Good day 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 speakers' presentation, there will be a question-and-answer session. Please be advised that today's conference is being recorded. I would now like to hand the conference over to Adam Lawlis, VP of Investor Relations. Please go ahead.

Thank you, Julia. Good morning, and welcome to Diamondback'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 Stice, Chairman and CEO; Kaes Van't Hof, 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 GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.

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 day. We'll be covering a lot of that material in today's question session. Operator, please open the line for questions.

Thank you. Our first question comes from the line of Neal Dingmann 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 for your Travis, maybe speak to what you all believe could be your realistic free cash flow per barrel next year or actually looking at, just looking at what your breakeven would be assuming cost operations and well results continue to trend as they've been year-to-date.

Yes, Neal, we've really focused on free cash flow generation over, CapEx spend in recent years and I expect that trend to continue. I think, with the Endeavor assets under the hood, that only improves our free cash flow margin, our reinvestment rate goes lower. Our corporate breakeven, we highlighted went down by two or three dollars a barrel. And I think in a world of a tenuous macro, the lowest break even and the longest duration of inventory is going to pay dividends. There's two things we really look at free cash flow margin, which is the output of the reinvestment rate but also how much CapEx are we spending per barrel of oil produced? And we like to say that we have the highest amount of barrels produced per dollar of CapEx in the business and you expect that trend to continue. So a lot of times a lot of work has been done here integrating two companies 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. And 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?

Yes, I mean I think we laid it out on slide 9. The post dividend breakeven has gone from $40 a barrel to $37 a barrel by our map. I think we've always tried to say that we'd like our base dividend to break even at $40 a barrel. So either our breakeven has gone down or we have more implied capacity to look at the base dividend, 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 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 tell me what else I'm missing when you're all thinking about that swap.

Yes. So I'll give you the 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 TRP gets to move into the Delaware Basin and test some things in secondary zones. But Diamondback gets 18 DUCs in the Midland Basin, a little more current production, and 55 locations that compete for capital right away. So we're basically moving third and fourth quartile inventory into first and second quartile inventory, all while getting the benefit of capital efficiency from 18 DUCs added to the program and assets in our backyard. So 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.

No. Great. Nice deal.

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 DUCs, and these 55 top quartile locations, which are worth a lot these days in the Midland Basin.

Great details. Thanks, Kaes.

Thanks, Neal.

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

Good morning, team. Travis, from a Diamondback perspective, it feels like the company has your hands in terms of several cookie jars. In terms of your equity investments, 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 the epic crude line Deep Blue, and obviously maybe I don't know if I like Neal, 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, Reeves 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, 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. 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 third, trying to recognize that there's ultimately going to be a need out of the Permian Basin for increased crude capacity. And so, 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 continued to evaluate the sustainability of the efficiency of that business model and recognize that there are 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, maybe four frac fleets versus five previously. Understanding you're probably seeing the same amount of footage, what type of dollar per foot or cost gains you get from just running less horsepower and rig and rig lines. Just trying to understand that dynamic.

Yes, I mean, we set out when we announced the Endeavor deal thinking that 2025 would need between 22 and 24 rigs. There's been a lot of efficiency on both sides throughout the year. And that 18 rig number is still going to accomplish the same amount of lateral footage as the higher rig count. I think from a rig perspective, it's all about controlling variable costs, right? We also put pipe in the ground. We also use the raw materials, the same raw materials throughout the basin. But Diamondback is able to do that a lot faster. And so, if a rig line is $70,000, $80,000 a day being able to execute with six less rigs, translates to less variable costs in the business. Similar story on the frac side. We think on the frac side, 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 complete wells faster. There could be some benefits to the reservoir that we're studying very closely. But overall, that also reduces the variable costs needed to run frac crews, which are much more expensive than a rig on a day-to-day basis. So, I think there will be periods of time where we need to run five simul-frac crews next year. High level, we can see the simul-frac crews completing a little over 100 wells per year per crew. And it's just amazing the efficiencies that both sides of the ledger have squeezed out of the business here in a year where 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.

Arun, 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 Kaes just outlined really describe delivery of synergies not only ahead of time, which we had originally contemplated through the year of 2025, we effectively got all of the synergies delivered now in the fourth quarter of 2024. So it's faster and it's lower. We put a note in there that we're on middle of 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. And I just want to, I know you've already seen these, but I want you to just mention it that we've put our, 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 6 and 7, you'll see a lot of the details that Kaes was just highlighting and then 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 TD Cowen. 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 to 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 2026?

Yes, 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, overspending 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 guided to in our Tumbleweed acquisition. 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, combined infrastructure budget, midstream budget, environmental budget, but in general, certainly moving towards the lower end of that range, we guided Q4 to 950 million to 10.50 million of CapEx. 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 guide you to next year because I think a lot of things are heading the right direction. Not only well cost, but well performance. 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 sense. Perhaps you can get just add a little bit of color just on some of the. I know some others talked about some of the other assets midstream you guys have highlighted obviously the royalty drop down. It seems like in the deck there's some expectation that some monetization is coming in 2025. 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?

Yes. So, the big item is the drop down of mineral interest to Viper. 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. And then, it's been interesting closing this deal. Mr. Stevens was notorious for having a lot, owning a lot of assets throughout the country. We got some small assets in the Bakken, we got a small piece of some offshore wells in the Gulf of Mexico. So we're excited to continue to monetize some of those. Some of the 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 both operated and non-operated positions. So we're going to look at that, try to trade and block up where we can. But 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. Your 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 viable that plan is before dis efficiency kick in?

Yes, Bob, I think we got a lot of flexibility. I don't think it's the tool, it's the process. Right. So we can dial things up and back very, 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 multiyear 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 expect is, what looks easy on the outside is hard on the inside, but 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 frac spread? What's the. Can you tweak things around the edge, I guess?

Oh yes. We already do that, Bob. We started the year with 15 rigs, and Endeavour was operating 10. Our team was ahead of schedule. We reduced to 10 rigs mid-year because we had drilled more wells than we anticipated in the first half of the year. So, adjusting the number of rigs, adding or dropping crews, that's just part of our operations.

And Bob, this is Danny. Our supply chain setups such that we don't really have any, really firm obligations with any kind of significant terms. So we've got flexibility built into our supply chain so that we can pivot to any market conditions or signals that we need to. And it won't be on a week-by-week basis. But if we see certainly a longer-term trend in the market, we'll pivot our activity levels 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.

Yes. 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 via supply driven view? And then, 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, as Kaes outlined, our strategy really is for flexibility. And when you look at the macro right now, it's kind of hard to look at a world that has 4 million to 6 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 Diamondback 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 we've always been about per share metrics, both cash flow and free cash flow. We have a slide in our deck that shows that growth over time. So that's not going to stop. I just think 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.

Yes. Thanks, Kaes. 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 to talk about that evolution? Maybe it's the reflection of your thoughts on valuation and maybe being countercyclical 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 buyback.

Yes, I think Travis would echo this comment, but capital allocation is our most important job and we've had a flexible capital allocation philosophy since we started this lower growth, high free cash flow generation business. We've always been able to flex between a buyback and a variable dividend. I would say post Endeavor, we certainly have a business that's worth more combined and diamondback standalone per share. And so that's increased kind of our tolerance for buying back shares at these levels. I mean, I think, 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. That's what you'd expect us to do. I think the only thing that's really, going to be steady is the base dividend and base dividend growth. But you should expect us to maintain that flexibility between buyback and variable despite our larger size.

And I think, Neil, the countercyclicality 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. And then oil price cycles down and you end up either issuing shares at the bottom or other unanticipated results. So 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, Neil.

Thank you. Our next question comes from the line of Betty Jiang 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 water in the Permian. I mean, these are recurring revenue streams that's clearly getting a fairly high multiple in the market. So what does it take for you to capture these type of new revenue streams? And how meaningful could it be?

Yes, Betty, 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. So I think the mandate, as Travis mentioned earlier from our investors, is to stop selling your gas for zero and pay in full boat for power. And so we're going to find ways to benefit Diamondback 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 power price in Texas over the next 10 years. So if we can cut off that cycle and benefit Diamondback shareholders, we're going to do it. I think the message we kind of put out there is that West Texas has a lot of land, a lot of surface. It has a lot of gas that's 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.

I appreciate that. My follow-up question is about how you plan to fund these investments, whether through a joint venture partner with an infrastructure provider or an infrastructure sponsor, as gas power plants are quite capital intensive to build.

Yes. Listen, I think you'd expect us to do similar things to what we've done in the past. Our first wave of equity method investments, which created a lot of value for our shareholders, was based on midstream and pipelines being out of the basin. And we think this can be a similar route. 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.

Thanks, Kevin.

In your shareholder letter, you highlight the two big operational changes of using clear fluids and drilling and using simul-fracs for completions of oil 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 use 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 today, all the rigs that were running are using clear fluid drilling system. And yes, that's a definite bring over from the Diamondback side. Simul-frac all of the wells we completed on a standalone basis. Besides the occasional spot crew in 2024, we're using simul-frac. And as of today, on a pro forma company, we're using all simul-frac operations. 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 we all have done acquisitions. A lot of those came with 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. 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 get space on future pipe, etcetera, maybe just how you can talk to abilities to kind of leverage that scale to improve pricing?

Yes, good question, John. We do have certainly some flexibility, particularly on the residue gas, natural gas side as well as the crude side. 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 increased ownership. So, that fits with our prior strategy of driving value through midstream but protecting ourselves commercially. I think on the gas side we've got a good amount of space on a combination of Whistler and Matterhorns. We have about 250 million a day of space on those pipes. Those were decisions made a couple of 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 of years. And that leaves some gas for other opportunities. Our friends at Energy Transfer who bought WTG, we're talking to them about some things about getting our gas out of the basin. And 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. So we heard our investors loud and clear. It's time to stop selling gas at zero and diversify our risk. And 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 follow-up question, in the prepared comments, you'll talk about, point out sort of the opportunity to implement these kinds 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, 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 sort of has legs that you all could implement across the board?

Well, the first thing we did was we had over 650 office moves in the first six days post-close. onboarded 1,000 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 that as I mentioned earlier, they've kind of just checked their egos at the door and we're really trying to learn, trying to learn the best from both sides. And obviously, some of the pace and requirements for a public company in 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 Read 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 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, call it mechanical changes, meaning going to electric fracs or the higher spec drilling rigs relative to experience and learning curves, the crews themselves. The reason I'm asking is 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 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 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. On the Diamondback side, clearly on the simul-frac plus drilling fluids. And on the Endeavor side, some of their post-completion work was really intriguing to us and we've put that into effect right away. So I would say also the consistency of the business model, not having to change the plan for every $10 move in oil price has allowed for large-scale consistent development. With a lot of crews having worked for us for three or four years now on the Halliburton side and on the rig side, 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, 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 well 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 know as we've heard from you and other companies, right. 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, market does force that upon you next year.

Yes, 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 efficiencies on the frac side, we've proven we can stand up. We stood 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 you, when we're based in Midland, we know this basin as well as anybody and we've done this before.

Yes, Roger, that's a cultural element that you'll see throughout Diamondback and that what I'm speaking to specifically is we don't ever seed ground once we've taken it. And 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 you know, supervising and leading those functions to bring back to the table the ground that we had taken so that it isn't lost. And that's a very, very important cultural element to maintaining our best-in-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 Cheng of Scotiabank. Your line is now open.

Thank you. Good morning, guys.

Good morning.

Thank you, and the team. When you combine the two companies, you're looking at a synergy target, which means that since the D&C cost is higher for one, there is an opportunity to reduce it. However, it’s also likely that they are doing certain things better than your team, and it’s important to set aside any big egos. Over the last three months, can you highlight a few key areas where they have significantly outperformed you? Additionally, can you provide estimates on the potential savings from those improvements?

Yes, I'll let Kaes 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 design. Yes.

Combined to combine look at completion designs. Right. So, we've looked across the fence line and 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 of years ago. Right. So if they're drilling better, in 2022, they were drilling better. Joe Mill Middle Spraberry wells in U.S. and we had a big study on, hey, what's Endeavor doing? And I'm sure, they did similar things looking it up. 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. So 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 than 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 in 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, a better solution to the problems. And those better solutions are always underpinned by execution and cost. And so as Kaes 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 basin 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 stays relatively close to where we are, how you balance between your desire to quickly get down to 10 billion net debt and payout ratio?

Yes, Paul, good question. I think I'll pick the second part first. I think if we're at this, in this kind of stock price environment, you're probably sticking to 50% of free cash, getting returns. And then when you go back to the third quarter, we had a couple things that impacted free cash flow for the quarter. One, we only had Endeavor count for 20 days out of the quarter. So even though the effective date of the deal was January 1st, the public numbers only account for 20 days or 21 days of Endeavor. So really the combined free cash flow of the business was a lot higher than that. But second, the Stevens family decided to sell down some of their shares post-close. And we've been pretty vocal with our shareholders that those are opportunities for us to commit to a large buyback at one time. And that's what we did with 2 million shares 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 slip a quick follow up?

Sure.

Do you have any insight into their family's plans regarding their shares? They sold 14.4 million. Are they finished, or have they suggested what their intentions are?

Yes. 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 on a consistent basis. I think the only thing that we've said publicly about the Stevens family stockholders is that over time they'd like to get down to where they're voting rights equal their ownership, which is, 25% of the business from about, 35% today.

Thank you.

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

Good morning, Travis, Kaes 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 LOE 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 realization of OpEx synergies. And if you give us a sense for that? And then Travis, going back to a point you made in your shareholder letter, you guys are still really, I guess, really optimizing, really analyzing and optimizing for 2025. And if your cost basis has already gotten better for 4Q, what does that suggest for 2025 in your mind?

Yes, I think some things have moved down as a result of combination. I think we're going to be pretty conservative on guiding OpEx, only having 20 days of a combined business. So we're going to do a lot of work refining that over the next three months. I'm confident that we'll find some things that combined will come down on the LOE side. I would say the big difference between Diamondback's cost structure and Endeavors 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. So 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 as we see three months of the combined business. And on 2025, 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 breakeven. So that work's 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 detail Kaes.

Thanks, Charles.

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

Hi, 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, for fourth quarter on production at 840 to 850 and you're basically saying we're reaffirming 800 to 825 for next year. Kind of feels like maybe that's a little conservative. I think maybe gas has been outperforming a bit here. And then also just on 2025, I think the pro forma plan has always been to be sort of flattish on oil per the macro. That kind of makes sense, but certainly sounds like you guys would be willing to kind of let that decline on your end. So just wanted to kind of verify that as 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?

Yes, listen, our base case is 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 hits 480 next year for low fours of CapEx. I think the macro is going to dictate the decision closer to January on what ends up happening. But and your comment about the BOEs. Yes, 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 BOEs probably will end up being closer to 850 versus that 800, 825.

Okay then 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 guided 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 kind of the same rate going forward?

Yes, I don't think it will be material. We'll still be in the kind of high teens, 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 2025 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? When do you start turning the dial?

Well, high level, we're really not in maintenance mode. We're at 470 to 475 oil today we got it at 480 next year. Well, that's 2% growth. It is something. That's kind of the first goalpost. I think the key point is not necessarily how or when. It's that 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 I think being cautious when things are 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 at the end of the day, the lowest cost operator should be producing the last barrel in the basin. But I think that spreadsheet math is what's gotten this industry in trouble in the past and feels like we're getting ourselves in trouble again. So I think, again, I can't hammer enough that free, free cash flow trumps CapEx at Diamondback these days.

I understand. Thank you. I have a quick question about the marketplace trends you’re observing. It's impressive to see you reaching $600 per foot. I'm curious about the additional deal synergy caps you've mentioned. Given the current backdrop of deflation in service costs and tangible items, how much of that deflation is factored into the $600 figure? Is it possible that this number could decrease further, unrelated to any additional efficiencies or deal synergies, just because of deflation? If you were to evaluate your service contracts today, what do you think the $600 figure could look like?

We're closely monitoring current market conditions. The $600 figure reflects real-time data. While some wells are performing below this benchmark, we're increasing our focus on Wolfcamp D, which is a more costly drilling option. Our portfolio includes a few Barnett Woodford wells, but predominantly, the core Wolfberry development is likely under this price. Longer lateral drilling has also been beneficial. This is a clear snapshot of the situation. As Danny noted, we operate with few long-term contracts and frequently recontract, allowing us to stay informed about service costs. Looking ahead, I don't foresee an increase in the rig count in the Permian region in the near term, which should help maintain or even lower prices, benefiting our shareholders.

Thank you. Good color Kaes.

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

Hey good morning guys. Thanks for getting me on. I want to take another shot at 2025 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-B&C 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 2026?

Yes. I mean listen, I think $625 was kind of our assumed well cost for 2025. Now we're at $600. There are some wells below that. So we'll see what happens over the next couple of months. I'm confident in this team's ability to drive out costs, but we also like to guide fairly conservatively 15 months ahead of 2025 full year. So we like to keep all 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 probably $50 million, $60 million of environmental CapEx we got to spend next year, which is kind of onetime in nature. I think the combined infrastructure budget will probably be a little higher in 2025 than it will in 2026. We like to think that the infrastructure budget eventually moves closer to 6%, 7% of total capital. And Endeavor has a midstream business that has some CapEx that should we sell the midstream assets to our JV, that CapEx would be removed. So some moving parts. I think high level, the key drivers are heading in the right direction. And I think the combined acreage position should result in lower spend above ground over time than 2025.

Awesome. I appreciate the color. Second question is going to go to Deep Blue. Here, you're targeting maybe Endeavor drop in first half of 2025, it sounds like, in the first deal, you took back $500 million of 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 what are assets.

Yes, we will see what unfolds. Our preference is to use cash to accelerate our debt reduction goals. However, we understand that we have a partnership with Deep Blue, and it’s important for them to understand that we intend to work together to enhance the value of this business. This does not imply that we will leverage a subsidiary to generate cash for the parent company. We plan to remain flexible, as we have been so far, and this partnership has already proven to be valuable within just a year. There’s still a lot of work ahead. I would say that addressing this is less of an immediate priority compared to our focus on the mineral drop-down. Many dedicated team members are actively working on this drop-down, which is a crucial development for both Diamondback and Viper.

And maybe just a third one, just on the royalties. 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-size pieces.

I think our preference is to do most of it at once. 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 drop down 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. So 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 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 question. I would now like to turn it back to Travis Stice, 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 you all have a great day.

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