Diamondback Energy, Inc.

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 1 1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1 1 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Adam Lawlist, VP of Investor Relations. Please go ahead.

Thank you, Stephen. 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, Kate Fantoff, 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 Steinitz.

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 1 on your telephone and wait for your name to be announced. To withdraw your question, please press Star 1 again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Neil Dingman 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 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 could potentially move the markets both positively and negatively, both with a supply disruption or even a demand destruction 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 return a shareholder model versus a growth model. As we've intimated, our plans as we look forward into next year, again, look for real efficient capital allocation. And as an output of that capital allocation, we expect 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 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, we tried to demonstrate our evolution from 2015 to today. We said average wells per project is about 24 wells. I think generally 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 there is also where we'll do slightly less than 24 wells, which usually translates to 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 summary. Let's see, what was your second question?

Just on the cost, I know Kay's not 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, again, as you pointed out, it's casing to down, you know, 20% or so. You know, it's really, as you look into next year, we feel more of a kind of a steady-state run rate on our costs. There will be some puts and takes on both sides of the equation. Case, do you want to add anything to that?

Yeah, I mean, I think the biggest benefit to the large-scale development, Neal, is, you know, the consistency of running the rigs, you know, in the same spot for a long period of time. But, you know, on the frac 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 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, you know, had a consistent plan here for a few years now, and the output of that is, you know, consistent results on the well productivity per foot.

Thank you both.

Thank you, Daniel.

Thank you. One moment for our next question. Our next question comes from the line of Neil Mittal 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 the split between buybacks and dividends going forward?

Our main focus remains a sustainable and growing base dividend that we think represents the most the most efficient way for our shareholders to understand 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 hold in the form of a variable, which we seem we did this year. I think the most important thing is 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 case, we continue to run NAV value at mid-cycle oil prices, which is $60 oil, and calculate stock price. 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 increase, or if not, then we pivot to a variable dividend like we did this time around. Again, it's base dividends, it's share repurchases with a degree of caution in a pro-cyclical environment, and then honoring our commitment through the form of a variable dividend.

Okay, that's really helpful. And 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 lace in 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 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 upstream 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 Donenbach business card, you weren't going to 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 going to be able to grow the business and generate a good return for our shareholders. Outside of the $500 million of proceeds we got in, which is the big winner, there will be some impacts to our cost structure. I would say generally, LOE is going to be up about 8% to 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 to $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, Keith.

Thank you.

All right. Thank you. One moment for our next question. The next question comes from the line of David Deckelbaum of TD Cowan. Your line is now open.

Good morning, Travis and case team, Danny. Thanks for taking my questions. Travis, I was curious if you could talk a little bit more 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 you're right, we have built this company through an acquire and export strategy. 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 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 being accretive on those financial measures that are so important to all of us. There has been a lot of private equity rolled 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 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. Maybe just for Kay, the duck backlog is built, I guess, up to 150 by the end of the year. I think you guys talked about low single-digit organic oil growth for next year. One, I just wanted to confirm, like, if that oil growth is reflecting the benefit of the increased royalty interest through the Venom acquisition or 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 the duck backlog, you know, is it, should we think about that flexibility, especially in this pricing environment, just based on FRAC accrual availability or, Is that really just like a capital allocation decision?

Yeah, I'll hit the organic growth comment first. Certainly, excluding the Viper deal, we expect it to grow organically. We expect to grow organically in 2024. I think the Viper deal provides a little bit of a jumpstart here in Q4, but I think the team's expecting to grow off that number 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 duck side, you know, we were kind of operating pretty close to the rigs on the completion cruise and, you know, really needed some flexibility here, and the drilling team's done a really good job this year getting ahead of plan, drilling more well 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 duct backlog allows that. So I think 150 plus or minus 10 or 20 wells either way is a pretty good number for our run rate and we kind of set the stage for a world where we run four of these simul-frac crews consistently throughout the year. They each do about 80 wells a year and in our mind that's kind of the most capital efficient development plan we can imagine here. That duck backlog just lets Danny sleep a little better at night and 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. The next question comes from the line of Scott Henold of RBC Capital Markets. Your line is now open.

Yeah, thanks. If I could go back to the M&A topic a little bit differently. Case, Travis, when you step back and think about where Dimeback's inventory depth is and to be a long-term successful large-scale play in the Midland, do you think that more large-scale M&A is necessary over time? And just remind us 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 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 an 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, do you want to add to that?

I think that makes sense. We've talked about the high bar for entry into the down and back portfolio. That's just how we view it. We're very proud of the inventory we have. I think what goes along with that durable inventory is how we convert that inventory into cash flow. Again, you see 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 Dynamo.

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... 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 going to 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 one or one and a half or two million dollars cheaper, we're 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 50,000 acres, and now we're at 550. And that culture and mantra has not changed, and I think that sets us up well for a world where assets are getting more and more sparse.

Got it understood. And if I could follow up on our conversation we had last night just on the shareholder returns and stock buybacks. And I thought it was an interesting conversation we had on just where FANG's intrinsic value is now and the opportunity to grow that over time. And so when you step back and think about the current oil market, obviously, we're in a little bit more heightened oil price versus your intrinsic point. But like as you see yourself progressing over the next years, I mean, does it seem to make sense that, 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 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 crude, 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 case, 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, up cycle. 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. And 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 question. Our next question comes from the line of Roger Reed 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. 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, 24 to 36 months for what else you can do operationally that will accrete value? And thinking that we're not going to have some of the asset sales that have been going on that have certainly helped on the sort of cash flow generation aspect.

Yeah, that's a good question, Roger. I think it's interesting. We put a slide in, slide 10, about operational track record and prowess. And 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, they're still taking days out of the average well on a much bigger program. 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 sprayberry tests in the northern Midland Basin that look very good relative to you know, our middle spray grade Joe Mill development, so we're excited about that. I think the Wolf Camp D in the Midland Basin is starting to become a primary development zone in some of the basins, 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, you know, on to testing. So I think, you know, the Midland Basin, the stacked bay and the amount of oil in place just provides a lot of opportunity for 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 back cast 10 years ago when we first started this, we're still drilling a few vertical wells. And 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 membership 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, 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? It's essentially the same rock and the same tools, but the culture that we built here at this company with that laser focus on the conversion process of rock into cash flow is felt by every employee in the company. 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 going to generate the outstanding results that we're known for. I know that's a little bit of motherhood and apple pie, but I'm really proud of the organization for through all the cycles we've been through over the last 10 years, what hasn't changed is an unrelenting focus on delivering best-in-class execution, highest margin barrels at the lowest cost.

I appreciate that. I'm not going to be 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, and I'd probably say that maintenance CapEx would be, you know, one to $200 million cheaper. You know, 30 wells maybe, Danny?

Yeah, I think, you know, we're kind of looking at it like our maintenance case, our case for 2024 is kind of a maintenance activity case, so flat activity outputs a little bit of a growth, but, you know, if we were to try and maintain a flat production profile, you'd probably be in the line of 20 to 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, as Danny just defined, is kind of holding, you know, the fourth quarter production flat for next year. And 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 barrel to cover our base dividend. So that kind of goes back to my cost and execution comments that ultimately translate into a very protected business model, even 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 targets?

Yeah, good question, Derek. 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, we're kind of a non-op partner to these JVs that do have a ton of value, just not something that we can commit to monetizing today.

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 in-house for almost a year, can you comment on the level of cost energies you've created in those transactions? Or maybe just share with us your analysis of Diamondbacks 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. 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. At the time, I think some of the Lario well costs were near $8.5, $9.5 million for a 10,000-foot lateral, and we were drilling them at $6.5 to $7. 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, Laria 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. And, you know, we had a technical view of that particular area that the basin could move further west, 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 Wolf Camp Bay and the Lower Sprayberry maybe being wine racked in that area. And also with the benefit of that block being so contiguous, we're able to bring a 15,000-foot lateral manufacturing process to that area. So 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 the only one for me. Appreciate you taking my question.

Good questions, Kevin. All right.

Thank you. One moment for our next question. Our next question comes from the line of Jeffrey Lambougeon of TPH and Company. Your line is now open.

Good morning, everyone, and thanks for taking my questions. The first one is on 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 going to 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 Wolf Camp D probably making it into the plan and a lot more upper sprayberry 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. And then maybe just a housekeeping-type question on the non-core asset sales 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 that 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 however you think about the opportunities that come here.

Yeah, 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. I think, you know, if I'm getting what your question is, it's, you know, where does the Delaware Basin sit in the portfolio? And 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, really wants that Delaware position of ours or portions of it, but we're not going to sell it for, you know, a song at PB15, right, PDP. So I think we're going to hold it for now, and if someone wants to, pay for upside in a reasonable number versus where we trade, we'll take a look at it. Perfect. Thank you.

Thanks, Joe.

Thank you. One moment for our next question. Our next question comes from the line of Mutin Kumar of Mizuho. Your line is now open.

Hi, good morning, guys, and thanks for taking my question. Travis, I want to start on slide 11. You've been espousing the co-development approach for some time, and you show 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 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?

We keep our finger on the pulse of a lot of emerging technologies. We focus 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, particularly that kind of result. 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 FOSS 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 allow, would you keep activity flat, or would 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 paths? You know, it kind of 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 SAML frac crews running consistently right now 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. Next question comes from the line of Charles Mead, Johnson Rice. Your line is now open.

Good morning, Travis Case and Danny. I want to ask one more question, maybe from a different angle on the A&D outlook. Case, I think I wrote down what you said in your prepared comments or maybe earlier Q&A, that there's very few positions out there that you envy A&D. 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 want to buy, but there's also fewer potential buyers out there, particularly for some of these large private positions. So 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, and certainly not lost on us. You've had a couple of very large buyers do a couple of 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 industry consolidation has happened. It's continuing to happen. I think 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. So, 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 or $2 million cheaper. We can run LOE a buck 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 J.P. 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 like Diamondback who's in Midland and, again, you know, both 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. And, you know, at the end of the day, you know, I think Diamondback, you know, hand on heart as 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 want to maybe switch gears and just talk about the DNC efficiency gains. You know, really surprised to see This year, the drilling efficiency games, seems like the drilling efficiency games are outpacing maybe what we're seeing on the completion side. Are you guys recalibrating, call it the rig to frack crew ratio, but give us a sense of maybe what you're doing on the drilling side for these efficiency games and maybe help us recalibrate what that drilling to simul frack 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 numbers. And, you know, the drilling side, you know, maybe a year ago that was 15 or 16 rigs for a full year. And now this year, in upcoming, it looks more like 14 to 15. So, 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 paths 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 simul-track crews busy consistently? I would guess the number is kind of in that high threes, almost four rigs to one simul-track crew today. Okay.

I think, like Kay said, our goal is to keep the drilling program ahead of the simulfrac fleets and just keep the simulfrac fleets moving and efficient, just like we want to keep rigs moving from pad to pad without waiting on pack instruction or whatever. We kind of see them as two different programs altogether, knowing that they're very dependent on each other. I think the drilling and completion teams both this year have really done an excellent job of leaning in and pushing the machine to the limits and finding the little pieces of efficiency gains they can pick up. We continue, as we've always done, to tinker and find better ways to execute our development strategy and build a better mousetrap. When we find different ways to design these wells and execute that, we'll lean into it and continue to chase that efficiency line.

Great. Thanks a lot.

Thanks, Aaron. Thanks, Aaron.

All right. 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 the runes question just on the activity set in the next year and get some more clarity on the plan for the ducks. So it sounds like you're going to be running the 14 or 15 rigs. Will you end up drilling 330 or so wells by running 14 or 15 rigs, or will the base plan for next year, you know, contemplate a drawdown of some of those excess ducks?

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 ducks for the size of projects that we have ahead of us. You know, earlier this year, we were getting pretty close you know, the rigs or the fractures were getting pretty close to the rig 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 fracture in, or at least that's how we do it. And, you know, that's why that kind of 150 number that 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 inventory number. Again, going back, these aren't the days of too well pads, where if something bad happens, you can pull out the pad and go somewhere else. These are long cycle mini, 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, all the cost trends across the various buckets on slide 10. You know, if 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 24? Or are those starting to stabilize now?

Yeah, I think we think, you know, it's kind of stabilizing right now. You know, and for us, there really is no RFP season, right? RFP season's 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 to Q4. Got it.

Appreciate the call.

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, it looks like you guys are talking about a rough budget next year of just a hair over two and a half billion dollars. 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, you know, 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, I've seen a major change in rate count. This feels like a 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 cost advantaged. I guess at the same time, you guys talk about a $60 type of budgeting case for oil. Obviously, we've been above there. Is there any scenario where Fang thinks about potentially going the other way and actually selling at the end of the day?

Leo, I tried to address that a little bit in my opening comments as one of the first questions and also in my In my letter, look, 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 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'm really confident about what our forward plan looks like.

Okay, thanks.

Thanks, Leo.

All right, thank you. And 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 that to reduce cost, I think the industry is moving for the education. Charlotte that wondering if you can give us some idea that how far along on your process in doing so and secondly that with the deep blue I think in the past that you guys very power 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 and 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.

Good question, Paul. I'll take the second one first. On the midstream infrastructure, we spent a lot of money building those systems to the specs that we needed. And so 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 its 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 will be 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. We've done a lot of work ourselves. I think the state of Texas and the utilities need to kind of do their part to get more power out to the Permian to connect all of us so that we can run off of line power versus different forms of generation in the field. So I think that's going to be a constant 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, what percent of your operation now has already been electric buy-in that where you think is the biggest opportunity over the next one or two years?

Yeah, we've got about 90 to 95% of our current production operations electrified. We've been, 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 percent 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 DMC side, you know, we've got two... that are Haliburton, what they call their Zeus fleets, which are their electric fleets. And we really enjoy the benefits of those and look forward to continuing to try and electrify the completion world. And then on the drilling side, we've got, I think, five or six rigs running right now on line power. And we're continuing to put in the infrastructure that we need to to run those rigs offline power as the supply chain kind of frees up on the back of COVID and we can get the electrical equipment we need to convert those rigs. So it's kind of all over, but we're working on it as fast as we can. And I anticipate that 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. I hope you find our shareholder letter constructive in the way that we can help communicate details about our business plan. The last comment I want to 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 our 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.