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. 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?

Alright. Thank you. At this time, we will conduct a question-and-answer session. 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 suggested you all would return to more of a production growth type model, I'd call it. And I think you've mentioned when the macro fundamental supported. I'm just wondering, do you believe we're close to that scenario and wondering, why do you believe the continued high free cash flow payout is warranted?

Yes. Neal, 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 supply disruption or even 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 in our plans. As we look forward into next year, again, look for real efficient capital allocation and as an output of that capital allocation which 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, I couldn't help but notice the new slides on slides 10 and 11 highlighted the efficient execution and then, 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, and we said the 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 shale was laid down. 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 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. And then, let's see. What was your second question?

Just on the cost, on the cost, I know, Kaes and I've talked about, I mean, is it just on, I know you have lower casing just different, sort of raw material costs, but is there other areas in that that larger projects that are causing these, when you see that, that well productivity chart on the right, sort of what's driving the lower cost efficiencies there?

Yes, certainly. Again, referencing back to slide 10, we've laid out the biggest elements of cost savings, cost components, and reductions over time. As you pointed out, it's casing is down about 20% or so. It's really as you look into next year, we feel more of a kind of a steady-state run rate on our cost. There'll be some puts and takes on both sides of the equation. Kaes, do you want to add anything?

Yes, I believe the primary advantage of large-scale development is the ability to consistently operate the rigs in the same location for an extended period. The most significant savings from a capital perspective come from the fracking side, where we can utilize two SimulFRAC crews simultaneously on the same site. This results in savings of approximately $250,000 to $300,000 per well due to SimulFRAC. Additionally, we have two fleets, or e-fleets, that operate on lean gas, saving another $200,000 to $250,000 per well. Therefore, this large-scale development is closely linked to the longer cycle of our operations, which indicates that we prefer not to alter our strategy with every fluctuation in oil prices. We have maintained a consistent plan for several years, leading to reliable outcomes regarding well productivity per foot.

Thank you both.

Thanks, Neal.

Thank you. One moment for our next question. Our next question comes from the line of Neil Mehta of Goldman Sachs & Co. Your line is open.

Yes. Thanks, guys, and appreciate the helpful letter and the time today. Travis, why don't we start on return of capital as a topic talked about this in the letter of, you wanting to air on the side of caution as it relates to, buying back stock to avoid repurchasing pro-cyclically 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?

So, Neil, our main focus remains a sustainable and growing base dividend that we think represents 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 so far in the fourth quarter. We honor our commitment to return at least 75% of our free cash flow by making our shareholders hold in the form of 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, 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. In this case, we continue to run a NAV value at mid-cycle oil prices, which is $60 oil, and calculate oil price or calculate stock price. Depending on where our stock is trading relative to that calculation, we either buy more or, if not, then we pivot to a share repurchase or to a variable dividend like we did this time around. So, again, it's based dividend, its share repurchases with a degree of caution in a pro-cyclical environment and then honoring our commitment in 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 Basin and 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?

Yes. Good question, Neil. The Deep Blue JV was a very big deal for us. It took a long time to pull together. We had built a significant amount of midstream infrastructure over the years and spent a lot of capital doing it. We felt it was an opportune time to monetize that in the hands of who we see as operational experts in Deep Blue and the Five Point team. I think they have already proven to have commercial success with third parties where maybe if you had the Diamondback business card, you weren't going to have the same type of commercial success. I think that sector is certainly ripe for consolidation as well. I think 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, 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. Then we'll have a lot less midstream CapEx as we don't have very many operated midstream assets. That’ll be kind of canceled out by slightly higher well costs $10 to $20 a foot, depending on the area, as we buy water from the JV. So, all in all, we sold the business for a much higher multiple than we trade, and then 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.

Alright. 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, and 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 and 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?

Yes, David. And I appreciate you referencing the Shareholder Letter. I tried to address that head-on. In a more macro sense, we'll always do what's right for our shareholders. 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 acquirer and exploiter strategy. I think 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 our inventory that meets the criteria we laid out in our Shareholder Letter, centered around sound logic and being able to compete for capital right away, which makes it accretive on those financial measures that are so important. There has been a lot of private equity roll through. I think based on our lack of participation, it tells you where we view those assets relative to our inventory. Like I said, I'm really pleased with the quality of our inventory, and I think we're executing on that in a flawless manner.

Thank you. I wanted to ask Kaes about the DUC backlog, which I believe is projected to reach 150 by the end of the year. I recall that you mentioned low single-digit organic oil growth for next year. Can you confirm if that growth reflects the benefits of the increased royalty interest from the Viper acquisition, or how we should interpret that growth rate? Additionally, considering the DUC backlog, should we expect flexibility in this pricing environment based on frac crew availability, or is this more of a capital allocation decision?

Yes. I'll hit the organic growth comment first. Certainly, we 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 jump start here in Q4, but 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. On the DUC side we were kind of operating pretty close to the rigs on the completion crews and really needed some flexibility here and the drilling team's done a really good job this year getting ahead of plan, drilling more wells than expected sooner. With these large pads and large projects, you really want to have the flexibility to go somewhere if something bad happens, and that DUC 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. We've kind of set the stage for a world where we run for the SimulFRAC crews consistently throughout the year; they each do about 80 wells a year. In our mind, that's the most capital-efficient development plan we can imagine. That’s our backlog, just let Danny sleep a little better at night and allows for some flexibility heading into next year.

Good deal. Thanks for the responses.

Thanks, David.

Alright. Thank you. One moment for our next question. Next question comes from the line of Scott Hanold of RBC Capital. Your line is now open.

Yes, thanks. If I could go back to the M&A topic a little bit differently. When Kaes, Travis, when you step back and think about where Diamondback'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 like where you think your inventory life is, and where ideally would you like it to be?

Yes. 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. I'd kind of go back to thinking about what positions in North American shale or in the Midland Basin would be envious, 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 what's out there. I just think Travis's comment is really about knowing who you are. This Company has been an acquirer and exploit company that's been able to execute on acquiring and exploiting assets through our low-cost structure. Generally, we have had a philosophy that the low-cost operator in a commodity-based business wins. Our cost structure is what has created this business to be as big as it is today. Travis, do you want to add anything to that?

I think that makes sense. We've talked about the high bar for entry into the Diamondback portfolio. That's just how we view it, and we're very proud of the inventory we have. What goes along with that durable inventory is how we convert that inventory into cash flow. Again, you see this quarter flawless execution from our teams in converting rock into cash flow. Our cost structure is enviable, and our execution prowess is unmatched, and that makes a big difference when you talk about a profitable oil and gas company.

Yes. And then 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?

Yes. 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 another solid five or ten years beyond that. It's very logical that at some point 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 $1 million or $1.5 million or $2 million cheaper, 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. We started with 50,000 acres an hour at 55,000. As that culture and mantra has not changed, 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. 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. As you see yourself progressing over the next years, does it seem to make sense that buying back stock at higher prices in this heightened market relative to what you did in the past still make sense from a value return standpoint?

Yes, it's really all about value. If you run your business conservatively from an oil price perspective and accrete value quarterly at $75 to $80, $85 crude, if you're actually building equity value on a conservative basis. 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're basically building $3, $4 a share of extra intrinsic value. I think that's what we've done here over the last couple of years in this up-cycle. As Travis mentioned, we want to be conservative when buying back stock. We think capital is precious and capital discipline not just applies in the field, but also to returning capital to shareholders. That’s why we've had this flexible return of capital program since we put it in place two and a half years ago.

Thank you.

Thanks, Scott.

Alright. Thank you. For your question one moment for our next. Next question comes from the line of Roger Read of Wells Fargo Securities. Your line is now open.

Yes. Thanks. Good morning. I think I'll skip the obligatory share repo versus a variable dividend question for a moment, and just go back to the operational aspects. 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'll accrete value. And thinking that we're not going to have some of the asset sales that have certainly helped on the sort of cash flow generation assets?

Yes. That's a good question, Roger. I think it's interesting. We put a slide in slide 10 about operational track record and prowess. 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.' 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, two, three, four days faster than they were even two years ago. The culture that we've 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, generally we've tested some other zones in the Midland Basin that looked very, very good. We got a couple Upper Spraberry tests in the Northern Midland Basin that looked very good relative to our Middle Spraberry Road, Jo Mill development. 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. Certainly, there's a lot of excitement about deeper zones in the Midland Basin as well, the Barnett and the Woodford that we're on testing. 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, do you want to add anything?

Yes. Roger, if you back cast 10 years ago, when we first started this, we were still drilling a few vertical wells. 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, a major depth of about what we were drilling vertically when we started. We're drilling those 7,500-foot lateral wells in under four days. When we started, sometimes it would take us over 24, 25 days to get to that same measured depth vertically. Probably the most repeated question we get is what is the secret sauce? What is the magic that Diamondback does that allows execution quarter-over-quarter to far exceed the competition? It's essentially the same rock and the same tools, but the culture we've 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 continue to give them good rock, they'll 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 what hasn't changed, which is our 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. Alright. Our next question comes from the line of Derrick Whitfield of Stifel. Please go ahead.

Good morning, all and thanks for all the incremental disclosures this quarter.

Thanks, Derrick.

Thanks, Derrick.

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, Derrick. I'd probably say that maintenance CapEx would be $100 million to $200 million cheaper, 30 wells maybe.

Yes. I think, we're kind of looking at it like our maintenance case for 2024 is a maintenance activity case. So, flat activity outfits a little bit of growth, but 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, Derrick, while you're on that topic of maintenance CapEx, I might just point you to slide seven. We've had that slide in there a couple of times, but it shows maintenance CapEx, which Danny just defined as holding the fourth quarter production flat for next year. I just want to show you what our breakeven prices are on that slide, $32 a barrel to cover maintenance cap, maintenance CapEx, $40 a 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. 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?

Yes. Good question, Derrick. We do lay out some of our remaining JVs that we have on slide 26. Yes, 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 done, guys. Thanks for your time.

Thanks, Derrick.

Thanks, Derrick.

Alright. Thank you. One moment for our next question. Next question comes from the line of Kevin MacCurdy 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 synergies you've created in those transactions or maybe just share with us your analysis of Diamondback 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?

Yes. 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 other people dropped out. 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 Lario well costs were near $8.5 million, $9.5 million for 10,000 foot lateral, and we were drilling them at around $6.5 million to $7 million. That's kind of been our mantra for a long time. I would just say generally, if you split the two deals out, Lario was an execution deal because we knew we could drill those units cheaper and execute on large scale development. FireBird is more of a technical deal. We had a technical view of that particular area that the basin could move further west, particularly in the northern top portion, where some multi-zone development looks really good. I think we're conservative on the multi-zone potential of the central block. Now I feel a little more confident about the Wolfcamp A and Lower Spraberry maybe being in that area. With that block being so contiguous, we're able to bring a 15,000-foot lateral manufacturing process to that area. We underwrite these deals at our cost structure, which, if you look at our cost structure versus others, 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 question, Kevin.

Alright. Thank you. One moment for our next question. Next question comes from the line of Jeoffrey Lambujon of TPH & Co. Your line is now open.

Good morning, everyone, and thanks for taking my questions.

Morning, Jeff.

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 laterally in the commentary in terms of how that might evolve over the near-term program? That would be helpful as well.

Yes. Jeff, with these longer cycle projects, we have a pretty good view of what the projects look like coming up here in 2024. I'd say generally 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'd say it's also a very heavy Martin County development year for us, which is great, large scale, multi-zone development and some of the best undeveloped resources remaining in the Midland Basin. I'd say from a testing perspective, some more wells can be probably making it into the plan and a lot more Upper Spraberry making it into the plan. We kind of have a couple of really good tests, and part of our culture is when something works, we implement it very quickly. That is how we kind of see the shallower development 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 than theirs, how do you think about opportunities that can near?

Yes. A good question. That ties to something that Danny answered your last question. The number of wells in the Midland Basin will be kind of 85%, 90% of total capital. The Delaware Basin will still be a small percentage of total capital. I think, if I'm getting what your question is, it's where does the Delaware Basin sit in the portfolio. For us, certainly we start that area of capital a little bit here in the last few years. It provides a lot of cash flow and production, which is beneficial to us today. As you've seen over the course of the year, it seems like inventory is coming at a premium. There may come a time when someone really, really wants a portion of our Delaware position, but we're not going to sell it for anything less than a reasonable price versus where we trade. We plan to hold it for now, and if someone wants to pay for upside in a reasonable number, we will 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 want to start on slide 11. You've been espousing the co-development approach for some time, and you show pretty solid results, consistent results since 2020. Just curious, one of your 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?

Nitin, 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 are 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 when you see results like that, so 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 if you are a fast follower 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?

Yes. I mean, I think generally that would be a great problem to have. It really ties back to this can you run a SimulFRAC program consistently on that position and those projects and those paths kind of goes all those back to this longer cycle nature of the shale business model. We feel really good about the four SimulFRAC crews running consistently right now, Nitin, and have the infrastructure to do that. If growth exceeded expectations, that would be a good problem to have.

Great. Thanks. That's it for me, guys.

Alright. Thank you. One moment for our next question. Next question comes from the line of Charles Meade of Johnson Rice. Your line is now open.

Good morning, Travis, Kaes, and Danny. I have one more question, possibly from a different perspective regarding the A&D outlook. Kaes, I believe you mentioned in your prepared comments or possibly earlier in the Q&A that there are very few positions that you envy, which indicates that your standards are high. However, from my viewpoint, while it seems that there aren’t many positions you’re interested in acquiring, there also appear to be fewer potential buyers, especially for some of the large private positions. Do you agree that there are fewer credible buyers for these sizeable packages that might still be available? More generally, how is the landscape changing as you engage in data rooms and processes as buyers and sellers?

Yes. That's an interesting observation, Charles, and it's certainly not lost on us. You've had a couple very large buyers do a couple of deals in the basin and out of the basin. They could kind of do whatever they want it seems. I would just say generally industry consolidation has happened and continues 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 fewer buyers of assets, but they're all well-funded good operators with big balance sheets, and they are competitive. We have to stick to our zones and our underwriting philosophy around our cost structure and our rates of return internally, a lot of hurdles for commodity price. Usually, that results in more assets coming to Diamondback because you can underwrite wells drilled at $1 million or $2 million cheaper. We can run LOE cheaper, 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 JPMorgan Securities. Your line is now open.

Yes. Good morning, gentlemen. I wanted to keep on the A&D theme. When we assess the potential of a large private or one of these unicorns to potentially consolidate, does it just come back to price, or is there something that they think about in terms of the independent versus major oil business model that could be advantageous to a company like Diamondback who is in Midland and has one of the lowest cost structures in the industry?

Yeah. Arun, we don't spend a lot of time thinking about what sellers think. We think about what is the best opportunity available for our shareholders and creating shareholder value for our shareholders. At the end of the day, I think Diamondback, hand on heart, has one of the best positions remaining in North America and the best cost structure. That should be a very winning combination for our shareholders for a long time here.

Understood. I want to switch gears and just talk about the DUC efficiency gains. It seems like the drilling efficiency gains are outpacing what we're seeing on the completion side. Are you guys recalibrating the rig to frac crew ratio? Give us a sense of 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 changed so much. 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. On the drilling side, maybe a year ago that was 15 to 16 rigs for a full year. Now, this year moving forward, it looks more like 14 to 15. 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. When we need to pick up a rig and when we need to drop it, you're really kind of just targeting can we keep those SimulFRAC crews busy consistently? I'd guess the number is kind of in that high threes, almost four rigs to one SimulFRAC crew today.

Yeah. Arun its Kaes. Our goal is to keep the drilling program ahead of the SimulFRAC fleet and just keep the SimulFRAC fleet moving efficiently just like we want to keep rigs moving from pad to pad without waiting on packs or whatever. We see them as two different programs altogether, knowing that they're very dependent on each other. I think the drilling and completion teams have really done an excellent job of leaning in to push the machine to the limits and finding those little pieces of efficiency gains that 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 lean into it and continue to chase that efficiency line.

Great. Thanks a lot.

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’s question just on the activity set in the next year and get some clarity on the plan for the DUCs. It sounds like you could 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 contemplate a drawdown of some of those excess DUCs?

I don't think we're planning on drawing any down, absent any in-the-field issues. I think generally, we feel a lot better at this level of DUCs for the size of projects that we have ahead of us. Earlier this year, we were getting pretty close; the frackers were getting pretty close to the rigs getting off location, and with 20-well or 24-well pads, you have to have all 24 wells done before you can bring in the drilling side. Before you can bring the fracture in, at least that's how we do it. That's why the 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 inventory number. Again going back, those aren't the days of two-well pads where, when something bad happens, you can pull out the pad and go somewhere else. These are long cycle mini, and Daniel 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, all the cost trends across the various buckets on slide 10. If you think about going through RFP season for 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? Are those starting to stabilize now?

Yeah. I think we think it's kind of stabilizing right now. For us, there really is no RFP season, right? RFP season is every day coming back. 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 for next season or for the summer. It's going to happen now. So, it's a constant RFP season here. These are all real-time costs that the team presents to Travis on a line-by-line basis every quarter. This is a real-time look at where we are and where things are headed. As you noticed, we put a Q4 2023 number in there just to show where even we've moved from Q3 to Q4.

Got it. Appreciate the color. Thank you.

Thanks, Scott.

One moment for our next question. Our next question comes from the line of Leo Mariani of ROTH MKM. Your line is now open.

Hey, 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 $2.5 billion. Sounds like that's kind of flat activity. Just wanted to get a sense of what's assumed in there for inflation or deflation? Are you just kind of assuming sort of current well costs in that number?

Yeah. I mean, we're always kind of a little conservative here, Leo. So, I'd say we're in the range of where we think we are today. Again, we think generally service costs have flattened out. I haven't seen a major change in rig 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. Think you guys have made it pretty clear that you want to continue to be a consolidator over time with your cost advantage. At the same time, you guys talk about kind of a $60 type of budgeting case for oil, obviously, it's 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?

I addressed that briefly in my opening comments and in my letter. We will always do the right thing for our shareholders; I believe we have done so for the past 12 years. Our focus remains on delivering our business plan. We have confidence in our business model and believe there is a significant place for Diamondback in our investment community, and we continue to execute flawlessly. I am very confident in our future plans.

Okay. Thanks.

Thanks, Leo.

Alright. 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 ways to reduce costs, I think the industry is moving for electrification. I'm curious how far along you are in that process? And secondly, with the Deep Blue, I think in the past that you guys are very proud of your water infrastructure and all that. Is that signaling that now you have a change of view of what kind of infrastructure need to be owned or controlled by Diamondback going forward? Should we just assume that this means that you really don't think it's necessary for you to have control or to own those infrastructures?

Yeah. Good questions, Paul. I'll take the second one first, on midstream infrastructure. We spent a lot of money building those systems to the specs that we needed. We're not turning over a blank canvas. This is a painting that's already finished. We feel confident, particularly with a lot of our field team members going over to Deep Blue to run the asset, that we'll be well served as its largest customer and also a large equity holder. If we were early in our development plan, it might have been a different story. But in this case, it's a very well-built-out system that's kind of readymade to turn over to them to do some more things commercially that we couldn't do as a standalone water enterprise. Your other question on electrification is certainly a hot topic in the Permian; generally, electrification means both lower costs and lower environmental footprints, and that's a great thing for us in the basin. We've done a lot of work ourselves. I think the state of Texas and the utilities need to 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. It's a constant battle that we're intently focused on, and again, it saves money and improves environmental performance, which feels like a win.

Just curious that, I mean, what percent of your operation now here has already been electric? And in what way do 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. The biggest opportunities we've been working on to-date in the production operations world have been electrification of our compression fleet. I think we're probably 70-ish percent electrified there. We'll continue to work on getting rid of our gas receipt compressors and putting electric packages in their place. On the DMC side, we've got two SimulFRAC fleets that are Haliburton, what they call their zoos fleets, which are their electric fleets, and we've enjoyed the benefits of those. We look forward to continuing to electrify the completion world. On the drilling side, we have, 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 run those rigs off line power, as the supply chain kind of frees up on the back of COVID. We can get the electrical equipment we need to convert those rigs. It's kind of all over, but we're working on it as fast as we can. I anticipate that over the next four or five years, there won't be much of the field that's not electrified.

Thank you.

Alright. 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. I want to thank all the veterans that are important to Diamondback; thank you for your service. Anyone 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. Particularly for the Diamondback employees, hopefully, we'll see you at breakfast or lunch ceremonies that we have planned for this Friday. Thank you. You all have a great day and God bless.

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