Good day, and thank you for standing by. Welcome to the Diamondback Energy Third Quarter 2023 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 one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Adam Lawlis, VP of Investor Relations. Please go ahead. Thank you, Steven. Good morning, and welcome to Diamondback Energy's third quarter 2023 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, and good morning to everyone. As Adam mentioned, we released a shareholder letter last night that contains much of the narrative we hope to cover again this morning. So with that, we'll just open the lines up for questions. Operator? All right, thank you. At this time, we will conduct the question and answer session. As a reminder, to ask a question, you will need to press star one on your telephone and wait for your name to be announced. To withdraw your question, please press star and one again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Neal Dingmann of Truist Securities. Please go ahead. Morning, Travis and team. Thanks for the time and another nice quarter. Travis, my first question is on capital allocation, specifically. Several quarters ago, you, you suggested you all would return to more of a production growth type model, I'd call it, and I think you mentioned, you know, when the macro fundamentals supported. I'm just wondering, do you believe we're close to that scenario? And wondering, you know, why do you believe the continued high free cash flow payout is warranted? Yeah, Neil, that's a good question. Look, the world is certainly in a mess right now across any number of fronts, all of which, you know, could potentially, you know, move the markets both positively and negatively, both with a supply disruption or even a demand disruption as well, too. So obviously, we can't control any of those items. Again, we simply respond to our shareholders that own our company, that right now, you know, return a shareholder model versus a growth model. As we've intimated, our plans as we look forward into next year, you know, again, look for real efficient capital allocation, and as an output of that capital allocation, we expect, you know, low single-digit type volume growth. Again, not as an input, but what results from an efficient capital allocation program. Got it. That makes sense in this environment. And then secondly, on your development, couldn't help but notice the new slides on Slides 10 and Slides 11 highlighting the efficient execution and then the differentiated development. My question is, does most of your remaining Midland inventory lend to the 24 average, wells per project size that you mentioned? And then I'm just wondering, could you speak to where the largest cost efficiencies continue to come from on these projects? Sure. On the development strategy over time slide, which is Slide 11, for those of you that are looking at it online, you know, we tried to demonstrate our evolution from 2015 to today, and we said average wells per project is about 24 wells. I think generally that's that applies across our Midland Basin. However, not all deposits are equal in terms of the way the shales were laid down across the Midland Basin. So there will be areas where we can do slightly more than 24 wells, and then areas also where we'll do slightly less than 24 wells, which usually translates to, you know, one or two wells less per shale interval. So again, it's a general representation showing the development over time, but that's a good, that's a good summary. And then, let's see, what was your second question? Just on the cost. I know Kaes and I have talked about it. I mean, is it just on... You know, I know you have lower casing and just different, you know, sort of raw material costs, but is there other, you know, areas in that larger projects that are causing these, you know, when you see that well productivity chart on the right, you know, sort of what's driving the lower cost efficiencies there? Yeah, certainly. Again, referencing back to Slide 10, we've laid out the biggest elements of cost savings, cost components and the reductions over time. And it's, again, as you pointed out, it's casing to down the, you know, 20% or so. You know, it's, it's really, as you look into it, look into next year, we, we feel more of a kind of a steady state run rate on our costs. There'll be some puts and takes on both sides of the equation. Kaes, do you want to add anything to that? Yeah, I mean, I think the biggest benefit to the large-scale development, Neil, is, you know, the consistency of running the rigs, you know, in, in the same spot for a long period of time. But, you know, on the frack side is where we save the most money from a capital efficiency perspective, because we're doing, you know, in some cases, two simulfrac crews on the same site at the same time. So you're saving essentially, you know, $250,000-$300,000 a well from- ... simulfrac, and now we have, you know, two of those fleets or E-fleets that run off lean gas that save kind of another, you know, $200,000-$250,000 a well. So, and this large scale development, you know, kind of ties to the longer cycle nature of our business, and that also means, you know, we don't want to change the plan, you know, every move in oil price. And so we've had a consistent plan here for a few years now, and the output of that is, you know, consistent results on the well, the well productivity per foot. Thank you, both. Thanks, Neil. Thank you. One moment for our next question. Our next question comes from the line of Neil Mehta of Goldman Sachs and Company. Your line is open. Yeah. Thanks, guys, and appreciate the helpful letter and the time today. Travis, why don't we start on return of capital as a topic? You talk about this in the letter of you wanting to err on the side of caution as it relates to buying back stock to avoid repurchasing procyclically, and as a result, leaned into the variable dividend in the last quarter. Can you talk about the way that you're approaching this and how that should inform the way we think about, you know, the split between buybacks and dividends going forward? Sure. Neil, our main focus remains a sustainable and growing base dividend that we think represents the most efficient way for our shareholders to understand, you know, what our shareholder return program looks like. Following that is the share repurchase program, which we laid out, what we've done in the third quarter and so far in the fourth quarter. And then we honor our commitment to return at least 75% of our free cash flow by making our shareholders whole in the form of a variable, which we've seen, we did this year. I think the most important thing is when you talk about share repurchases, is that you need to have some discipline around that, because in my experience, lack of discipline leads to chasing stock repurchases all the way to the top of the cycle. So we, like most of our capital allocation decisions, actually, like all of our capital allocation decisions, we hold ourselves accountable to some form of rigorous analytics. And in this Kaes, you know, we continue to run a NAV value at mid-cycle oil prices, which is $60 oil, and calculate oil price or calculate stock price. And depending on where our stock is trading relative to that calculation, we either buy more of, and the further dislocation we get from that, we buy, you know, we increase, or, if not, then we pivot to a share revert- or to a variable dividend like we, like we did this time around. So, again, it's base dividends, it's share repurchases, with a degree of caution in a procyclical environment, and then honoring our commitment to the form of a variable dividend. Okay, that's really helpful. The follow-up is just on non-core asset sales. You've done a good job of exceeding your target. Can you talk a little bit about the Deep Blue Midland Basin JV? And then not only in terms of the proceeds, but what does it mean for your go-forward cost structure, as we think about modeling the impacts through 2024? Yeah, good, good question, Neil. You know, the Deep Blue JV was a very big deal for us. You know, it took a long time to pull together. You know, we had built a significant amount of midstream infrastructure over the years and spent a lot of capital doing it. And, you know, we felt it was an opportune time to, you know, monetize that in the hands of, you know, who we see as, you know, operational experts in Deep Blue and the Five Point team. You know, I think they have already proven to have commercial success with third parties, where, you know, maybe if you had a Diamondback business card, you weren't gonna have the same type of commercial success. You know, I think that sector is certainly ripe for consolidation as well, and I think, you know, they're the experts that can get that done. So that's kind of why we retained the 30% equity interest in the business. We're very confident that they're gonna be able to grow the business and generate a good return for our shareholders. You know, outside of the $500 million of proceeds we got in, which is the big winner, you know, there will be some impacts to our cost structure. I would say generally, LOE is gonna be up about 8%-10% versus prior as a company. And then, you know, we'll have a lot less midstream CapEx, as we don't have very many operated midstream assets, and that'll be kind of canceled out by slightly higher well costs, you know, $10-$20 a foot, depending on the area, as we buy water from the JV. So, you know, all in all, we sold the business for a much higher multiple than we trade, and we're excited to see what they can do in terms of creating value for the 30% that we're retaining. Thanks, team. Thanks, Neil. All right. Thank you. One moment for our next question. Our next question comes from the line of David Deckelbaum of TD Cowen. Your line is now open. Morning, Travis and Kaes team, Danny. Thanks for taking my questions. Travis, I was curious if you could talk a little bit more, you know, about the remarks in the shareholder letter on being an acquirer, an exploiter, and just maybe putting in context sort of how robust you think that opportunity set is right now, just given the cycles in the business and some of the PE cycles that have gone through the Permian right now? Yeah, David, and I appreciate you referencing the shareholder letter. I tried to address that head-on. I think just in a more macro sense, we'll always do what's right for our shareholders. I mean, we've got now over a decade of what I think is demonstrating doing the right thing for our shareholders. But, we remain laser focused on delivering on our business plan. And, and you're right, we have built this company through an acquire and exploit strategy. But, but I think, you know, as investors are really starting to understand, we have such a high quality inventory right now, that the bar is pretty high for additional opportunities to add to, add to our inventory that meets those, the criteria that we laid out in our shareholder letter with sound industrial logic, and being able to compete for capital right away, and then, and then being accretive on those financial measures that are so important to all of us. So, you know, there has been a lot of private equity roll through, and I think, based on lack of our name on those, it just tells you where we view those assets relative to our inventory. Like I keep, like I said, I'm really pleased at the quality of our inventory, and I think we're executing on that in a flawless manner. Appreciate that. And then, you know, maybe just for Kaes, you know, the DUC backlog is built, I guess, up to 150 by the end of the year. I think you guys talked about, you know, low single-digit organic oil growth for next year. I just wanted to confirm, like, if that oil growth is reflecting the benefit of the increased royalty interest through the Viper acquisition rather, or if that's, you know, how we should be thinking about that growth rate. And then, you know, just in concert with that, the DUC backlog, you know, is it... Should we think about that flexibility, especially in this pricing environment, just based on frack crew availability, or is that really just like a capital allocation decision? Yeah, I'll hit the organic growth comment first. You know, certainly, excluding the Viper deal, we expect it to grow organically in 2024. I think, you know, the Viper deal provides a little bit of a jump start here in Q4, but I think the team's expecting to grow off that number, you know, to steady state throughout the next year, just due to the quality of what we've got in front of us. You know, on the DUC side, you know, we were kind of operating pretty close to the rigs on the completion crews and, you know, really needed some flexibility here. The drilling team's done a really good job this year, getting ahead of plan, drilling more wells than expected sooner. You know, with these large pads and large projects, you know, you really want to have the flexibility to be able to go somewhere if something, you know, something bad happens, and that DUC backlog allows that. So I think, you know, 150 plus or minus 10 wells or 20 wells, either way, is a pretty good number for our run rate. And, you know, we've kind of set the stage for a world where we run, you know, four of these simulfrac crews consistently throughout the year. They each do about 80 wells a year, and, you know, in our mind, that's kind of the most capital efficient development plan we can imagine here. That DUC backlog just lets Danny sleep a little better at night and, you know, allows for some flexibility heading into next year. Good deal. Thanks for the responses. Thanks, David. All right. Thank you. One moment for our next question. Next question comes from the line of Scott Hanold of RBC Capital Markets. Your line is now open. Yeah, thanks. If I could, you know, go back to the M&A topic a little bit differently. You know, when you know, Kaes, Travis, when you step back and think about, like, where Diamondback's inventory depth is and to be a long-term, successful, large-scale play in the Midland, like, do you think that, you know, more large-scale M&A is necessary over time? And just remind us, like, you know, where you think your inventory life is, and where ideally would you like it to be? Yeah, I mean, I don't think it's necessary, Scott. I think we've positioned the business through both large scale and small scale M&A. It's just kind of been in our DNA for the last 10 years. You know, I kind of go back to thinking about what positions in North American shale or in the Midland Basin would we envy? And there are very few, particularly with where we sit today and the amount of deals we've done over the years. So I think it's a fortunate spot to be in with the inventory duration and depth that we have relative to, you know, what's out there. I just think, you know, Travis's comment is really about knowing who you are, and this company has been a acquire and exploit company that's been able to execute on acquiring and exploiting assets through our low-cost structure. And, you know, generally, you know, we have had a philosophy that the low-cost operator in a commodity-based business wins. And, you know, our cost structure is what has created this business to be as big as it is today. Travis, you want to add anything to that? I think that makes sense. You know, we've talked about the high bar for entry, you know, into the Diamondback portfolio, and it's just, you know, that's just how we view it. And we're very, you know, we're very proud of the inventory we have. And I think what goes along with that durable inventory is how we convert that inventory into cash flow. And again, you've seen this quarter, you know, flawless execution from our teams in converting rock into cash flow. And that's, you know, our cost structure is enviable, our execution prowess is unmatched, and that makes a big difference when you talk about a profitable oil and gas company like Diamondback. ... Yeah, and just as part of that was the inventory life kind of conversation, more of like where you think you're at now, and what do you think is ideal? Yeah, I mean, I think I kind of said this, that we put our next five years up with anybody in North America, and I still stand by that. I think we have, you know, another solid five or ten years beyond that. You know, it's very logical that at some point, you know, you're gonna have to move down the quality of your inventory. We don't see that in the forward plan today, but if we retain our cost structure and our ability to drill wells $1 million or $1.5 million or $2 million cheaper, well, as the shale cost curve goes up, we continue to stay at the low end of that cost curve. It's kind of been our mantra for 10 years now, and we started with, you know, 50,000 acres, and now we're at 550 acres. And, you know, that culture and mantra has not changed, and I think that sets us up well for a world, you know, where assets are getting more and more sparse. Got it, understood. And if I could follow up on, you know, on our conversation we had last night, just on the shareholder returns and, you know, stock buybacks. And, you know, I thought it was an interesting conversation we had on, you know, just where FANG's intrinsic value, you know, is now and, you know, the opportunity to grow that over time. And so, like, when you step back and, you know, think about the current oil market, obviously, we're in a little bit more heightened oil price versus your intrinsic point. Like, as you see yourself progressing over the next years, I mean, does it seem to make sense that, you know, buying it, you know, buying back stock at higher prices in this heightened market, you know, relative to what you did in the past, you know, still make, you know, sense from a value return standpoint? Yeah, it's really all about, all about value. And, you know, like we talked about last night, if you run your business conservatively from an oil price perspective and accrete value quarterly, you know, at $75, $80, $85 dollar crude, you know, if you're actually building equity value on a conservative basis, right? I kind of said last night to you that I think generally, if you run a quarter like last quarter versus the $60 base Kaes, you know, you're basically building $3-$4 a share of extra intrinsic value. And I think that's what we've done here over the last couple of years in this, you know, upcycle. And, you know, as Travis mentioned, you know, we want to be conservative when buying back stock. You know, we think capital is precious, and capital discipline not just applies in the field, but it applies to returning capital to shareholders. That's why we've had this flexible return of capital program since we put it in place, you know, two and a half years ago. Thank you. Thanks, Scott. All right, thank you, for your question. One moment for our next. Our next question comes from the line of Roger Read of Wells Fargo Securities. Your line is now open. Yeah, thanks. Good morning. I think I'll skip the obligatory share repo versus variable dividend question for a moment and just go back to the operational aspect. So can you give us an idea, as you mentioned, the sort of accreting value into the shares through operations, what we should be looking at over the next, say, you know, 24 months-36 months, for what else you can do operationally that'll accrete value? And thinking that we're not gonna have, you know, some of the asset sales that have been going on, that have certainly helped on the sort of cash flow generation aspects. Yeah, that's a good question, Roger. You know, I think it's interesting. You know, we put a slide in Slide 10 about operational track record and prowess. And, you know, I think we sat in this room two or three years ago saying, "Hey, the drilling guys, they're near the asymptotic curve of drilling these wells." Well, if you look at the top left of that chart, you know, they're still taking days out of, you know, the average well on a much bigger program, right? These guys are drilling 280 wells in the Midland Basin, you know, two, three, four days faster than they were even two years ago. And, you know, the culture that we built accretes that value to our shareholders. It's not something we model, but it certainly comes our way. So in the field, I think that's part of what is coming our way. I also think, you know, generally, we've tested some other zones in the Midland Basin that look very, very good. We've got a couple Upper Spraberry tests in the northern Midland Basin that look very good relative to, you know, our Middle Spraberry Jo Mill developments. We're excited about that. I think the Wolfcamp D in the Midland Basin is starting to become a primary development zone in some of the basin. And certainly there's a lot of excitement about deeper zones, you know, in the Midland Basin as well, the Barnett and the Woodford, that we're on to testing. So I think, you know, the Midland Basin, the stack play and the amount of oil in place just provides a lot of opportunity for, you know, future value to accrete to our shareholders that they don't know about today. Travis, you want to add anything to that? Yeah, you know, Roger, if you backcast 10 years ago when we first started this, we're still drilling a few, you know, vertical wells. And, you know, I put in the letter that we released last night, just a couple of data points on a 7,500-foot lateral well, which has a total depth, total measured depth of about what we were drilling vertically when we started. But drilling, you know, we drilled those 7,500-foot lateral wells in under four days. And when we started, you know, we were drilling it, sometimes it'd take us over 24 days, 25 days to get down to that same measured depth vertically. And so, you know, probably the most repeated question that we get is: What is the secret sauce? What is the magic that Diamondback does that allows execution quarter-over-quarter to just far exceed the competition? ... You know, it's, it's essentially, you know, the same rock and the same tools, but the culture that we've built here at this company, with that laser focus on the conversion process of rock into cash flow, you know, is felt by every employee in the company. And when you have everyone leaning in the same direction on cost and efficiency, as long as we can continue to give them good rock, they're gonna, they're gonna generate the outstanding results that we're known for. So I know that's a little bit of motherhood and apple pie, but it's, you know, I'm really proud of the organization for, you know, through all the cycles we've been through over the last 10 years, what hasn't changed is, you know, an unrelenting focus on delivering, you know, best-in-class execution, highest margin barrels at the lowest cost. I appreciate that. I'm not going to get in between motherhood and apple pie here in the U.S., so, I'll turn it back. Thanks. Thanks, Roger. Thank you. One moment for our next question. All right, our next question comes from the line of Derek Whitfield of Stifel. Please go ahead. Good morning, all, and thanks for all the incremental disclosures this quarter. Thanks, Derek. Thanks, Derek. Building on an earlier question, how should we think about 2024 maintenance capital run rate, assuming the benefit of deflation and your current operational efficiencies? That's a good question, Derek. I, I'd probably say that maintenance CapEx would be, you know, $100 million-$200 million cheaper, you know, 30 wells, maybe. Danny? Yeah, I think, you know, we're kind of looking at it like our maintenance—our case for 2024 is kind of a maintenance activity case, so flat activity outputs a little bit of growth. But, you know, if we were to try and maintain a flat production profile, you'd probably be in the line of 20 wells-30 less wells in the year. You know, Derek, while you're on that topic of maintenance CapEx, I might just point you to slide seven. You know, we've had that slide in there a couple of times, but it shows maintenance CapEx, which Danny just defined, as kind of holding, you know, the fourth quarter production flat for next year. I just want to show you what our break-even prices are on that slide, $32 a barrel to cover maintenance CapEx, you know, $40 a barrel to cover our base dividend. That kind of goes back to my cost and execution comments that, that ultimately translate into a very protected business model, even at low, at low commodity prices. That's great. And as my follow-up, with respect to your non-core asset sales, how should we think about the market value of what's being retained by Diamondback and how that will be realized over time now that you've exceeded your disposal target? Yeah, good question, Derek. You know, we do lay out some of our remaining JVs that we have on Slide 26. I think some of those logically are monetized at some point in the coming years. I don't think we're in a huge rush to do so, but in most cases, you know, we're kind of a non-op partner to these JVs that do have a ton of value, just not something that we can, you know, commit to monetizing today. Well done, guys. Thanks for your time. Thanks, Derek. Thanks, Derek. All right, thank you. One moment for our next question. Our next question comes from the line of Kevin McCurdy of Pickering Energy Partners. Your line is now open. Hey, good morning. I appreciate the commentary on industry consolidation. Digging into your cost structure comments a little bit, now that you've had Firebird and Lario and in house for almost a year, can you comment on the level of cost synergies you've created in those transactions? Or maybe just share with us your analysis of Diamondback's costs versus peers. I'm just trying to get a sense of what kind of uplift assets get when they're incorporated into Diamondback in your cost structure. Yeah, I mean, that's a good question, Kevin. You know, I hate to say it, but we didn't win those deals because we were buddies and bid less than other people. So I think we bid the most, but we bid the most because we could underwrite it with the lowest cost, right? At the time, you know, I think some of the Lario well costs were near, you know, $8, $8.5, $9.5 million for a 10,000-foot lateral, and we were drilling them at, you know, $6.5-$7. And so that's kind of been our mantra for a long time. I would just say generally, you know, if you split the two deals up, Lario was an execution deal because we knew we could drill those units cheaper and execute on, you know, large-scale development. I would say, you know, Firebird is more of a technical deal. You know, we had a technical view of that particular area that the basin could move further west and particularly in the northern portion, there'd be some multi-zone development that looks really good. I think we were conservative on the multi-zone potential of the central block and now feel a little more confident about the Wolfcamp A and Lower Spraberry maybe being wine racked in that area. Also, you know, with the benefit of that block being so contiguous, you know, we're able to, you know, bring a 15,000-foot lateral manufacturing process to that area. So you know, we underwrite these deals at our cost structure, which, you know, if you look at our cost structure versus others, that means we should get more of those properties at the same rate of return because of our ability to execute. Great. That's, that's the only one for me. Appreciate taking my question. Great questions, Kevin. All right. Thank you. One moment for our next question. Our next question comes from the line of Jeoffrey Lambujon of TPH and Company. Your line is now open. Good morning, everyone, and thanks for taking my questions. Thanks, Jeff. My first one is on the, the ops and capital allocation side. If you can just speak to any more detail on next year's plan in terms of where you might focus within the Midland Basin, both in terms of geography, but also maybe just less active zones in terms of industry activity that you may be testing more. And if you could speak maybe a bit more onto some of that lateral end commentary in terms of how that might evolve over the near-term program, that would be helpful as well. Yeah, you know, Jeff, with these longer cycle projects, you know, we have a pretty good view of what the projects look like coming up here in 2024. You know, I'd say generally, you know, we're gonna be in the range of 11,000 feet average lateral length, probably maybe even a little bit more than that. I would say, you know, it's also a very heavy Martin County development year for us, which is great. You know, large scale multi-zone development and some of the best undeveloped resource, you know, remaining in the Midland Basin. I'd say, you know, from a testing perspective, some more Wolfcamp D probably making it into the plan and a lot more Upper Spraberry making it into the plan. You know, we kind of have a couple of really good tests and, you know, part of our culture is when something works, we implement it very, very quickly, and that's how we kind of see the shallower development, you know, picking up the pace in the northern Midland Basin, particularly that Northwest Martin County area, that we feel really good about for adding a new zone. Okay, great. Then maybe just a housekeeping type question on the non-core asset sale side, particularly on the upstream. I think a few people noted now just how you're exceeding or you've already exceeded the target before year-end here, and it makes sense there's no need to go out and do more right away. But just wondering if you could speak to potential opportunities, maybe in terms of longer dated inventory, that someone else might find more valuable today, or just how you think about the opportunities that are near? Yeah, a good question. That ties to something I didn't answer in your last question. You know, the number of wells in the Midland Basin will be kind of 85%-90% of total capital. So the Delaware Basin still, you know, will be a small percentage of total capital. And I think, you know, if I'm getting what your question is, it's, you know, what, where does the Delaware Basin sit in the portfolio? You know, I think, I think for us, you know, certainly we've starved that area of capital a little bit here in the last few years. I think it provides a lot of cash flow and a lot of production, which is, you know, beneficial to us today. But, you know, as you've seen over the course of the year, it certainly seems like inventory is coming at a premium. And, you know, there may come a time where someone really wants that Delaware position of ours or portions of it, but we're not gonna sell it for, you know, a song at PV- 15, right? PDP. So, I think we're gonna hold it for now, and if someone wants to pay for upside and a reasonable number versus where we trade, we'll take a look at it. Perfect. Thank you. Thanks, Jeff. Thank you. One moment for our next question. Our next question comes from the line of Nitin Kumar of Mizuho. Your line is now open. Hi, good morning, guys, and thanks for taking my question. Travis, I wanna start on slide 11. You've been espousing the co-development approach for some time, and you show pretty, you know, pretty solid results and consistent results since 2020. Just curious, one of your, I guess, peers in the basin talked about increasing recoveries by 20%, through the use of technology. You know, you guys are at the cutting edge yourself, so I'm curious, are you seeing anything out there that can improve recovery factors by that kind of magnitude? Nitin, we keep our finger on the pulse of a lot of emerging technologies. We focus, you know, our internal expertise on improving recovery. That's not something that's on our radar screen that we're aware of today, but that's not to say that the potential is not there as you look forward in the future. There's a lot of smart guys in our industry. We have a ton of smart guys inside Diamondback, and whether that technology is developed internally or externally, it's widely communicated and quickly followed, especially with that kind of result. So, you know, we're focused on improving recovery, and I know our peers are doing the same. That's not a today number for sure, though. I guess my follow-up would be, you know, if you are a fast, fast follower, you know, you've talked about how volume is an output of your program, your capital allocation framework. In an event that you could improve recoveries that way, would you keep activity flat, or do you expect to reduce CapEx and just maintain that volume growth to be in the low single digits? Yeah, I mean, I think generally, you know, that would be a great problem to have. It really ties to this, you know, can you run a simulfrac program consistently on that position and those projects and those pads? You know, it kind of goes, all goes back to this longer cycle nature of the shale business model. And, you know, I think, you know, we feel really good about four simulfrac crews running consistently right now, Nitin, and have the infrastructure to do that. And, you know, if growth exceeded expectations, you know, that would be a good problem to have. ... Great, thanks. That's it for me, guys. All right, thank you. One moment for our next question. The next question comes from the line of Charles Meade of Johnson Rice. Your line is now open. Good morning, Travis, Kaes, and Danny. I wanna ask one more question, but maybe from a different angle on the A&D outlook. Kaes, I think it was in your prepared comments or maybe earlier Q&A, that there's very few positions out there that you envy. And so, that makes sense that you guys your bar is high. But from my seat, it also looks like if you look at the other side of the equation, it looks like there's not a lot of positions you wanna buy, but there's also fewer potential buyers out there, particularly for some of these large private positions. So, how does the... I guess, do you agree that there's fewer credible buyers for some of these big packages that may still be out there? And more broadly, how is the, you know, how's the kind of the lineup shifting? Is your, you know, active in data rooms and in processes, you know, buyers versus sellers? Yeah, that's an interesting observation, Charles. You know, it's certainly not lost on us. You know, you've had a couple of very large buyers, you know, do a couple deals in the basin and out of the basin. They can kind of do whatever they want, it seems like. But I would just say generally, you know, industry consolidation has happened. It's continuing to happen. I think, you know, a lot of the privates are gone, as you mentioned, to logical acquirers. I would just say that there may be less buyers of assets, but they're all very well-funded, you know, good operators, big balance sheets, and competitive. You know, I think we just have to stick to our guns and our underwriting philosophy, which is, you know, our cost structure, our rates of return internally, you know, our hurdles for commodity price, and usually, that has resulted in, you know, more assets coming to Diamondback because we can underwrite, you know, wells drilled at $1 million-$2 million cheaper. We can run LOE $1 cheaper, and that's the kind of stuff that accretes to our shareholders. Got it. Thanks for that. That's it for me. Thanks, Charles. Thanks, Charles. Thank you. One moment for our next question. Our next question comes from the line of Arun Jayaram of JP Morgan Securities. Your line is now open. Yeah, good morning, gentlemen. I wanted to keep on the A&D theme. You know, when we are assessing the potential of a large private or one of these unicorns to potentially, you know, consolidate, does it just come back to price, or is there something, do you think, that they think about in terms of the independent versus major oil business model that could be advantageous to a company with like Diamondback, who's in Midland and again, you know, boasts one of the lowest cost structures in the industry? Yeah, Arun, you know, we don't spend a lot of time thinking about what sellers think. You know, we just think about what is the best opportunity available for our shareholders and creating shareholder value for our shareholders. You know, at the end of the day, you know, I think Diamondback, you know, hand on heart, has one of the best positions remaining in North America and the best cost structure, and that should be a very winning combination for our shareholders for a long time here. Understood. I wanna maybe switch gears and just talk about the DUC, efficiency gains. You know, really surprised to see, you know, this year, the drilling efficiency gains. Seems like the drilling efficiency gains are outpacing maybe what we're seeing on the completion side. Are you guys recalibrating the, call it, the rig to frac crew ratio? But give us a sense of, maybe what you're doing on the drilling side for these efficiency gains, and maybe help us recalibrate what that drilling to simulfrac crew ratio looks like today. Yeah, it's interesting. We really haven't thought about the rig to crew ratio in a long time because it's just changed so much. You know, I think we've moved to a world where we know how many wells we need to drill and how many wells we need to complete in a year to hit, to hit numbers. And, you know, the drilling side, you know, maybe a year ago, that was 15 rigs or 16 rigs for a full year, and now this year and upcoming, it looks more like 14 rigs-15 rigs. So, you know, the amount of work that our planning team does on the plan and how we're doing relative to plan is pretty astounding, and how far ahead they are on these pads and when we need to pick up a rig and when we need to drop it. We're really kind of just targeting, can we keep those simulfrac crews busy consistently? And I would guess, you know, I guess the number is kind of in that high threes, almost four rigs to one simulfrac crew today. Yeah, Arun, I think that, you know, that, you know, like Kaes said, our, our goal is to keep, you know, the drilling program ahead of the simulfrac fleets and just keep the simulfrac fleets moving and efficient, just like we wanna keep rigs moving from pad to pad without waiting on no pad construction or whatever. So we kind of see them as two different, you know, programs altogether, knowing that they're very dependent on each other. You know, I think the drilling and completion teams both this year have really done an excellent job of leaning in and, you know, pushing the machine to the limits and finding the little pieces of efficiency gains they can pick up. And, you know, we continue, as we've always done, to tinker and find better ways to execute our development strategy and build a better mousetrap. And, you know, when we find different ways to design these wells and execute that, we'll lean into it and continue to chase that, you know, that efficiency line. Great. Thanks a lot. Thanks, Arun. Thanks, Arun. Great. Thank you. One moment for our next question. The next question comes from the line of Scott Gruber of Citigroup. Your line is now open. Yes, good morning, and congrats on another good quarter. I want to follow up on Arun- Thanks, Scott. Thanks. I want to follow up on Arun's question, just on the activity set in the next year, and get some more clarity on the plan for the DUCs. So it sounds like you're going to be running, you know, the 14 rigs or 15 rigs. Will you end up drilling, you know, 300 wells or so wells by running 14 rigs or 15 rigs? Or will the base plan for next year, you know, contemplate a drawdown of some of those excess DUCs? I don't think we're planning on drawing any down, you know, absent any, you know, in the field issues. You know, I think generally, you know, we feel a lot better at this level of DUCs for the size of projects that we have ahead of us. You know, the earlier this year, we were getting pretty close. You know, the rigs or the frac crews were getting pretty close to the rigs getting off location. And, you know, a 20-well pad or 24-well pad, or however you want to break it up, you know, you have to have all 24 wells done before you can bring, on the drilling side, before you can bring the frac crew in, or at least that's how we do it. You know, that's why that kind of 150 number we mentioned feels like a much more balanced number going forward. I got you. So the inventory count is, under normal conditions, is just going up. I got it. Yeah, this feels like a good, good inventory number. Again, going back, we're not—these aren't the days of, you know, two well pads, where if something bad happens, you can pull off a pad and go somewhere else. You know, these, these are long cycle, mini. You know, Danny likes to call them mini offshore projects, given the amount of dollars that go into a project before first oil comes online. That makes sense. And a good detail on, you know, the, the cost trends across the, the various, buckets on, on slide 10. You know, as you think about, you know, going through RFP season for, you know, various services, I know you have some longer term contracts in place, but do you think you'll see any continued deflation across any of the major buckets as you go into 2024, or are those starting to to stabilize now? Yeah, I think we think, you know, it's kind of stabilizing right now. You know, and then for us, there really is no RFP season, right? RFP season is every day at Diamondback. If something's cheaper and we can do something cheaper or replace something with something cheaper, it's going to happen right away. It's not going to wait, you know, for next season or for the summer. It's going to happen now. So it's a constant RFP season here, and these are all real-time costs that, you know, the team has to present to Travis on a line-by-line basis every quarter. And, you know, this is a real-time look at where we are and where things are headed. You notice we put a Q4 2023 number in there just to kind of show where, you know, even we've moved from Q3- Q4. Got it. Appreciate the color. Thank you. Thanks, Scott. Thanks, Scott. Thank you. One moment for our next question. Our next question comes from the line of Leo Mariani of Roth MKM. Your line is now open. I just wanted to follow up a little bit on 2024. If I'm kind of reading this right, and it looks like you guys are talking about a rough budget next year of just a hair over $2.5 billion. Sounds like that's kind of flat activity. Just wanted to get a sense of kind of what's assumed in there for inflation or deflation. Are you just kind of assuming, you know, sort of current well costs in that number? Yeah, I mean, we're always kind of a little conservative here, Leo. So, you know, I would say we're kind of in the range of where we think we are today. You know, again, we think generally service costs have kind of bottomed or flattened out. And, you know, absent a major change in rig count, this feels like a pretty good, pretty good range for next year. Okay. And then just to follow up quickly on the M&A topic here. I think you guys have made it, you know, pretty clear that, you know, you want to continue to be a consolidator over time with your, your cost advantage. You know, I guess at the same time, just kind of, you know, you guys talk about kind of a $60, you know, type of budgeting case, you know, for oil. Obviously, we've been above there. Is there any, you know, scenario where, you know, FANG thinks about potentially going the other way, and actually selling at the end of the day? You know, Leo, I tried to address that a little bit in my opening comments as one of the first questions and also in my letter. Look, we're, we'll always do the right thing for our shareholders. We've been, you know, I feel like we've done that for 12 years now. But again, what our focus is, you know, on delivering our business plan, and we believe in our business model. We believe that there's a meaningful spot in our investment community for a company like Diamondback, and we continue to execute flawlessly. And I think, I think I'm really confident about what our forward plan looks like. Okay, thanks. Thanks, Leo. All right, thank you. One moment for our next question. Next question comes from the line of Paul Cheng of Scotiabank. Your line is now open. Thank you. Good morning. Two questions. One, one of the way to reduce costs, I think the industry is moving for the electrification. Simulfrac, wondering if you can give us some idea that how far along on your process in doing so? And secondly, with the Deep Blue, I think in the past you guys are very proud of your water infrastructure and all that. So is that signaling that now you have a change of view of what kind of infrastructure need to be owned by or need to be controlled by Diamondback going forward? So should we just assume that this means that you really don't think that's necessary for you to have control or to own those infrastructure? Thank you. Yeah, good, good questions, Paul. I'll take the second one first, you know, on the midstream infrastructure. You know, we spent a lot of money building those systems to the, the specs that we needed. And so, you know, I think we're not, you know, we're not turning over a blank canvas, right? This is a painting that's already been on, it's finished finishing touches, and so we feel confident, you know, particularly with a lot of our field team members going over to Deep Blue to run the asset, that we'll be well, well-served as its largest customer and also a large equity holder. So I think if we were early in our development plan, it might be a different story. But in this case, you know, it's a very well built out system that is kind of ready-made to turn over to them to, in our minds, do some more things commercially that we couldn't do as a standalone water enterprise. And then your other question on electrification, you know, it's certainly a hot topic in the Permian. You know, I think, you know, generally, electrification means both lower cost and lower environmental footprint, and that's a great thing for us in this basin. You know, we've done a lot of work ourselves. I think the state of Texas and, you know, the utilities need to kinda do their part to get more power out to the Permian to connect all of us so that, you know, we can run off of line power versus, you know, different forms of generation in the field. So I think that's gonna be a constant battle that we're intently focused on. And again, it saves us money and improves environmental performance. That feels like a win. Just curious, then, I mean, what% of your operation now here has already been electrified? That where you think is the biggest opportunity over the next one or two years? Yeah, we've got about 90%-95% of our current production operations electrified. You know, the biggest opportunities we've been working on to date in the production operations world have been electrification of our compression fleet, and I think we're probably, you know, 70-ish% electrified there. So we'll continue to work on, you know, getting rid of our gas, you know, gas recip compressors and putting electric packages in their place. And then on the DUC side, you know, we've got two simulfrac fleets that are Halliburton, what they call their Zeus fleets, which are their electric fleets. And, you know, we've really enjoyed the benefits of those and, you know, look forward to continuing to try and electrify the completion world. And then on the drilling side, you know, we've got, I think, five or six rigs running right now on line power. And we're continuing to, you know, put in the infrastructure that we need to run those rigs off line power, as the supply chain kind of frees up, you know, on the back of COVID, and we can get the electrical equipment we need to convert those rigs. So, you know, it's kinda all over, but, you know, we're working on it as fast as we can, and, you know, I anticipate that, you know, over the next four or five years, there won't be much of the field that's not electrified. Thank you. All right, thank you. This does conclude the question and answer session. I would now like to turn it back to Travis Stice, Chairman and CEO, for closing remarks. I appreciate all the good questions this morning, and I hope you find our shareholder letter, you know, constructive in the way that we can help communicate details about our business plan. The last comment I wanna make before we sign off is that we have an opportunity this Saturday to recognize all of our veterans across this country on Veterans Day. Certainly, for all of the veterans that are employed by Diamondback, thank you for your service, and then anyone that's on the phone that also dedicated a portion of their lives to our country, I want to tell you thank you for your service as well. And then, particularly for the Diamondback employees, hopefully we'll see you at breakfast or lunch ceremonies that we have planned for this Friday. So thank you. Y'all have a great day. God bless. All right. Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.