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 speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one, one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one, one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Adam Lawlis, Vice President 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 and letter to stockholders which can be found on our website. Representing Diamondback today are Kaes Van’t Hof, CEO, Danny Wesson, COO, and Jere 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 Kaes. Great. Thank you, Adam. 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. We'll get it started. I hope you read our letter and investor presentation and release last night. We're going to go straight into Q and A. 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. Good morning. Sorry about the AC situation. Hope you have a couple fans because it can get hot in Midland in the middle of the summer. Hopefully this is not part of, Kaes, your thoughts on reducing costs at the company because AC is pretty important. Let me shift gears a little bit, Kaes. 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. Could you comment on how you think about the consolidation roadmap in the Permian and Diamondback Energy's role within the industry and just overall M&A thoughts? Yeah, I mean, 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 Energy over the last 15 years. What I think, and I think investors would agree, has been an extremely tough tape. 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. 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. We have 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 strategy. Some slides we put in the deck today are pretty interesting and 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. I think we're singularly focused on continuing to execute at the highest level and we exhibited that today. Great, Kaes. 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. You know, we're a small way through it with two small sales, 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, as you know, on the block are our EPIC pipeline stake, which we've increased to 27.5% of that pipe, the pretty valuable pipe now with, you know, 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. You know, 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. 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 Deckelbaum of TD Cowen. 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 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 at a high level. This commentary is kind of new to us, right? I mean, if you look back at the development of shale or Diamondback, you know, it used to be 80% of our spend was on capital and 20% was on op costs. Now here we are at the size that we are, you know, capital, 65% or so of our spend. Op costs are 35% and we think it's going to 50/50. 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. We're seeing some interesting results on some of our, we call them HCL jobs. 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 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. I don't know, Danny or Chad, do you want to add anything that we've been doing on that and our focus on that? That's the highlights. 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 had been in years past. Really to allocate some more capital to working over older wells and trying to optimize the tail, 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. I think some of these wells that 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, stimulation into the reservoir, we're seeing almost 20%- 50% to 100% improvement in production on lower production volumes. It was very encouraging what we're seeing on some of the work we're doing on the tail end of the production. Thanks for the color, Danny. Maybe Kaes, just following up on Arun's 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 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. 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. 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. That should create more free cash or significantly more free cash in Q3, some of which can be used to pay down debt. 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. Your line is now open. Yeah, thanks. Kaes 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 some bifurcation in the industry about how players want to approach the back half of the year. You guys have definitely taken a more guarded position here. Talk about the top-down view that informs how you're approaching your activity. Yeah, Neil, good question. I think the stoplight 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. If you go back to May 5, May 4 when we released Q1 earnings, there's probably still more uncertainty then than there is today. Basically, we said we're prepared to go red if needed back then and I think we're still ready to do that. 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 firms, yours included, that see oil prices as much lower next year. I don't know if I believe that they're going to be that low. It's certainly hard for me to get extremely bullish today. 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 at some point. In case that kind. It 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 Permian and you want to stay a pure play. You know, incremental M&A, if it's done, it would probably be done from a Viper Energy Partners 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 at Diamondback Energy, you know, 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 Energy 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. You know, that's why we were so aggressive on Double Eagle. Unfortunately, the timing wasn't great as it closed right before Liberation Day. We still feel very happy about the assets we acquired there, the sub-$40 break-even inventory we acquired there. We really don't see that much sub-$40 break-even inventory in hands of, you know, potential targets. 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. I think your analysis is correct that Diamondback Energy is going to be more patient and Viper Energy Partners is going to keep growing its business. Great. We'll talk in the Viper call. It'll be hotter then 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 you all. Every quarter you seem to find ways of squeezing out more efficiency, getting drill days down, etc. You know, look how much, how many more things, you know, can you do? I mean drilling days can't go to zero. Do you have a line of sight on how you can continue to improve efficiencies or are you getting to a point where you're more at the optimal level? Maybe if we understand what the leading edge kind of metrics right now are versus averages, that would be helpful. Hey Scott. Yeah, thanks for the question. Love to talk about the ops guys and, you know, it's a nice reprieve in some of the stuff we talk about on these calls. I think 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 kind of sporadically throughout quarters in the past, but they're getting to where they're hitting them more consistently. I think that's the real efficiency driver, is how do we become more consistent in chasing those really record wells. You know, we continue to push lateral lengths longer. We put in our letter, I highlighted a well that, you know, we drilled 30,000 ft, I think is a record well in Texas. We're really pushing the limits of what we've known to be capable to do on the drilling side. I really don't know where the threshold limit's going to take us there. 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 drilling well. 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. You see that in the results of the aggregate lateral footage per day, pushing 4,000 ft per day on the simul-frac crews. I think there's opportunity to do some different things in the simul-frac world where we can grow that efficiency 15%- 20% more on top of that. We're not done chasing those things. I think we'll continue to try and lead the pack in the Permian with regards to drilling completion efficiency. 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. 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? Yeah, Scott, the back story there is a business that we invested in, WTG West Texas Gas, sold to Energy Transfer a year ago. WTG had 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. With that growth there were some growing pains and some power issues that took both WTG and Energy Transfer some time to work through. Now we've started to see those plants operate a lot more efficiently. 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. I think that's very positive for long term cash flow and the production in that area makes it more economic. Big wins from the Energy Transfer team. That's why we put them in the letter. We continue to do things on our side too. Our flaring was down, I don't know, 75 bps or 100 bps in the second quarter versus the first quarter. That ties to the gas capture side. Really trying to get all three molecules generating as much revenue as possible for Diamondback 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. I've 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 9, about our development strategy where we talk about how many zones per section, how many wells per section we're drilling. I think it's well known that Diamondback Energy is the cost leader in the basin. I think it's less understood that we're also a technical leader in the basin, drilling and maximizing both returns and resource. With our cost structure, we're able to put another couple wells in every section. 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. With respect to your comments on the ambitious goals, I think that's amazing. I'm not going to knock technology developments in the basin because Diamondback Energy is naturally going to be a beneficiary of that. I think it's positive all around. 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. Maybe some technology will help us combine with our low cost structure over the next 10 years. Kerny, and then just one housekeeping item for me. Was there a production associated with the Delaware Basin non-op divestiture? 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 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 Phillip Jungwirth of BMO. Your line is now open. Thanks. Good morning. Wondering how you're viewing the cost of capital advantage right now for Viper vs. 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. 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 some of the things we can do in terms of repurchases. I think it brings in a different kind of investor for the period of time between sign and close. 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. Another thing I'll note from a debt cost capital perspective, I've heard that it 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. I think there's some things on the equity side that are temporary that need to work themselves out. Okay, great. Maybe more from a macro perspective, 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 could look at slide nine in our deck actually, and we highlight some of the average wells per section from ourselves and some peers. If you look at 15 to 25ish wells a section, call it 20 on average, 10 days a well, you're looking at 200 days of drilling time to cycle off that pad. 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. The 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 that much lateral footage. It can be a month or two of completion timing. 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 bringing in rigs at certain times or frac crews at certain times. These are not as short cycle as I think we regard them in the public markets. From a macro perspective, you can't take 60 rigs out of the Permian in three months and 20- 30 frac spreads out of the Permian in three months and not eventually see a production response. I think 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. It's taking a little bit longer than we all expected, but maybe that was the price reprieve we had in June. There's just too much activity being taken out of the U.S. basins. Great, thanks. Thank you. Our next question comes from Scott Gruber of Citigroup. Your line is now open. Yes. Good morning. Morning, Scott. Another question on your excess DUC balance, you know, how big will that be at the end of the year and what's the strategy kind of going into 2026 with the excess DUCs? 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? Good question, Scott. It seems the DUC balance has gotten a little more attention than we expected. We're completing 500- 550 wells a year. It's good to have 250- 300 in the hopper, especially with this large pad development waiting for completions. I think we'd be comfortable going as low as, you know, high 100- 200 DUCs, 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. What we decided was, given that we're still dependent in this yellow light analogy, we wanted to maintain that flexibility later through this year. 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. We built a lot of flexibility into our entire plan, which is why our results are always consistent and best in class. That's why you expect us to do that, our investors expect us to do that. 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 well in four days, we might not have any DUC drawdown by the end of the year. I got it. On cash taxes, 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 makeup in the second half. How do you think about 2026 and beyond from a cash tax rate perspective? Yeah, Scott, this is Jere. 2026, we expect cash tax rate to kind of level out at 18%- 20% of pre-tax income. When we look at 2025, we're expecting a 15%- 18% cash tax rate, down from roughly 19%- 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&E expenditures that were capitalized over the last three years. 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 Wolfcamp B. Yet at the same time you're able to maintain performance, if not better performance, which is quite impressive. How do you see development mix evolving over time? 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. We focused on delineating some of these upside zones over the past couple years. On the slide that you're talking about in the back of the deck, you can see that mix changing over time. I would expect that to increase over time as we 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 zones like the Wolfcamp D. I would expect that to continue as we progress through the year and then going into 2026. I think also on top of that, Endeavor acreage probably had some better Wolfcamp D than our legacy acreage and probably better overall Wolfcamp B further south in the Midland Basin. That's driving it a little bit. As Al mentioned, being able to add these zones into the mix and not see productivity degradation as a company is a very impressive feat. 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 are seeing along that front? Where do you see the value add opportunities for Diamondback? Yeah, buddy. I mean I think that the two big value. This is Jere, the two big value drivers for Diamondback are one, you know, finding an in-basin egress solution for our natural gas molecules, and then two, lowering 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 LOE. 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 power gen, 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 ten years. We're just being patient. I think there's some other little things we can do on our existing asset base if we don't do a large power trade. I mean, just using the example today, right, our natural gas liquids yield and gas capture went up in Martin County because the gas plants had a better power solution in place. It just shows that there's power issues all throughout the basin with or without hyperscalers or data centers coming into the basin. Got it. That makes sense. Thank you. Thank you. Our next question is from Derrick Whitfield of Texas Capital. Your line is now open. Thanks and good morning all. Good morning. Derrick, There's been a lot of industry 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? Those are all Travis's. 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 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. I think that's just natural competition and we welcome that. I think what we said in terms of activity has been spot on. I mean, we said 15% of the rigs out of the Permian in Q2 and that number has been exceeded. 60 rigs are out, 20- 25 frac spreads are out. 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. 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. Maybe shifting to operations, I wanted to lean in on Scott's earlier question. On your four-day spud 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? More broadly, did most of your wells fall within a day or so of the eight average? I mean, I think that the four-day well is in the top decile of our performance for sure. I think we had 30 something wells, we have 30 something wells that we've spud the TD in less than five days, not in this quarter, but since, in company history. The eight days were, you know, most of our wells are within a day or two of the eight-day average. I'll echo the point I made earlier with Scott, that 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. I think that's going to be the story. 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 some kind of fit selection, a BHA selection optimization. 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 MacCurdy of Pickering Energy Partners. Your line is now open. Hey, good morning Kaes. 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- 550 foot well cost guidance? We've taken about 15% inflation since Liberation Day was announced on casing. I think we're anticipating a little bit more of that to come. We have a procurement agreement with a casing supplier, but the pricing kind of floats with regards to market pricing formulaically. We're not necessarily locked into a casing price except on a quarterly basis. 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. I think it'll 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 what happens over the next year or so. I appreciate that detail and as a follow-up, it looks like lower OpEx is certainly beneficial to your 2Q financials. Can you walk through the moving parts of your changes to guidance and LOE and GPT? I'll take GPT really quickly. The GPT moves between when we're taking in kind or not taking in kind on the gas side. We flipped some contracts to take in kind and that number goes up. On the LOE side, generally the team's had a really good first half of the year. We expect kind of run rate LOE to be somewhere in the $5.60- $5.80 range on a normalized basis. 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 come through 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 on the LOE side. Danny talked about workover expense and management, production management. Not all 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 Josh Jayne 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. 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. Obviously you have super high quality acreage and very low cost. I'm just kind of thinking about what metric you're looking at to make the decision to lower even here. Yeah, I mean I wouldn't say we're lowering much from here. 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 outperforming. Going back to three months ago, there was a concern that we were headed lower. The calls for $50, $40 oil were rampant and we were prepared to reduce further if needed. As the price pressures have eased over the last three months, we decided that we can hold production here at 490. All of our investors have been supportive of our decision. We've always tried to make the right capital allocation decision. I'd flip that question back to you, Josh, to ask the higher cost operators why they're maintaining activity levels when the lowest cost operator is doing the right thing and waiting for a better day. Yeah, that's fair. 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 add activity back? Not at all. That's not an excuse that is allowed inside the halls of Diamondback. Anybody using the efficiency excuse for why they're maintaining activity is not looking at their business in the right amount of detail. We change things every day. I think Danny uses a really good analogy that the Diamondback activity plan looks like a duck 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. 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. That takes a lot of work from top to bottom in this organization. Great. Thanks guys. Thanks, Josh. Thank you. Our next question is from Kalei Akamine of Bank of America. Your line is now open. Hey, good morning guys. Kaes, 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 2026 oil prices? No, it's really just patience on adding puts. You know, we've been buying puts, but 2026 puts are expensive today. Right. 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 2026. We really don't want to pay too much per barrel for the deferred premium puts. I also think as balance sheet improves and non-core asset sales get in, proceeds come in, the need to hedge reduces or the need to, you know, we could lower that hedge price to, you know, pay less for the puts. I think the base dividend's 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. As the balance sheet shrinks and the share count shrinks and the break-even stays low, the need for hedging reduces over time. That makes sense. My second one is on maybe operations post the water sale. The Endeavor asset will effectively flow it into a bigger system. Does that create opportunities to improve your own operations with respect to water? That is, 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 in a meaningful way. I think we've set it. We've set up the deals with our partners at Deep Blue to be able to simulfrac or use two simulfracs across our position. I don't think much of that changes. I do think getting a deal done and getting these two systems together will create some synergies, but you probably won't see it at the Diamondback level. Got it. I appreciate the answers. Thank you. Our next question is from Charles Meade of Johnson Rice. Your line is now open. Good morning, Kaes, to you and your companions in the sweat lodge. Good morning, Charles. It sounds like you guys are holding up well. Really, just one question for me, Kaes, 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 green light conditions would be in your metaphor to re-accelerate? Have there been any changes to that in light of a lot of the dynamics that you've been talking about here today, whether casing costs up, service pricing, efficiency, higher service pricing down? Also, arguably there's a, with the impending decline of U.S. oil volume, that's a nascent, bullish indicator, I think. Can you just give us a reminder of where you are and how that's changed? Yeah, good. That's a good question, Charles. 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 the discussion around who was cheating on their quota, it's who can hit their quota. I think that's a huge difference in messaging, right? If production, OPEC hangs in there and you see U.S. production start to struggle a little bit, then the curve's going to have to react. When the curve reacts, that's probably our biggest signal. I think generally the tone over the last four months has been a lot of companies running $50 and $60 scenarios versus the traditional last three years, $60, $70 and $80 scenario. I think when you start to see some changes in U.S. production plus all of the OPEC barrels back, you start to look at what does a normalized market look like. I think that resolves itself sooner rather than later in a commodity based market. I'm cautiously optimistic on 2026, but right now for the rest of 2025, we're hunkering down and maintaining our flexibility for next year. Yeah, emphasis on caution. Thanks a lot, Kaes. Thank you, Charles. Thank you. Our next question is from Doug Leggate of Wolfe Research. Your line is now open. Thanks. Good morning, guys. Kaes, 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 under Travis it was pretty clear that Diamondback would essentially be ex growth, given, for want 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 Kaes versus under Travis? I wouldn't say the change of stance, Doug. I think we're closer to discussing it again. If you go back to why U.S. shale or the big publics went 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 timeout, 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 a return. The risk of that return almost went away in 2020. Coming out of that, a lot of the companies decided to exert capital discipline and spend less and return cash to shareholders. I think that's been in general a positive outcome for our shareholders. I don't think we're talking about going to spending all of our dollars growing the business. I do think at some point that, outside of a, 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. That call's coming at some point over the next couple years. That's very clear. I guess my follow up is related to that because although a lot of people might say there'll become a time to grow, not everybody can because of inventory. I want to be careful how I ask this, but you've talked about eight to 10 years of tier one inventory. As you and I have talked about before, you don't just develop tier one when you're doing a cube or whatever. 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 10 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 t oday, before we have to get to kind of true, you know, tier two, tier three zones, I think we need to move away from individual well IRRs or break-even costs and really start to look at, you know, and we do this internally, looking at pad level break-even costs or section level break-even costs, because you're really developing half a section or a section at a time. That's really 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 Capital Partners. Your line is now open. 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, you know, oil price is a key thing. What else would you be looking at apart from oil price here? Yeah, it's really just oil price, Leo. I mean, I think if we're printing a month in the low $50s, a full month, then I think we have to have a discussion. I think we 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. I'm not in a camp of being the first to hit the red light if that comes, because we've done our part here. Okay, that makes sense. With respect to targeted debt levels for Viper, you guys came out with a new target today of $1.5 billion in net debt, at which point you would increase returns to shareholders. Can you provide any similar methodology at the Diamondback level in terms of how you're thinking about that to maybe boost some of the shareholder returns? Yeah, I think at the Diamondback level having more flexibility is important. Right now we're committed to at least 50% of free cash going to equity, a combination of the base dividend and share repurchases. I think if there's share price weakness that number should go higher than 50%. If things are strong, then it should stay around 50%. 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 debt because I think at Diamondback we'd like to have lower debt but also cash on the balance sheet for flexibility when 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, Kaes. Just want to look at the visits on a longer term basis. I mean, since the formation, you guys have been always doing very good as the growthful acquisition and as you say, until you prove them, you are not a good consolidator. You should continue to be the preferred one. At the same time, you also say that the asset available in Midland, where your focus is, is getting scarcity. 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. Yeah, it's a good question, Paul. I mean, listen, I think we've obviously done a ton of consolidation, particularly in the last two years. Endeavor and Double Eagle, both very large trades, you know, relative to the other trades we've done in our company's history. I think we're in really good shape right now. Over the next five to ten 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 you said, there aren't 15 private equity companies with 20,000 acres of Tier 1 rock available to be consolidated. 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. I think patience is going to be the key for us versus where we've been the last ten 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. Okay, 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 flat crew or number of welcoming on stream, 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? 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. I think we can generally hold our oil production, you know, 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. It's still a really good best-in-class capital efficiency on the oil side. Also, we have the flexibility to go higher or lower depending what the macro tells us. In case that's already including the tariff impact, right? It's already including what impact? The tariff. Yes. Okay, we do. Thank you. Thanks, Paul. Thank you. This now concludes the question and answer session. I would now like to turn it back to Kaes Van’t Hof for closing remarks. 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. Thank you for your interest in Diamondback Energy 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.