Hello, and welcome to Diamondback Energy fourth quarter 2024 earnings call. At this time, all participants are on 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 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 again. I would now like to turn the conference over to Adam Lawlis, Vice President of Investor Relations. You may begin. Thank you, Tawanda. Good morning, and welcome to Diamondback Energy's fourth 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; Danny Wesson, COO; and Jere Thompson, CFO. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance of 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, and welcome everyone. I appreciate you joining this morning. I hope you find the shareholder letter a meaningful way to communicate. Also, as Adam pointed out, we've got an updated investor deck out there that we can reference during our questions this morning. Operator, if you'll please open the line for questions. Thank you. Ladies and gentlemen, as a reminder, to ask a question, please press star 11 on your telephone, then 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 Dingmann with Truist Securities. Your line is open. Morning, and Travis, congratulations on it to you, but obviously to Kaes and Jere, but especially for a fantastic career. I look forward to seeing you soon. My first question, maybe just around that. Again, another great quarter. My first question is really around the free cash flow sensitivity that you all show on Slide 13. Specifically, when looking at that, I'm just wondering. You put a comment that I noticed on the bottom of the slide suggesting now around $67 a barrel produces the same free cash flow as $76 last year. I'm just wondering, is this continued achieved through the larger scale? Is this a lot of the completion driver? I'm just wondering maybe if you could talk and discuss the drivers behind all this. Yeah, Neil, that's a new number that we're going to start to look at here. I kind of equate that number to the same thing as a dividend break even. It's basically what oil price gets you the same free cash flow per share as the prior year. And if that number is going down, capital efficiency is improving or you've done an accretive deal. And when we announced the Endeavor deal a little over a year ago, we said we'd have 10%+ free cash flow per share accretion. And here you are a year later showing that free cash flow per share is going down by $9 a barrel to equal the same number as last year. So it's going to be tough to keep moving that number down, $9 a barrel every year. But I think through a lower share count, lower cost structure, and quality inventory, that's certainly going to be the goal. No, great direction. The thing just keeps dropping. And then my second question, maybe on your D&C plans, I was wondering, can you talk about maybe, I don't know, Kaes, do you look at it completions per simul- frac crew or maybe talk? I'm just noticing the amount of completed wells, and you all talk about sort of four to five of these simul- fracs. And then secondly, noticed you all continue to complete several more wells than you drill like you did last year. Maybe just discuss that. Yeah, so on the DUC drawdown, we're drilling less wells and we're completing a combination of things. We were ahead of plan last year, so we drilled more wells than we expected, and then we also acquired a lot of DUCs with the Endeavor deal and a smaller amount with the TRP deal that closed earlier this year, so there's a pretty significant DUC drawdown planned in the CapEx budget. I would just say if we're ahead of schedule and CapEx is looking good for the year, we'll probably reduce that drawdown and drill a few more wells, particularly right now, given that putting pipe in the ground on the drilling side is almost as cheap as it's been in the last five or six years. So, I think we have flexibility in the plan, but really seeing the efficiencies come through here, right, with drilling over 400 wells with 15 or 16 rigs this year versus last year. Going into the year, we thought we were going to drill 280 wells, Diamondback standalone with 15 or 16 rigs. And then on the frac side, basically the simul-frac fleets are getting about 100 wells per fleet per year. That's kind of up from 80 a year ago, just continued efficiencies in the field. And that's partly due to the higher pump rate that we've implemented from some of the learnings from Endeavor. And I think we're still looking at ways to push that even higher. We're trying some things that might get us closer to 110 wells-120 wells per year. It's not in the plan today, but that's some upside that we could accrue to our shareholders. Perfect. Thanks. Look forward to seeing y'all. Thanks, Neil. Please stand by for our next question. Our next question comes from the line of Neil Mehta with Goldman Sachs. Your line is open. Yeah, good morning, and congratulations, Travis, and congratulations, Kaes. I think one of the takeaways, it seems, from the deck is that post the Double Eagle acquisition, there might be a pause as it relates to M&A given that it feels like you've consolidated a lot of the quality positions in the Permians. Kaes, Travis, just love your perspective on that, and if that's the case, how do you think about leaning into the share repurchase program at these valuation levels? Good morning, Neil. Thank you for your comments as well too. Yeah, we tried to articulate during the announcement of the Double Eagle trade that this was really the last opportunity in the core of the Midland Basin. And if it in fact is the last opportunity, then there's really not much left on a go-forward basis. So that's our strategy. We took advantage of probably what was among the last meaningful assets in the Midland Basin. Yeah, Neil, not saying we're never going to do another deal again, but certainly need to digest here the quality of the inventory that we have. Put this in a really good position to move more towards the other side of the capital allocation discussion, which is the share repurchases and reducing the enterprise value. And I think at these levels, it's very obvious that share repurchases is a great use of capital. At $70 oil, this business generates $20 a share of free cash flow in 2025. At current prices, that's essentially a 12.5%, 13% yield. So for us, that's cheap. And our goal is to continue to make our stock look cheap by improving per-share metrics. And I think that's what we've laid out here with the 2025 plan. Yeah. And Kaes, on that buyback program, you have a very concentrated shareholder coming out of the Endeavor transaction. How do you think about maintaining the dry powder for potential sell-downs there? And how should the market be thinking about your largest shareholder in general? Yeah, I mean, I think the market should realize that we have a long-term patient shareholder in the Stephens family that has known this basin for 45 years and is very, very comfortable with the decision they made in merging with Diamondback. This isn't a private equity investment that has to monetize for fund life. There's a lot of patience from their side. And we have conversations with them just like all of our other shareholders. And they, like our other shareholders you can see on page one of our roster, are encouraging us to lean into our buyback right now because the stock's cheap and the best use of capital is to buy back our shares. So lastly, I'd probably say that I think the market's gotten a little ahead of this lockup expirations over the coming months. And in my mind, there's a lot of other ways to reduce ownership that aren't well-telegraphed marketed deals. And that's stuff that we're thinking about. And I think we have the balance sheet capacity and the free cash flow generation, most importantly, to get creative on that front while still buying back shares in the open market. Thanks, Kaes. Thanks, Travis. Thank you. Please stand by for our next question. Our next question comes from the line of John Freeman with Raymond James. Your line is open. Yeah, good morning. And yeah, remarkable career, Travis. And congratulations, Kaes, Jere, on the well-deserved promotions. I just want to start on looking at the midstream budget, the roughly $415 million on the midstream infrastructure budget. Is there anything that's sort of, I don't know, one-time in nature related to either kind of Double Eagle or Endeavor transactions where you kind of either had to put in some infrastructure, facility upgrades, anything like that that we should be aware of? Yeah, John, I think one thing we highlighted is that there is $60 million of midstream CapEx in there, traditional midstream CapEx from the Endeavor water business, EDS. If that business were to monetize likely into our Deep Blue JV, that would reduce our CapEx burden depending on the timing of that deal. And I think second to that, we have some kind of accelerated environmental CapEx this year and probably a little bit next, but that's to the tune of $60 or $70 million of one-time this year. So a couple of things going away in the future. I'd say in general, we'd like to get that midstream or sorry, that infrastructure and other budget down to kind of 5%-7% of total capital from where it is today. And the teams, we've put it in Travis's letter, the teams have already worked on a best-in-class combined facility design that we expect will save us $1.5 million or 10% or so per facility. And that'll add up over the years as we develop the asset base. That's great. And then just a follow-up on Neil's earlier question on the DUCs. Can you just remind us just rough numbers where y'all sort of stood on DUCs, kind of pro forma for the Double Eagle transaction? Yeah, we were carrying around just a little over 200 DUCs total, 200 to 250 DUCs total pro forma of the Double Eagle transaction. The Double Eagle's coming over with about 50 WIPs that you would add to that number that we call work-in-place wells that we don't expect that will be DUCs. They'll be brought online kind of sometime between now and close. That's great. Thanks, guys. Appreciate it. Thank you. Please stand by for our next question. Our next question comes from the line of David Deckelbaum with TD Cowen. The line is open. Thanks for taking my questions, guys. And just to echo everyone's congrats to you, Travis, Kaes, and Jere. I was hoping just to step back a second just to revisit. I mean, obviously, Kaes, you made some comments about the attractiveness of the valuation of shares right now in the context of Stephens family as well. You guys have this $1.5 billion commitment on asset sales, and I think you bridge that with free cash down to almost $10 billion of net debt by the end of the year. I guess, how do you think about the flexibility of getting above that 50% return of capital this year when you appreciate where your shares are now relative to how you see valuation? Or should we be looking for that net debt trigger before kind of getting away from that 50%, at least 50% commitment? Yeah. I mean, David, I think that at least 50% commitment is going to remain regardless of the situation. Now, the execution of that, whether it's above 50% or not, I think will depend on the market conditions. And I think in Q4, for instance, we leaned in a little bit, I think, free cash flow beat even our internal expectations, but we were fully prepared to go over 50% of free cash return in Q4 given the volatility we saw in December. I'd probably lean against going to 75% or 100% in these market conditions. I don't think we're there. I think we got to get these non-core asset sales done and debt down. But we got a lot of levers to pull, and I think if we saw more volatility than we're seeing right now, we'd be leaning in. I appreciate that. And just the follow-up on the infrastructure spend, obviously a trajectory coming down with some of the synergies of facility design. You talked about the potential with the sale to Deep Blue. But just also wanted to bring up the slide around surface acreage and power generation. How do you feel or how do you think about sort of financing your own internal power needs? How sort of imminent are these needs in terms of spends to expand what you would need just to service your own wells? And when do you think we would expect to hear some announcements around some of those solutions, whether it includes third-party commercial opportunities or just incremental spend to build out for your own operations? Yeah, I'd say internally, we've spent probably on average $70 million-$100 million a year on power for the last five or six years. So I think there's $70 million or $75 million in the budget this year for our power needs. That's just poles and wires in the field. I'd kind of separate that from our power JV we're looking at. And I think there's been a lot of discussions around power in the basin. Obviously, we're short power in the basin. I think what we're trying to pull together with a large IPP is can we build a large behind-the-meter gas power plant in the basin using Diamondback gas, but also having Diamondback receive some of that power back with a hyperscaler or data center operator taking on the lion's share of that power. So that's in the works. We're still confidentially discussing it with the hyperscalers, getting feedback. I think what separates Diamondback from others in this space is our flexibility and how nimble we are and how quickly we can move to get something done, let alone how much gas we have that needs a better market. Two separate things, but we'll continue to build out power in the field because it increases uptime as well as reduces LOE. Appreciate the color, guys. Thank you. Please stand by for our next question. Our next question comes from the line of Arun Jayaram with JP Morgan Securities. Your line is open. Good morning. My first question, Travis and Kaes, I was wondering if you could talk about the asset sale divestiture program you anticipate to execute on in terms of the Double Eagle transaction. Are these going to represent primarily midstream assets, but give us a sense of what your plans are in terms of monetizations? Yeah, Arun, I think what we've been telling the market is that we think we can get these non-core asset sales done without selling operated acreage. And I think the lion's share of the value will come from a couple of our equity method investments that we list in our deck that have kind of been built out in our near monetization. And on top of that, our midstream business that we acquired from Endeavor, the EDS water business, likely has some synergies to merge into our Deep Blue JV, which is doing very, very well and winning a lot of third-party business in the basin. I think that gets you most of the way there. We've started to uncover a lot of assets from Endeavor that we acquired that are all over the country. But the biggest one is probably a sizable non-op position in the Delaware Basin. That's likely your last kind of monetization candidate to get to that $1.5 billion. Great. And maybe the follow-up. Your overall top-down capital efficiency screens quite well relative to our model and the Street's expectation in terms of the CapEx per unit of oil output, that metric you mentioned in the shareholder letter. One kind of question is that the CapEx number is accompanied by more kind of gross TILs. And did field a few questions around what are some of the implications for well productivity as we think about the 2025 program versus last year? Yeah, I think overall, well productivity is going to be as good as any year this year. We've had a couple of pretty banner years the last few years. I think a TIL number, while a lot of other peers don't even give that number, we put it out there for transparency purposes. But there's a lot of things that can move around in a TIL number, right? If one 20-well pad is completed on December 30th of last year, does it count for last year or this year? So there's some noise in that number. I think a true run rate, we kind of got into the street to 500 wells a year-ish before Double Eagle. And Double Eagle adds about 30 wells a year of development. So I think somewhere in that 525 wells-540 wells per year, assuming flat capital efficiency is kind of an apples-to-apples number. I think your other question on capital efficiency. We have posted this dollar of CapEx per BO produced. I think that's a number that we want to hold ourselves to in the future. It's going to be tough to replicate the efficiency of 2025 given the DUC drawdown. That's the mission to the team. I think there's a lot of ancillary CapEx that's going to come down to replace that. Capital efficiency is going to remain strong, particularly on a relative basis to where the market is today. Great. Thanks a lot. Thank you. Please stand by for our next question. Our next question comes from the line of Derrick Whitfield with Texas Capital. Your line is open. Good morning, Adam. Echo everyone's congrats as well. Thank you, Derek. With regard to the Double Eagle transaction, how should we think about the capital and production impacts from your agreement with Double Eagle to accelerate non-core Southern Midland Basin development? And when would that start to, or could that start to meaningfully impact your financials? Yeah, Derek, on the capital side, there's zero capital. We're getting a carry. So no impact to us. Part of the rationale for that part of the deal is we were going to have to move a few rigs down south to secure some leasehold that had lower working interest and needed some horizontal wells to maintain the leasehold. And we obviously have a good relationship with the Double Eagle guys, and they needed a place for their couple rigs to go. And so they're going to accelerate some development down there. I think the color we've given the market is that it's about $100 million of free cash flow on a consolidated basis in 2026. And I'd probably say that 50% of that is for Viper. We'll talk about it on the Viper call, but the Reagan County piece was the second largest from an acreage perspective piece of the dropdown, and so this is kind of an unmodeled upside for the dropdown that in turn benefits Diamondback through Viper's outperformance. That's great. And then regarding your commentary on unmodeled synergies, where do you see the greatest remaining opportunities now that your organizations are fully integrated? I think we've really talked a lot about synergies around the drill bit and completions and the capital synergies. I think there's some longer-dated synergies in the field and the production world as we get the teams integrated and continue to share learnings and best practices from the operating teams in the field and on the production and PDP side. Where can we see improvements, shared resources? Those things take a little longer than just converting a drilling rig or a completion crew over to a program. So we're still in the middle of all that. And the integration of the field organization really is going to be hot and heavy this year. And we're excited to. It'll be smaller things that are harder to measure, but it'll be a lot of things that will accrue, hopefully, to our LOE and OpEx budgets in future years. Thanks. That's great. Thank you. Please stand by for our next question. Our next question comes from the line of Kevin MacCurdy with Pickering Energy Partners. Your line is open. Hey, good morning. Do you have a breakdown of the 2025 CapEx plan for the legacy assets versus the CapEx for Double Eagle? Just trying to get a feel for how much lower the new legacy guide is compared to the prior commentary. Yeah, Kevin, we gave out Double Eagle $200 million of CapEx for Q2 to Q4 for 27,000 bbl a day of oil. Their assets are a little earlier, so it's kind of a 40-something like that, 1,000 BOEs a day. And so if you look at our $3.8 billion-$ 4.2 billion, you take 200 off that on each side. You're at $3.6 billion-$ 4 billion. And it kind of ties $3.6- $4 billion for the full year. And it kind of ties to where we guided Q1 of 2025, which is $900 million- $1 billion for 470 oil- 475 oil, which ironically looks a lot like Q4 of 2024. So we were kind of moving towards, given the volatility we've seen over the last quarter last year and certainly some more headlines and volatility this year to kick things off, we figured cutting capital and growing less or growing zero prior to the Double Eagle deal made a lot of sense. And so Q1 was a pretty good look at what we were planning to do prior to DE. And we certainly had to change our plans pretty quickly as that deal moved quickly. But I think in general, you're seeing a more capital-efficient plan than expectations. Great. Appreciate that detail. And as a follow-up, is there any CapEx associated with the assets that you might sell this year, both on the JV and the non-op? I think the only thing we highlighted this midstream CapEx number, which is $60 million or so. There's certainly some CapEx associated with the non-op in the Delaware, but it's not a meaningful overall number. Appreciate it. Thank you. Thank you. Please stand by for our next question. Our next question comes from the line of Paul Cheng with Scotiabank. Your line is open. Thank you. Good morning. First, congratulations to Travis and Kaes and Jere. Maybe that's on Kaes. Can you tell us that with the drawdown in DUC, how much do you estimate is the saving in CapEx on those 120, 130 DUCs? Yeah, Paul, basically on a gross basis, drilling right now is about $220 a foot. So on a net basis, your average working interest is about $200 a foot. So you're basically at $2.2 million-$2.4 million a well. So I'd say overall, it's probably about a $200 million savings this year. And I think, as I mentioned earlier in the call, the goal for the team is going to be how can we offset that in 2026 but reduce CapEx elsewhere. Okay. And just curious that the cadence of the program, I mean, if we put Double Eagle aside, should we assume that it's roughly about four rigs each quarter, the same number of wells that are coming on stream? Because when we're looking at the number of wells that you expect to bring, one would think, given your strong productivity, that production will be somewhat higher than what you got. So just curious that, is there anything we should be aware in terms of the timing of the wells or anything? No, I think we kind of said that 20 wells were brought into this year from last year. Who really knows what's going to happen at the end of this year? But I think this kind of low 500s before Double Eagle wells per year run rate is a pretty good number with 30 added wells from Double Eagle. But with a program of 500 wells a year, wells moving forward or backward across the calendar line is not something we actively think about. I see. All right, we're through. Thank you. Thanks, Paul. Thanks, Paul. Please stand by for our next question. Our next question comes from the line of Leo Mariani with ROTH. Your line is open. Hi, guys. I was hoping to dig a little bit more into the Double Eagle deal here and the synergies. You guys obviously spoke about a little bit on the call and kind of alluded to some of this in the press release. But clearly, FANG is a low-cost operator in terms of being able to drill and complete wells nicely under $600 per foot in the Midland. Do you kind of have a number for those guys in terms of what their kind of run rate was, just trying to get a sense of the well cost savings over time here? And I'm also going to probably assume that maybe your LOE is also a bit lower than theirs. So I was hoping maybe you could kind of quantify kind of the D&C and LOE numbers there to give us a sense of maybe some potential savings over time. Yeah, Leo, for a group known for their land prowess, those guys are actually pretty good operators over there at Double Eagle. They're doing a pretty good job. They were probably in the 625-650 range. But on a private deal, we're going to model it with our cost structure. And we put that new kind of well cost out last year when we announced the trade. So that's probably the biggest number we put out. I think second to that, because of the adjacencies, we're not going to have to build as much infrastructure to service those assets. And yeah, I mean, I think from a timing perspective, those guys that have been running five or six rigs, and they ran them all in the southern portion of their asset, and we're about to move four or five rigs up to the north and chew through that inventory very, very quickly. And so we decided to move on the deal because so often in this business, you've seen companies buy deals that have high decline curves and have to chase that decline curve with too much capital and too many rigs. And the outcome of that is inventory duration being shortened rather than lengthened. So we timed it well where we didn't acquire too much production and instead acquired a lot of upside that fits in well with our plan over the next 10 years. Okay. That's helpful. And just wanted to kind of ask on the capital side here. So certainly noticed that your capitalized interest has kind of been going up the last few quarters. I'm sure a lot of that's related to the Endeavor deal. But just wanted to kind of check in on that. Is the capitalized interest included when you lay out the budget for 2025 here on the capital side? Yeah. No. So capitalized interest seems to be the hot topic. I don't know if we've gone down to capitalized interest as something that's interesting in this business. But at the end of the day, we don't make the accounting rules. When you do a deal with a lot of undeveloped acreage, if you raise debt dollars to pay for it, those go in the capitalized section. For us, that runs through addition to oil and gas properties, which is not in our CapEx budget. We kind of put our CapEx budget as what it takes to run the business. But our shareholder commitments and return commitments and all the math we do on our side does include that. But from a free cash flow definition perspective, we exclude it. I think over the coming couple of years, as we pay down a significant amount of that debt, that issue will be put to rest. Thank you. Thank you. As a reminder, ladies and gentlemen, that's star 11 to ask the question. Please stand by for our next question. Our next question comes from the line of Doug Leggett with Wolfe Research. Your line is open. Hey, gentlemen. Good morning. This is actually Carlos in for Doug. And he most definitely extends his congratulations to you, Travis, Jere, and Kaes. Look, guys, what we're trying to figure out is we talk about a decade of inventory at the current pace, and that's presumably associated to your highest return screen. What would that look like if we applied the current strip to screen returns? Would that number change? And how much so? Thanks. Yeah. I think the gold standard in the industry right now is sub-40 break even. And that's what we've been focused on and saying the decade reference. Obviously, inventory expands significantly as commodity prices go up. I think for us, that number's put in our deck on Slide 12. We show kind of the $50 break even. Now, that's a 10% rate of return at $50 a barrel, right? We're not going to be wanting to drill that many wells in that situation. Instead, we'd like to have the balance sheet strength to be buying back shares in that situation. But I think from an overall strategy perspective, the inventory's there. It's just about at what time do you have to prosecute that inventory? We've tried to position ourselves to be the last person to have to drill the lower returning inventory, but also have the lowest cost structure to be able to do it. Gotcha. That's very helpful. And not to be the dead horse here, but in terms of your DUCs and the capital associated with that, how much of that capital benefit or at what rate do you expect that capital to come back throughout 2026? What's the cadence associated with the capital benefit reverting back to normal levels? It's pretty level loaded. We have a very good forward visibility into what we're completing and what we're drilling. I think we also went into this year running 18 or 19 rigs and realized that we were going to have a pretty sizable DUC balance we could draw down, so we're going to be down at kind of 15 rigs here in the next couple of weeks, and we'll probably keep that pace for most of the year. I think, as mentioned earlier, if things are going well on the year and we're towards the lower half of guidance, we'll probably drill 30- 50 more wells and keep a relatively high DUC balance. We really like that because it gives us operational flexibility, particularly with the size of these pads and the size of the development. So it's good to have somewhere to go when things go south. That DUC balance allows us to do that. Awesome. Thank you, guys, and congrats again. Thanks. Please stand by for our next question. Our next question comes from the line of Kalei Akamine with Bank of America. Your line is open. Hey, good morning, guys. On Slide 28, you're breaking out surface acres in the Permian for the first time. Kind of suggests that you're getting close to securing maybe the Permian's first data center deal. How should we think about how the financial benefits are going to flow back? And I'm thinking in terms of land sale revenues. Will there be maybe a fixed price for gas? Could you even be paid in kind or through discounted power prices? Yeah. Good questions. I think the land payment, in my mind, is the least important of all of the payments given the size of the land needed. It's not a huge piece of property, but it's about 1,000 acres, and you can buy a lot of surface out here in the Permian cheap. Fortunately, we have a lot of it, but I think the benefits to us would be participation from an equity perspective in the plant and on the power side, and also contributing all of the gas needed for the plant. The debate is on between us and our partners on how we want to structure that. You could look at things on a fixed price basis. You could look at a collar. You could look at an index. I think what we're trying to do is kind of be more flexible than most here because in our situation, we're looking to take back a good amount of power ourselves, which I think will maintain our best-in-class LOE structure, particularly as power gets more scarce in the basin. A lot of moving parts, but we're very actively working on it today. I think it could be exciting for the Permian and exciting for Diamondback shareholders. I appreciate that, color. For my next question, I'm thinking about the Endeavor share overhang. Kind of going back to Neil's question. Post-dropdown, you guys are a lot longer on the stock. Do you think there's any opportunities to maybe creatively swap VNOM shares for the seller shares in FANG? Yeah. Probably not something I can comment on. But I think from Diamondback's perspective, is happy with our ownership in Viper. I think the stock's had a good run. I think the world's kind of waking up to the value of minerals. And Diamondback has now a $7.5 billion-$8 billion dollar stake in Viper that I think is truly unique. But we structured that deal with as much equity as we did because we look at debt on a net debt on a consolidated basis. And in our mind, it didn't make sense to lever up Viper in exchange for after-tax debt dollars at the parent. So we did a highly equitized trade. But I think from the Diamondback side, it gets us back over 50% ownership of Viper and leaves Viper underlevered to continue to consolidate its market because I think that mineral consolidation will be pretty significant over the coming years relative to upstream. Thanks, guys. Travis Stice, congrats to you guys both. Thank you. Thank you. Ladies and gentlemen, I'm sure no further questions in the queue. I would now like to turn the call back over to CEO Travis Stice for closing remarks. Thanks, everyone, for listening in this morning. Appreciate the attention. If you've got any follow-up questions, please reach out to the numbers provided. Thanks again. Y'all have a great day. Ladies and gentlemen, that concludes today's conference call. Thank you for your participation. You may now disconnect.