of the eight average?
Kaes Van’t Hof
Yeah. I mean, I think that the four-day well is — it’s in the top-decile of our performance for sure. I mean, I think we had 30-something wells, we have 30 something wells that we’ve spud in less than — I mean, spud the TD in less than five days of not in this quarter, but since you know, in company history. And so the eight days were — most of our wells are within a day or two of the eight-day average. 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 consistently deliver that top-tier well and they’re getting better at it. And so I think that’s going to be the story and efficiency going-forward is, hey, how do we — 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, bit selection or BHA selection optimization. And as we get more data and we — and we’re able to go back into the areas and optimize, we’re going to see more consistent delivery of those ultra-fast TD times.
Derrick Whitfield
That’s great. I’ll turn it back to the operator.
Operator
Thank you. Thank you. Our next question comes from Kevin McCurdy of Pickering Energy Partners. Your line is now open.
Kevin MacCurdy
Thank you. Hey, good morning. Kesh, 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 million to 580 a foot wall cost guidance?
Kaes Van’t Hof
We’ve got — we’ve taken about 15% inflation since Liberation Day was announced on casing. And so I think we’re anticipating a little bit more of that to come. You know, we have a — we have a procurement agreement with a caping supplier, but the pricing, it kind of floats with regard to-market pricing formulaically. So we’re not necessarily locked into a casing price except on a quarterly basis. And so you know we — 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.
Daniel N. Wesson
Yeah. I think it will be interesting, Kevin, to see how the push-pull of a lower rig 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.
Kevin MacCurdy
I appreciate that detail. And as a follow-up, I mean, it looks like lower opex is certainly beneficial to your 2Q financials. Can you walk-through the moving parts of your changes to guidance in LOE and GP&T?
Kaes Van’t Hof
Yeah. Yeah, I’ll take GPT really quickly. 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, generally, the teams had a really good first-half of the year. We expect kind of run-rate LOE to be somewhere in the kind of 560 to 580 range on a normalized basis. But I think — I think we’ve generally been surprised to start to see some of those smaller synergies in the field between the Endeavor and Diamondback teams kind of come through on the — on the LOE side. I think long-term, 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 the LOE side. Work, Danny talked about workover expense and management, production management.
So not all LOE is low-return. Some of it can be very-high return.
Kevin MacCurdy
Yeah. Thanks for the answers and good luck with the AC situation over there.
Kaes Van’t Hof
It’s getting hotter, Kevin.
Operator
Thank you. Our next question comes from Josh Jay of Daniel Energy Partners. Your line is now open.
Josh Jayne
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. We’ve had some companies tell us that with service cost declines and efficiency gains that returns are even in lower-tier acreage are pretty strong here. And obviously, you had 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..
Kaes Van’t Hof
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 volume is outperforming. I think you know going back to three months ago, again, there was a concern that we were lower, headed going lower, headed lower. The calls for $50 and $40 oil were rampant and we were prepared to reduce further if needed. And I think as the price pressures have eased over the last three months, we decided that, hey, I think we can hold production here at 490. 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 they’re maintaining activity levels when the lowest-cost operator know, is doing the right thing and waiting for a better day?
Josh Jayne
Yeah. That’s fair. And then I guess my second question to you is 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.
Kaes Van’t Hof
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 not is not looking at their business in the right amount of detail. We — we change things every day, right? I think Danny uses a really good analogy that the Diamondback activity plan looks like a duct 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.
Josh Jayne
Great. Thanks, guys.
Kaes Van’t Hof
Thanks,. Thanks, Jeff.
Operator
Thank you. Our next question is from Akamine of Bank of America. Your line is now open.
Kalei Akamine
You. Good morning, guys. Guys. Two real quick ones for me. Number-one, just kind of looking at your hedge book for 2026, you look rather exposed on the oil side. Does that marry up with your outlook for ’26 oil prices?
Kaes Van’t Hof
No, it’s really just patience on adding puts. We’ve been buying puts, but 2026 puts are expensive today, right? So 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 ’26, 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 asset sales get-in — proceeds come in and the need to hedge reduces or the need to — we could lower that hedge price to pay less for the puts. I think the base dividends protected today at $37, $38 a barrel at maintenance capex. I think we’re due for a dividend review in the beginning of the year next year. But as the balance sheet shrinks and the share count shrinks and the breakeven stays low, the need for hedging reduces over-time.
Kalei Akamine
That makes sense. My second one is on maybe operations post the water sale. So the Endeavor asset will effectively 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?
Kaes Van’t Hof
Not a meaningful way. I think I think we’ve set-up the deals with our partners at Deep Blue to be able to simul frac or use two simul fracs across our position. So I don’t think much of that changes. I do think you know, getting a deal done, getting these two systems together will create some synergies, but you probably won’t see it at the Diamondback level.
Kalei Akamine
Got it. I appreciate the answers.
Kaes Van’t Hof
Thank you.
Operator
Thank you. Our next question is from Charles Mead of Johnson Rice. Your line is now open.
Charles Meade
Good morning, Case to you and your companions in the.
Kaes Van’t Hof
Good morning, Charles.
Charles Meade
It sounds like you guys are holding up well. Really, just one question from me, Case, and you touched on this, but I just want to try to go right at it. Can you give us an update on what the — the green light conditions would be in your metaphor 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 arguably there is with the impending decline of US oil volumes, 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?
Kaes Van’t Hof
Yeah. That’s a good question, Charles. I mean, I think we’re certainly closer to the second-half of the year when a perceived supply wave is coming our way. We’ll see what actually happens. We’ve now unwound or OPEC has unwound their initial cuts and I think they’re moving to a world where instead of, you know, was a discussion around who was cheating on their quota, it’s who can hit their quota and I think that’s a huge a huge difference in messaging right if, if you know production at OPEC hangs in there and you see US production start to struggle a little bit and then the curve is going to have to react. And when the curve reacts, that’s probably our biggest signal. I think just generally, the tone over the last four months has been a lot of companies running $50 and $60 scenarios versus the traditional last kind of three years, $60, $70 and $80 scenario.
So I think you know, I think when you start to see some changes in US production plus all of the OPEC barrels back, you start to look at what does a normalized market look like. And I think that resolves itself sooner rather than later in the commodity-based market. So I’m cautiously optimistic on ’26, but right now for the rest of ’25, we’re hunkering down and maintaining our flexibility for — for next year.
Charles Meade
Yeah, emphasis on caution. Thanks a lot, Case.
Kaes Van’t Hof
Thank you, Charles.
Operator
Thank you. Our next question is from Doug Legate of Wolfe Research. Your line is now open.
Doug Leggate
Thanks. Good morning, guys. Case, I wonder if I could ask — I guess it’s been asked multiple times the return to growth question, but maybe ask it a little more pointedly. It seemed that under Travis, it was pretty clear that Diamondback would essentially be ex-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 Travison?
Kaes Van’t Hof
I wouldn’t say the change of stance, Doug. I think I think we’re closer to discussing it again. I think if you go back to you know why US shale or the big public swent kind of ex-growth, it was coming out of 2020 and we went through a near extinction event as an industry and the shareholders said, time-out, it’s time to give us our money back. We gave you a lot of money over the last 10 years to grow your business and now we expect our return and the risk of that return almost went away in 2020. And coming out of that, a lot of the companies decided to 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 I think I don’t think we’re talking about going to spending all of our dollars growing the business, but I do think at some point that outside of a, you know, your words, not 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.
Doug Leggate
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, not everybody can because of inventory. So I want to be careful how I ask this, but you’ve talked about eight to 10 years of Tier-1 inventory. But as you and I have talked about before, you don’t just develop Tier-1 when you’re doing a cube or whatever. So from a practical development stance, meaning Tier-1 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 10 years, what’s the real number?
Kaes Van’t Hof
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 Tier-2, Tier-3 zones. I mean, I think we need to move away from individual well IRRs or breakevens and really start to look at — and we do this internally, looking at pad level breakevens or section level breakevens because you’re really developing half a section or a section at a time and that’s really the rate-of-return you’re achieving on that on that project?
Doug Leggate
That’s very clear. Thanks guys. I appreciate getting me on.
Kaes Van’t Hof
Thanks, Doug.
Operator
Thank you. Our next question is from Leo Mariana Mariani of ROTH. Your line is now open.
Leo Mariani
Yeah, Hi guys. 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, oil price key thing, but what else would you be looking at kind of apart from oil price here?
Kaes Van’t Hof
Yeah. 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, a full month, then I think we have to have a discussion. But 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 I’m not in a camp of being the first to hit the red light if that if that comes because we’ve done our part here.
Leo Mariani
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 methodology at the Fang level in terms of how you’re thinking about that to maybe boost some of the shareholder returns?
Kaes Van’t Hof
Yeah. I think at the Fang level, having more flexibility is important, right? And right now, we’re committed to at least at least 50% of free-cash flow into equity, combination of the base dividend and share repurchases. I think if you know if there’s share price weakness, that number should go higher than 50%. But if things are strong, then it should stay around 50%. I think at the E&P level, you have all the capex that’s associated with the business. And so it’s hard to put an exact number on where you’d like that because I think at Diamondback, we’d like to have lower debt, but also cash on the balance sheet for flexibility when you know the cycles do move against you.
Leo Mariani
Thank you.
Operator
Thank you. Our final question is from Paul Cheng of Scotiabank. Your line is now open.
Paul Cheng
Hi, good morning. Can you 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 as the acquisition. And as we say until you prove them, you are not a good consolidator, 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 scality. And so from that standpoint, I mean how the longer-term your business model need to be evolved over the next, say, Call-IT, five to 10 years?
Kaes Van’t Hof
Yes, good question, Paul. I mean listen, I think we’ve obviously done a ton of — a ton of consolidation, particularly in the last two years, Endeavor and Double Eagle both very large trades 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, 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 obvious by inspection to shareholders because as we — as you know and as you said, there aren’t 15 private-equity companies with 20,000 acres of Tier-1 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 where we’ve been in the last 10 years or so. Do you think that you will need to move outside Midland into some of your peers, we talk about international opportunity 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 G&A perspective today, Paul.
Paul Cheng
Okay. Our second question real quick, 2026, I know it’s still a little bit early, but if we assume your program would be relatively flat on the number of drilling rig or frac crew or number of well coming on-stream. And what’s the plus and minuses that on the capex program may look like in terms of inflation or efficiency gain, can you give us some idea that how that different factor will move that number comparing to this year number?
Kaes Van’t Hof
Yeah. I mean, I think 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 I think we can generally hold our oil production 490,000 barrels a day, plus or minus with about $900 million a quarter going-forward, maybe a little bit lower than that if things go our way. So it’s still — that’s still a really good best-in-class capital efficiency on the oil side. And also we have the flexibility to go higher or lower depending what the macro tells us.
Paul Cheng
In case that’s already including the impact, right?
Kaes Van’t Hof
Sorry, including what impact?
Paul Cheng
The.
Kaes Van’t Hof
Yes.
Paul Cheng
Okay. We do. Thank you.
Kaes Van’t Hof
Thanks, Paul.
Operator
Thank you. This now concludes the question-and-answer session. I would now like to turn it back to Case Vanthoff for closing remarks.
Kaes Van’t Hof
Thank you. 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 Diamondback, and we look-forward to discussing any questions any one might have offline. Thank you.
Operator
[Operator Closing Remarks]