Diamondback Energy, Inc.

Hey, and thank you for standing by. Welcome to the Diamondback Energy third quarter 2024 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 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 Adam Lawless, VP of Investor Relations. Please go ahead.

Thank you, Julia. Good morning, and welcome to Diamondback Energy's third quarter 2024 conference call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback's website. Representing Diamondback today are Travis Geist, Chairman and CEO, Case Vantoff, President and CFO, and Danny Wesson, COO. 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 gap measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Dice.

Thank you, Adam. Welcome, everyone, and thank you for joining our call this morning. I hope you've had a chance to review both the shareholder letter that went out last night as well as the investor deck. We'll be covering a lot of that material in today's question session. Operator, please open the line for questions.

Thank you. At this time, we will conduct a question and answer session. As a reminder, to ask a question, you will need to press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Neil Dingman of Truist. Your line is now open.

Morning, guys. Nice update last night. Travis, guys, I'll save all my AI and data center questions this morning for your year-end call, and I'll jump into my first question this morning on capital efficiency, which, again, I think by my calculation, you all continue to have better than any other E&P. And so specifically, could you all, if it's for you or Travis, maybe speak to what you all believe could be your realistic free cash flow strategy per barrel next year or actually looking at just, you know, looking at what your breakeven would be, assuming cost, operations, and well results continue to trend as they've been here to date?

Yeah, Neil, you know, we've really focused on pre-cash flow generation over, you know, CapEx spends in recent years, and I expect that trend to continue. I think, you know, with the Endeavor assets under the hood, you know, that only improves our free cash flow margin, reinvestment rate goes lower, our corporate break-even, you know, we highlighted went down by $2 or $3 a barrel. And, you know, I think in a world of a tenuous macro, the lowest break-even and the longest duration of inventory is going to pay dividends. You know, there's two things we really look at, free cash flow margin, you know, which is the output of the reinvestment rate, but also, you know, how much capex are we spending per, barrel of oil produced. We like to say that we have the highest amount of barrels produced per dollar of capex in the business and expect that trend to continue. A lot of work has been done here integrating two companies very, very quickly. I'm ecstatic about the progress that's been made. We've already learned some things from the Endeavor side and vice versa. I think that's all going to accrue to the benefit of our shareholders through more free cash flow over a longer period of time.

Are you willing to put a number on where you see breakeven going at some point next year?

Yeah, I think we laid it out on slide nine. The post-dividend breakeven has gone from $40 a barrel to $37 a barrel. by our math, you know, I think we've always tried to say that we'd like our base dividend to break even at $40 a barrel. So, you know, either our break even has gone down or we have more implied capacity to look at the base dividend, you know, which we expect to do early in 2025.

Outstanding. Then my second question on the TRP asset trade specifically, how you all thought about valuation on each side. I'm just wondering on the The Delaware PDP side, was that based largely just on reserve value of the assets? And then looking at the Midland side, is that based on a per location or maybe help me with what else I'm missing when you're all thinking about that swap?

Yes, I'll give you a high level. The operated acreage in the Permian is very, very valuable. And since we did the Endeavor deal, we've been pretty vocal that we're not a seller of the Delaware Basin. I think this trade was pretty unique in that You know, TRP gets to move into the Delaware Basin and test some things in secondary zones, but Diamondback gets 18 ducts in the Midland Basin, a little more current production, and, you know, 55, you know, locations that compete for capital right away. So we're basically moving, you know, third and fourth quartile inventory into first and second quartile inventory, all while, you know, getting the benefit of capital efficiency from 18 ducks added to the program and assets in our backyard. We're looking at other options for other assets like this TRP trade. TRP was the first to move here and we were excited to get a trade done with them because those are pretty hard to do. From a valuation perspective, I'd say the high level PDP values were pretty similar. I would say we have a lower decline rate that we're selling We're getting more current production at a higher decline rate, but we're also paying for ducts and these 55 top quartile locations, which are worth a lot these days in the Midland Basin.

Great. Great details. Thanks, guys.

Thanks, Neil.

Thank you. Our next question comes from the line of Aaron Jayaram of JPMorgan Securities, LLC. The line is now open.

Good morning, team. Travis, you have, from a Diamondback perspective, it feels like the company has your hands in terms of several cookie jars in terms of your equity investments. And I was wondering if you could help us frame kind of the value creation potential or embedded maybe asset value that we may not be giving you credit for as we think about investments in Epic, CrudeLine, Deep Blue, and obviously maybe, I don't know, like Neil, I can wait until you're in. I wanted to get your thoughts on this data center kind of opportunity with the surface acres because investors have noted how one of a company who's developing a data center in Reese County has a pretty punchy evaluation in the equity market.

Sure, lots of questions there, Arun, but thanks for your time this morning. Listen, on this whole data center deal, we've been listening to our shareholders to try to figure out a way to respond to their questions about can we create more value from our gas stream. And when you look at what we have as a total company, we've got abundant natural gas, we've got abundant surface acreage, over 65,000 acres on a pro forma basis. And there's a need for greater electricity. So rather than continuing to get low margins on our gas and full boat on electricity, we're trying to figure out a way to be creative on ways to turn some of that natural gas into more value for our shareholders. The Epic pipeline was a move that allowed us to increase our ownership almost to a full trying to recognize that there's ultimately going to be a need out of the Permian Basin for increased crude capacity. And so, you know, while it's probably not a long-term investment, we think like a lot of our other equity investment methods, we'll be able to turn that into a very nice return for our shareholders. And in Deep Blue, we just continue to evaluate, you know, the sustainability of the, you know, the efficiency of that business model and recognize that there's some endeavor assets that could potentially fit into that as well as we continue to unpack value creation from the pro forma companies.

Great. My follow-up is I just wanted to maybe understand on the efficiency gain side of the equation. In your prepared remarks, you commented how you think you can kind of execute your 2025 program with 18 rigs versus maybe a previous expectation of 22 to 24, you know, maybe four frack leads versus five previously, you know, understanding you're probably DNCing the same amount of footage, what type of, you know, dollar per foot or cost gains do you get from just running less horsepower and rig lines? Just trying to understand that dynamic.

Yeah, I mean, you know, we set out when we announced the Endeavor deal thinking that 2025 would need between 22 and 24 rigs. You know, there's been a lot of efficiency on both sides throughout the year, and, you know, that 18 rig number is still going to accomplish the same amount of lateral footage as the higher rig count. You know, I think from a rig perspective, it's all about controlling variable costs, right? We all have to put pipe in the ground. We all have to use the raw materials, the same raw materials throughout the basin, but Diamondback is able to do that a lot faster. And so, you know, if a rig line is $70,000, $80,000 a day, you know, being able to execute with six less rigs, you know, translates to less variable costs in the business. Similar story on the frac side. You know, we think on the frac side, you know, we kind of learned from the Endeavor side about the higher pump rate We kind of increased our pump rate from 80 barrels a minute up to kind of 90 to 100. That allows us to, one, complete wells faster. There could be some benefits to the reservoir that we're studying very, very closely. But overall, that also reduces the variable costs needed to run tractors, which are much more expensive than a rig on a day-to-day basis. I think there will be periods of time where we need to run five simulfrac crews next year. High level, we see the simulfrac crews completing a little over 100 wells per year per crew. It's just amazing the efficiencies that both sides of the ledger have squeezed out of the business here in a year where you know, we keep saying, oh, they're close to the asymptotic curve of efficiency. Well, they blew that out of the water this year. So kudos to the teams and the basin experts executing on our business.

You know, Rudy, just to add to that, I think from a high-level perspective, the message that we really tried to emphasize was that all of the things that Case just outlined really describe delivery of synergies not only ahead of time, which we had originally contemplated, you know, through the year of 2025, We effectively got all of the synergies delivered now in the fourth quarter of 2024. And so it's faster and it's lower. You know, we put a note in there that we're, you know, on Middle Basin Wells, we're now at $600 a foot. And I think these guys got some momentum behind them that we're going to continue to see an improvement in that number. So high level, really proud of the organizations that they've checked their egos and looked at the right way to do things. from both perspectives, and what we're seeing early on is some significant Synergy deliveries. I know you've already seen these, but I want to just mention it that, like we've done in the past, we've put our Synergy scorecard in our investor deck with some details behind it. So if you'll just look at slides six and seven, you'll see a lot of the details that Case was just highlighting and also some of the high-level comments that I made.

Thanks, Travis.

Thank you. Our next question comes from the line of David Deckelbaum of T.B. Cohen. The line is now open.

Thanks, guys. Travis, in case, I just wanted to ask just in the context of some of the synergy scorecard being achieved perhaps a little bit earlier than anticipated and obviously announcing some of the incremental savings. You guys are sort of still kind of standing by that 4-1, the 4-4 budget for next year to kind of keep this 475,000 barrels a day flat. Are we at the point now, I guess, what sort of activity does that envision? And just given some of the incremental cost savings that we're seeing, are we trending now to be all the way at the lower end, or is there kind of a cushion built in there for some flexibility going into 26th?

Yeah, good question, David. We always like a little flexibility. I think given the macro environment, as Travis said in his letter, there's some things we're thinking about for next year. Again, always thinking about free cash flow generation over spending CapEx dollars. But I think we're certainly near the lower end of that original range, 4.1 to 4.4. to get to 480,000 barrels of oil a day next year. That includes the 5,000 barrels a day that Viper got into in our tumbleweed acquisition. You know, I think generally if you see well costs down $25 a lateral foot, we're completing about 5 million lateral feet a year. That's $125 million. So that's certainly going to be taken out of the budget. I do think there's still some of the ancillary spend items that we're refining, you know, combined infrastructure budget, midstream budget, environmental budget. But in general, certainly moving towards the lower end of that range, you know, we got Q4 to 950 to 1050 million of capex. You know, I wouldn't want to multiply the lower end of that number by four to get to your 2025 budget, but I'd certainly look at the midpoint or the high end. to, uh, to guide you to, to next year. Cause I think, you know, a lot of things are heading the right direction, not only well costs, but well performance, um, you know, things like the TRP trade, all that's going to accrue to the benefit of the CapEx budget next year.

I appreciate all that color. It makes, makes sense. Um, you know, perhaps you can get, uh, just add a little bit of color just on some of the, I know some others talked about some of the other assets, midstream, uh, you guys have highlighted, obviously the royalty dropdown. It seems like in the deck there's some expectation that some monetization is coming in 25. Can you kind of give a little bit of color on where those processes stand now and when you'd be expecting to see some inflows from there?

Yeah. So, you know, the big item is the drop down of mineral interest to Viper. You know, that's actively ongoing. We've been pretty vocal that early 2025 is our goal there. I don't see anything that's taking us off that track. Second is the midstream discussion with our partners at Deep Blue. I think that's a little less important than the Viper drop-down at the moment. It's been interesting closing this deal. Mr. Stevens was notorious for owning a lot of assets throughout the throughout the country. We've got some small assets in the Bakken. We've got a small piece of some offshore wells in the Gulf of Mexico. We're excited to continue to monetize some of those smaller assets. I don't think they're going to make a huge dent in the cash number, but they're all little things that you'd expect us to monetize at the right time. I think the other big item is about 15,000 acres in the Delaware Basin. of, you know, both operated and non-operated positions. So, you know, we're going to look at that, try to trade and block up where we can, but, you know, we're not in the non-op business given our cost structure, and we'd likely monetize that into a very healthy market at some point.

Thank you, guys.

Thanks, David.

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

Good morning. Your 2025 base plan is clear, and you mentioned the ability to refine that plan based on the macro environment. Can you talk about how dialable that plan is before dis-efficiencies kick in?

Yeah, Bob, I think we've got a lot of flexibility. I don't think it's the tool, it's the toolman, right? So we can dial things up and back very, very easily. I think just generally if other companies are seeing what we're seeing, this is not a strong macro environment. So I don't know why the discussion of growth or multi-year growth needs to be in the equation. I think Diamondback has learned that our growth profile impacts the macro and we're very focused on the macro here where almost universally the street is calling for oversupply in 2025. So I think we're building in flexibility to, spend less should that come to fruition but it's not hard to grow volumes in the Permian Basin with the assets that we have so I think what you would you would expect is you know what looks easy on the outside is hard on the inside but we we make it happen but can it be gradual can it be like deferring some Wells or does it have to be dropping a rig line or dropping a frack spread what's the

Can you tweak things around the edge, I guess?

Oh, yeah. I mean, we already do that, Bob. We went into the year running 15 rigs. Endeavor was running 10. Our team was ahead of schedule. We dropped to 10 rigs mid-year because we had drilled more wells than we expected in the first six months of the year. So dropping rigs, adding rigs, dropping a crew, swapping a crew, that's just what you expect us to do.

And Bob, this is Danny. Our supply chain setups such that we don't really have any, you know, really firm obligations with any kind of significant terms. So we've got a flexibility built into our supply chain so that we can pivot to any kind of market conditions or signals that we need to. It won't be on a week-by-week basis, but if we see, you know, certainly a longer-term trend in the market, we'll pivot our activity levels, you know, to protect our free cash flow. and focus on driving shareholder returns over any kind of growth or production output.

Very clear. Thanks. Thanks, Bob.

Thank you. Our next question comes from the line of Neil Mehta of Goldman Sachs. Your line is now open.

Yeah, good morning, team. I just love your perspective on the macro. I think Travis, in your letter and in these comments, you've kind of shared a more cautious view for 2025. Is that a demand-driven view, a supply-driven view? And then, you know, you've taken a different tack than some of the majors and other independents. It takes a little bit more of a growth orientation into 2025 in the Permian. Why do you think your strategy is the right strategy?

Well, you know, As Kay's outlined, our strategy really is for flexibility. When you look at the macro right now, it's kind of hard to look at a world that has four to six million barrels a day of surplus capacity on the sidelines and try to think we can grow effectively into that. We've learned as an industry and at DynaVac the hard way that you really need to focus on shareholder returns and free cash flow generation in this industry. And there may be a call for growth at some point in the future, and I expect our shareholders would look to us to respond to that call. But it's certainly nothing that we hear or see today. And as Danny alluded to, we've got the flexibility to go any direction we need to go. But with this macro view, we're going to just stay conservative and let volume be the output of cash flow generation.

Well, and most importantly, we're focused on per share cash flow and free cash flow, right? So if the macro is tenuous in 2025, well, per share metrics are going to have to grow through a lower share count. And, you know, we've always been about per share metrics, both cash flow and free cash flow. We have a slide on our deck that shows that growth over time. So that's not going to stop. I just think, you know, being cognizant of your impact to the global market is important, and it's a lesson that Diamondback learned through 2020, and we hope the industry also learns that lesson.

Yeah. Thanks, Case, and thanks, Travis. That's the follow-up, which is just around share buybacks. At different points in the cycle, you've elected towards the variable or dividend-oriented strategy versus the buyback, but it's notable that you're really leaning back into the share repurchase program. So can you get a to talk about that evolution. Maybe it's the reflection of your thoughts on valuation and maybe being counter-cyclical if you do think we're in a softer period in 2025, but just your thoughts on the best way to allocate capital and why you're leaning towards the buybacks.

Yeah, I mean, I think Travis would echo this comment, but capital allocation is our most important job. And, you know, we've had a flexible capital allocation philosophy since, We started this, you know, lower growth, high free cash flow generation business. We've always, you know, been able to flex between a buyback and a variable dividend. I would say, you know, post-endeavor, we certainly have a business that's worth more combined than Diamondback standalone per share. And so that's increased kind of our tolerance for buying back shares at these levels. I mean, I think... you know, should things get improved from here, we buy back less. Should things get significantly worse from here, we lean in and use more of our free cash flow to buy back shares. You know, that's what you'd expect us to do. I think the only thing that's really, you know, going to be steady is base dividend and base dividend growth, but you should expect us to maintain that flexibility between buyback and variable, you know, despite our larger size.

And I think, Neil, the counter-cyclicality of share repurchases has proven to be the right strategy in a commodity-based business. Our industry over the last 10 years probably has many instances where oil price was high, free cash flow was high, and share repurchases were high. Then oil price cycles down and you end up either issuing shares at the bottom or rather unanticipated results. Again, just like we were talking about on the flexibility of our return program, we try to learn from the past and not repeat any mistakes, and that's certainly foundational to our share repurchase program.

Makes a lot of sense. Thanks, guys.

Thanks, Neal.

Thank you. Our next question comes from the line of Betty Jang of Barclays. Your line is now open.

Good morning. So I was wondering if you guys can talk a bit more about the opportunities with the surface acreage and the water, being a provider of water in the Permian. I mean, these are recurring revenue streams. That's clearly getting a fairly high multiple in the market. What does it take for you to capture these type of new revenue streams and how meaningful could it be?

Yeah, Betty, you know, I think there's a lot of land out here in West Texas, a lot of surface. We have about 65,000 acres in our portfolio. We also control a lot of molecules, you know, so I think... You know, the mandate, as Travis mentioned earlier, from our investors is to stop selling your gas for zero and paying full boat for power. And so we're going to find ways to, you know, benefit Dynamag shareholders by finding a new local market for our gas, but also insulating part of our business from what we believe to be an increasing demand power price in Texas over the next 10 years. So if we can cut off that cycle and benefit Dimebag shareholders, we're going to do it. You know, I think the message we kind of put out there is that West Texas, you know, has a lot of land, a lot of surface, has a lot of gas that's, you know, being sold for less than it should. It's got a lot of water production with that oil production that we have in the basin. And I think that results in a very cheap way to develop power. And the data center operators have not been focused on the Permian yet. There's certainly some conversations that are happening. And we're kind of putting the flag out there that this is a very cheap way to execute their business model while benefiting Diamondback shareholders. So more to come on that. We're getting started. But we put a little teaser in the presentation this quarter.

Yeah, no, I appreciate that. Maybe my follow-up is just how you're thinking about funding these type of investments. Would it be a JV partner with an infrastructure provider, infrastructure sponsor or, yeah, because these, the gas power plants are pretty capital intensive to build.

Yeah, I mean, listen, I think you'd expect us to do similar things to what we've done in the past, right? Our first wave of equity method investments, which created a lot of value for our shareholders, was based on midstream and pipeline getting out of the basin, and we think this can be a similar route. You know, I think it's still early, but I think you'd expect us to lean on the experts as our partners. I think we provide a lot of expertise in how to navigate the basin and navigate the rock, and... we'll let our partners on the power side handle their portion of the business.

Makes sense.

Thank you for that.

Thanks, Betty.

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

Hey, good morning. First, congratulations on closing the deal. I know you've been working on that for a long time.

Thank you.

In your shareholder letter, you highlight the two big operational changes of using clear fluids and drilling and using simulfracts for completions of all wells. I wondered if you could expand on that a little bit. Were those FANG practices that you're bringing to Endeavor Acreage? And do you have a rough estimate of what percentage of your wells used those techniques in 2024? Yes.

Well, for the Diamondback side, all of the wells we drilled and completed in 2024 were using clear fluid. And as of the fourth quarter, uh today all the rigs that we're running are using clear fluid drilling system and yes that's a that's a definite you know bring over from the diamondback side uh simulfrac all the wells we completed on a standalone basis uh besides the occasional spot crew in 2024 we're using simulfrac and as of today on a pro forma company uh we're using all simulfrac operations uh four rigs or four crews and three of those are electric

Great, thanks for the detail. That's all for me.

Thanks, Kevin.

Thank you. Our next question comes from the line of John Freeman of Raymond James. Your line is now open. Good morning, guys.

Hey, John.

The first question I had, just when we sort of think about like long-term about trying to improve the realized gas price in the Permian, I believe in the past when you've done acquisitions, a lot of those came with, you know, marketing contracts. You all kind of had to wait for those to roll off before you had control. I believe Endeavor didn't really have any kind of binding marketing contracts. So if you sort of think about just the big benefit you're going to now get with just the dramatically bigger scale, maybe ability to kind of, you know, get space on future pipe, et cetera, maybe just how you can talk to, you know, abilities to kind of leverage that scale to improve pricing.

Yeah, good question, John. You know, we do have certainly some flexibility, particularly on the residue gas, natural gas side, as well as the crude side. You know, you've seen us make some moves already on the crude side with a little bit of an increased commitment to the EPIC pipeline, as well as, you know, increased ownership. So, you know, that fits with our prior strategy of driving value through midstream but protecting ourselves commercially. You know, I think on the gas side, you know, we're – We've got a good amount of space on a combination of Whistler and Matterhorn, so we have about $250 million a day of space on those pipes. Those were decisions made a couple years ago. We expect to have a good amount of space, about 10% of the pipe, on Blackcomb, which is the next pipe from the Whitewater crew that's coming out in a couple years. And that leaves some gaps for other opportunities. Energy Transfer, who bought WTG. We're talking to them about some things about getting our gas out of the basin. That kind of leaves a little bit of gas for us to make some of these capital allocation decisions in the basin related to power, also related to our Verde Clean Fuels investment. We heard our investors loud and clear. It's time to stop selling gas at zero and diversify our risk. that's what we're going to do, particularly as more and more gas gets produced in this basin.

That's great. And then just my final question. In the prepared comments, you'll talk about, you know, point out sort of the opportunity to implement these kind of shared best practices, if you will, of the two companies, and you're closely studying kind of various completion designs. Just in, how does that kind of work in practice? Do you all just sort of start to you know, I guess, quite frankly, test these in the field or kind of what's the process for maybe implementing some of these changes to see if there is something that, you know, sort of has legs that y'all could, you know, uh, implement, uh, across the board.

Well, the first thing we did was, uh, we, we had over 650 office moves in the first six days, uh, post, uh, post closed onboarded a thousand employees. And so we physically located a lot of the GGRE teams together. And then since the physical integration, we've started the team integration as well, too, where teams are getting together, actually having conversations about, okay, here's what we were doing. Here's what you were doing. Now let's try to figure out how we can put those things together in the best way to go forward. And I'm real proud of the organization. As I mentioned earlier, they've kind of just checked their egos at the door, and we're really trying to learn the best from both sides. you know, some of the pace and requirements for a public company and the 90-day scorecards is a little different than working for a private company. But all things considered, I couldn't be more proud of the way the organization is responding to giving and receiving grace and trying to seek to understand as we put these synergies together. And the synergies are going to be delivered as we put these teams together. And I think the scorecard that you've seen – We'll figure out a way to communicate some of these wins over time. But the big ones that we promised in February of this year, we've already delivered. And again, that's also a credit to the organization.

Thanks. I appreciate it.

Thank you. Our next question comes from the line of Roger Reed of Wells Fargo Securities. Your line is now open.

Hey, thanks. Good morning. A lot of it's been hit, but I thought I'd come back on the productivity and efficiency side of things. Maybe just a quick look back for a look forward. But as you think about the improvements, both in terms of, you know, drilling speeds, drilling capabilities, lower drilling costs, and then a similar kind of approach on the frac side. How much of it do you think is, you know, call it mechanical changes, meaning going to, you know, electric fracks or, you know, the higher spec drilling rigs relative to, you know, experience and learning curves, you know, the crews themselves, you know, and the reason I'm asking is I'm trying to think about if it's mostly mechanical, that kind of runs its course, but if it's a combination of factors, then that would, you know, indicate we do have further to go in terms of more cost reductions.

I think it's a combination, but it's also a mentality that, you know, when we see something mechanical that works, it gets implemented right away across the whole portfolio. It's not, hey, we think this works, let's talk about it next fall. If this works, let's do it now. And that's happened on both sides, you know, on the Dimebag side, clearly on the Simulfrac plus drilling fluids. And on the Endeavor side, you know, some of their post-completion work was really intriguing to us, and we've put that into effect right away. So, you know, I would say also the consistency of the business model, you know, not having to change the plan for every $10 move in oil price is allowed for large-scale consistent development, you know, with a lot of crews having worked for us for three or four years now on the Halliburton side, and on the rig side, you know, we have some preferred vendors that have worked with us for a long time. So I think there's certainly more to come. We're not going to give any of these efficiencies back. And I think, you know, on top of that, the completion design work that's going on between the two teams is what is probably most exciting to me personally eight weeks in on what can be done to improve our results going forward.

That makes sense, and this probably comes back a little bit towards Bob's question earlier about what you would do if oil prices were to fall, we were to get an oversupply in 2025. When you think about the productivity and efficiency, it's clear, as we've heard from you and other companies, a consistent plan that allows you to drill and complete wells and minimize your non-productive time and all that. So as you think about making tweaks along the edge, giving up those productivity and efficiency trends could be counterproductive to actually saving money in the very near term. What's the right way for us to think about how you'll weigh those decisions if they do, if market does force that upon you next year?

Yeah, Roger, I think it goes back to what Travis said about lessons learned, right? And I think we have the size scale and balance sheet to be able to withstand a cycle should it happen. I think the only thing that we would probably change is that at the low point of the cycle, you're going to be putting pipe in the ground cheaper than any point across that entire cycle. So I think we'd probably prefer to build more ducts than maybe in the past and have the balance sheet capacity to do so. But I think that would be the big change. The efficiency on the frac side, We've proven we can stand up. We set up two simul-frac crews just this quarter, and they're running at KPIs that are similar to the rest of our crews within a pad. So I don't really buy into the losing efficiencies argument when we're based in Midland. We know this basin as well as anybody, and we've done this before.

Yeah, Roger, that's great. That's a cultural element that you'll see throughout Diamondback. What I'm speaking to specifically is we don't ever cede ground once we've taken it. That's not a function of the service companies. That's not their responsibility. Our business partners on that side, it's our responsibilities as supervising and leading those functions to bring back to the table the ground that we had taken so that it isn't lost. That's a very, very important cultural element to maintain in our resting class execution and low-cost operations. And I hope that makes sense. Roger.

It does. I appreciate the clarity. Thanks, guys.

Thank you. Our next question comes from the line of Paul Chang of Scotiabank. The line is now open.

Thank you. Good morning, guys. Good morning, Paul. Good morning. Sharpa and the team, When we put the two companies together, initially you're coming up with a synergy target, but that's basically saying that, okay, you know, Endeavor, the DNC cost is higher than you, so you can bring it down. But, of course, Endeavor is also probably doing something better than you guys, as you're saying that you're not going to have the big ego. So over the past three months, can you identify a couple of the biggest issues maybe that what you found that they have done substantially better than you, and can you quantify that? What is the potential saving from those?

Yeah, I'll let Case talk about the specific savings, but we're eight weeks into this, and we had our operations review a couple of weeks ago, and we're immediately seeing some of the benefits of the Endeavor experience on drill-outs particularly. where they've got a better drill out. It costs a little bit more money, but it's done quicker. And then the other one is on... Completion designs.

Yeah. Combined look at completion designs, right? So, you know, we've looked across the fence line at what Endeavor was doing for the last five years, and then vice versa, and think about it. Now we get to answer the questions that could not be answered a couple years ago, right? If they're drilling better, you know, in 2022, they were drilling better Joe Mill, Middle Sprayberry Wells than us. And we had a big study on, hey, what's Endeavor doing? And I'm sure, you know, they did similar things looking at us. So, again, it goes back to that comment that Travis put in his letter. You can't model those benefits in an Excel spreadsheet, but I can guarantee you that there will be long-term benefits to the amount of data that's being shared between the two companies, and that is kind of the holy grail of better combined well results. Better combined well results with the lowest cost structure is going to be a pretty impressive combination over the coming years. I think the other thing that we looked at, we have a huge production base, almost 600,000 gross barrels of oil a day. I think there's a lot of work to be done between the two teams on efficiencies and economies of scale on the production operations department. More to come on that, that's probably slower to develop in D&C, which is front and center, but there's a lot of things coming our way.

And Paul, if you step back from it, it's hard to imagine any company, any single company that has more basin expertise than the pro forma company at Diamondback and Endeavor. And that's what we're seeing is we're seeing these basin experts come together collaboratively and come up with a better solution to the problems. And those better solutions are always underpinned by execution and cost. And so, as Kay's just alluded to, it may be hard to articulate today, but you're going to see it over time as we continue to pick up the quarters and dimes and nickels as we put these two companies together in the space and experts are trying to solve the same problem.

Thank you. The second question is that on the payout, in the third quarter you did 78% and of course you've been saying about 50% on the free cash flow. If we're looking out over the next couple quarters and if the share price stay relatively close to where we are, how you balance between your desire to quickly get down to 10 billion net debt and the payout ratio?

Yeah, Paul, good question. You know, I think I'll take the second part first. I think if we're in this kind of stock price environment, you're probably, you know, sticking to 50% of free cash getting returned. And then when you go back to the third quarter, you know, we had a couple things that impacted your free cash flow for the quarter, right? One, we only had Endeavor account for 20 days out of the quarter. So, you know, even though the effective date of the deal was January 1st, The public numbers only account for 21 days of Endeavor. Really, the combined free cash flow of the business was a lot higher than that. Second, the Stevens family decided to sell down some of their shares post-close. We've been pretty vocal with our shareholders that those are opportunities for us to commit to a large buyback at one time. That's what we did with 2 million shares closed. repurchased at one time. So I think that's more the exception than the norm here in this price environment, but that's why we have a strong balance sheet to be flexible to do things like that, to do things like the TRP trade, and still be on our way to $10 billion in net debt very, very quickly.

Thank you. Can I sneak a quick follow-up?

Sure.

Any idea what's the family intention about their share? They sold 14.4. Are they done or did they indicate that what's their intention?

Yeah, you know, I don't have an answer to that, Paul, but I do know that we have a lot of flexibility and a lot of capacity to participate and support our public shareholders' you know, on a consistent basis. I think the only thing that we've said publicly about the Stevens family stockholders is that, you know, over time they'd like to get down to where their voting rights equal their ownership, which is, you know, 25% of the business from about, you know, 35% today.

Thank you.

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

Good morning, Travis, Casey, and Danny. I just have one question, and I don't think it's been covered. You've covered a lot in your Q&A here, but it's really on OPEX. And I noticed that you've moved down the midpoints of your unit guidance. I think it was $0.10 on OOE and $0.20 on GP&T. And I'm wondering if you could give some – maybe kind of portion that up. How much of that is maybe the Diamondback legacy assets doing better? How much of it is actually the contribution from the Endeavor asset base? In that case, it would suggest that the Endeavor assets are lower cost than legacy Diamondback. Or also, maybe it's just early early realization of OPEX synergies. And if you kind of give us a sense for that, and then, Travis, going back to a point you made in your shareholder letter, it's, you know, you guys are still really, I guess, really, you know, optimizing, really analyzing and optimizing for 25. And if your cost basis has already gotten better for 4Q, what does that suggest for 25 in your mind?

I'll take the OpEx question first. I think some things have moved down as a result of the combination. I think we're going to be pretty conservative on guiding to OpEx, only having 20 days of a combined business. We're going to do a lot of work for finding that over the next three months. I'm confident that we'll find some things that combined will come down on the LOE side. Obviously, the big difference between Diamondback's cost structure and Endeavor's on LOE is that Diamondback sold our water business, so we're paying a third-party fee for water disposal and handling versus Endeavor consolidating that internally. That's a $0.50, $0.60 delta per BOE by our estimation that's going to help us combine. On the G&A side, we have a lot more BOEs. and not a lot more G&A, so I'd expect that to come down a little bit. But all these things I think we'll get to refine here with Q4 reporting after we see three months of the combined business. And on 25, Charles, I think we kind of hammered that point that well costs today are at the low end of our prior range. In some cases, we're even below that. So what we need to do is focus on a plan that maximizes free cash flow. produces a lot of oil and has a very, very low break even. So that works ongoing. I think things like the TRP trade getting worked into the plan are going to be free cash flow accretive to our stockholders.

Thanks for that in detail, guys.

Thanks, Charles.

Thank you. Our next question comes from the line of Leo Mariani of Roth. Your line is now open.

All right, I just wanted to ask a little bit more on 2025. I know it's not official guidance and still the outlook, but just kind of looking at where you are, you know, for fourth quarter on production at 840 to 850, and you're basically saying we're reaffirming 800 to 825, you know, for next year. It kind of feels like maybe that's a little conservative. I think maybe gas has been outperforming, you know, a bit here. And then also just on 25, I think kind of the pro forma plan has always been to be sort of flattish on oil per the macro, that kind of makes sense. But it certainly sounds like you guys would be, you know, willing to kind of, you know, let that decline, you know, on your end. So just wanted to kind of, you know, verify that as, you know, if it is a bad macro, do you see kind of a small decline and a pullback? Or would you be willing to have a more meaningful decline if oil prices are a disaster next year?

Yeah, absolutely. Our base case is, you know, still hit 480,000 barrels of oil a day. We got it Q4 to 470 to 475,000 barrels of oil a day. So base case still hit 480 next year for, you know, low fours of CapEx. I think, you know, the macro is going to dictate the decision, you know, closer to January on what ends up happening. But, you know, and your comment about the BOEs, yeah, you're probably right. We're very conservative on the BOE number. I think you can certainly assume closer to 840 to 850 BOEs versus that 800 to 825. At the end of the day, the oil drives the decision here, so we're very, very focused on oil guidance. But, you know, BOEs probably will end up being closer to 850 versus that 800 to 825.

Okay, and just on the tax side, I wanted to see if there's any incremental cash tax benefit at all from Endeavor. I mean, your cash taxes came in, I think, below what you guys got it to in 3Q. I know it was only 21 days or so of Endeavor, but do you expect any kind of incremental benefit at all there, or is it going to be roughly, you know, kind of the same rate going forward?

Yeah, I don't think it'll be material. You know, we'll still be in the kind of high teens, you know, mid to high teens cash tax rate.

Okay. Thank you. Thanks, Leo.

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

Yes, good morning. I wanted to come back to being flexible with the 25 plan. A lot of questions on the how, but I didn't hear about when unless I missed it. But just given your low breakeven, at what oil price do you think about shifting out of maintenance mode? You know, when do you start turning the dial?

Well, I mean, high level we're really not in maintenance mode, right? We're at 470 to 475 oil today. We got into 480 next year. Well, that's, you know, 2% growth. It is something. So, you know, that's kind of the first goalpost. You know, I think the key point is not necessarily, you know, how or when. It's that, you know, Diamondback is cognizant of this new business model and cognizant of the macro. And if we're not, we're not doing our jobs. So, you know, I think being cautious when things are, you know, when oil is in the high 60s and you have pockets of geopolitical premium coming in and out is a prudent thing to do. So, you know, at the end of the day, the lowest cost operator should be producing the last barrel in the basin. But I think, you know, that spreadsheet math is what's gotten this industry in trouble in the past. And it feels like we're getting ourselves in trouble again. So I think, you know, again, I can't hammer it up. Free cash flow trumps CapEx at Diamondback these days.

I got it. I appreciate it. And then a quick one on, you know, just the trends you're seeing in the marketplace. It's really nice to see you guys hitting that 600 a foot so quickly. And you mentioned some additional, you know, deal synergy caps. But I'm curious, Because we have a background here of deflation and service costs and tangible item costs. So just how much of that kind of background deflation is baked into that $600 number? Or could that number still continue to trend down above and beyond any additional efficiency and deal synergy capture just from deflation? If you mark the market, your service contracts today, where do you think you could see that $600 number go?

We're pretty mark the market. That $600 is a real-time number. Certainly, there are wells that are below that number, but we're adding more Wolf Camp D to the plan. That's a more expensive well to drill. There's a couple of Barnett Woodford wells throughout the portfolio that I think in general, the core of Wolfberry development is probably below that. Longer laterals also help that, but that's a pretty real-time look. As Danny mentioned earlier, we don't have a lot of long-term contracts. We recontract a lot. We get a lot of market intelligence on the service cost side. I'd say above that, Scott, I don't see a recount that's going up in the Permian over the next quarter or so, and so that should continue to deflate prices significantly. which should accrue to our shareholder's benefits.

Thank you.

Thank you. Our next question comes from the line of Kalei Ackermine of Bank of America. Your line is now open.

Hey, good morning, guys. Thanks for getting me on. I'm going to take another shot at 25 capex. First on the $600 per foot, it's a solid update. And I think it shows the talent of your team to drive that low number even lower. But wondering if you can help ground us. So I'm looking for a couple of pieces. First, can you remind us what's in the original 2025 guide? And then talk about the non-DNC piece embedded in that guide. Do you see any one-off spending to bring the Endeavor assets up to your standards? And then whatever that piece is, does that roll in 26?

Yeah, I mean, listen, I'll answer it again. You know, I think 625 was kind of our assumed well cost for 25. You know, now we're at 600. There are some wells below that. So we'll see what happens over the next couple months. I'm confident in this team's ability to drive out costs. But, you know, we also like to guide fairly conservatively 15 months ahead of 2025, you know, full year. So we like to keep a little flexibility on our side. I'd say on the non-DC&E CapEx, the Endeavor assets are as good as ours above ground. I think there's some things, you know, probably $50, $60 million of environmental CapEx we got to spend next year, which is kind of one time in nature. I think, you know, the combined infrastructure budget will probably be a little higher in 25 than it will in 26. You know, we like to think that the infrastructure budget eventually moves closer to 6, 7 percent of total capital. Endeavor has a midstream business that has some capex that should we sell the midstream asset to our JV, that capex would be removed. Some moving parts, I think high level, the key drivers are heading the right direction. I think the combined acreage position should result in lower spend above ground over time than 2025.

Awesome. I appreciate the color. Um, second question is going to go to deep blue here. You're targeting maybe even Denver dropped in first half of 25. It sounds like in the first deal, you took back 500 to cash, 30% equity, kind of wondering about deal structure. What should we expect for the upcoming drop? Will it be all cash or do you take back even more equity? And then for the guys that don't follow that space, how does one think about the range of deal multiples and water assets?

Yeah, I mean, it's a lot of we'll see. I think our preference is cash and more cash to accelerate deleveraging targets. But we recognize we have a partnership with Deep Blue and they should recognize the same, that we are going to work on this business to grow value together. And, you know, that doesn't mean – that means we're not – you know, we've never been in the business of levering up a sub in exchange for cash at the parent level. And so we'll be flexible. I think we've been flexible to date, and that business has created a good amount of value already in a year. So a lot of work to do. I'd say that's less of a near-term objective than the drop-down. We have a lot of people working very hard on the mineral drop-down, which is a very significant deal for both Diamondback and Viper.

And maybe to the third one, just on the royalties, Rob, it's a really big chunk when you think about the amount of EBITDA associated with that asset. And 8 to 10x, you get to really big numbers real fast. Are you still thinking that could be one package, or is there a scenario where you break it down into more bite-sized pieces?

I think our preference is to do most of it at once. You know, I think... Viper has a lot of strategic objectives that we'll talk about in about an hour on its call, but I think getting the dropdown behind us and showing the size and scale of that business on a combined basis is going to be important to future opportunities at Viper. I think it's amazing. Viper today has an interest in 11,000 horizontal wells across the basin, and that's an information advantage that I don't think can be replicated. I think momentum is very strong at Viper. That's also good for Diamondback shareholders because our ownership value has gone up dramatically this year. But I think our preference to get most, if not all, of it done and be off to the races in 2025.

Great. Thanks, guys.

Thank you.

This concludes the question and answer session. I would now like to turn it back to Travis Seif, CEO, for closing remarks.

Thanks again for everyone listening in today and for the good questions. If there's any follow-up questions that you have, just reach out with using the numbers provided. Thanks, and y'all have a great day.

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