Diamondback Energy Inc (FANG) — Q3 2025 Earnings Call Transcript

Thank you, Briana. Good morning, and welcome to Diamondback Energy's Third Quarter 2025 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 Kaes Van’t Hof, CEO; Danny Wesson, COO; and Jere Thompson, CFO. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance, 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 Kaes.

Thanks, Adam, and I hope everybody read the letter last night. As we've done in the past, we're just going to move straight into Q&A. So operator, let's open the line for questions, please.

Nice quarter. It’s great to be back. My first question is about activity. While I understand you continue to discuss the stop sign scenario depending on macro conditions, it seems some other operators in the Permian are accelerating even at current prices. Does the lack of capital discipline from others make you reconsider your plans, given that you are a lower-cost operator and cash flow is important?

Yes, Neal, I mean, I think we obviously track what everybody else is doing in the Permian. We have a lot of visibility into what's going on. But we also have a lot of conviction in where we stand and what our plan is. I think we can get into a game of who has the lowest cost structure reinvestment ratio, which we do. And on a year-to-date basis, we have a 36% reinvestment rate at mid-60s oil. I think that's something that would have been unheard of 6 or 7 years ago as investors pushed us to generate more free cash over cash flow. And I think that's the key point, right? We are focused on generating free cash flow per share, growing free cash flow per share over growing cash flow into a tenuous macro environment. Now when the assumptions change and the macro changes, we have the flexibility to change that. We're just going to do it with a much lower share count, lower net debt and off of a lower cost structure.

No, I'm glad to see that. Glad you're not changing the stripes there. And then second question, I guess, more just generic, maybe, Kaes for you or Danny, around Slide 8, specifically, continue to look at, I guess, I'd call it your development styles versus others, and you continue to be lower. I'm just wondering specifically what differentiates your development style versus others? Is it the larger projects? I mean does that factor in? Or what is the driver when I'm looking at this slide?

I believe Slide 8 is the key slide in the presentation. It provides insight into our efforts to improve development in the basin over time. Throughout our history, Diamondback has been recognized for maintaining the lowest cost structure and achieving excellent execution. However, what hasn't been emphasized enough is that we are not only drilling more wells per section, but we are also enhancing the performance of each well, allowing for more capital-efficient development of the entire section, which leads to significantly higher overall returns per section. In 2019, we transitioned to co-development and now manage all zones in the Midland Basin collaboratively. Rather than concentrating solely on individual well returns, we are prioritizing returns on a section and drilling spacing unit basis. I take great pride in the collaboration between the teams at Endeavor and Diamondback, which has combined the best inventory with an optimized cost structure, ultimately yielding the lowest reinvestment rate and the results shown on Slide 8. I encourage investors to pay close attention to this important slide.

Kaes, can you discuss the fourth quarter guidance regarding the $925 million capital expenditure and how it relates to your shift back to a maintenance mode? Is this a reasonable baseline for 2026 to maintain a production level of 505,000 barrels a day of crude, especially considering the Viper deal?

Yes, David, the new baseline is 510,000 barrels of oil per day. We announced the sale of some production at Viper, which will bring our run rate down to 505,000 barrels a day in Q1. We decided to keep that production level consistent with our Q4 capital expenditures, which is a good reference point. Reflecting back on Q2, our original budget for 2025 was $4 billion in capital expenditures, which we reduced by 10% initially and then cut another $100 million. This resulted in a $500 million decrease in expenditures due to strategic moves we made, anticipating a weaker oil market sooner. Consequently, production experienced a slight decline. This year's capital expenditure figure is solid. Whenever we reduce activity, capital expenditures tend to exceed the change in production. We are now stabilizing within the $875 million to $975 million range to maintain the new production baseline of 510,000 barrels a day, dropping to 505,000 in Q1 next year. There were many factors at play this year, but we felt it was necessary to adjust our strategy midyear due to concerns about oversupply and potential demand weaknesses. Overall, demand appears robust, while supply remains a hot topic for discussion.

I appreciate that information. Considering Slide 8 is the most important slide in the presentation, I feel it is necessary to ask a question about it. As we transition into the Endeavor-acquired Acreage in 2026, should we expect any significant changes to those three graphs? Can you share your confidence levels regarding well productivity as you begin implementing plans for some of the acquired assets?

Yes, I'll let Al talk about the specifics, but I'll go back to the announcement when we merged with Endeavor, and we told our investors that basically, if you took our pro forma average PV-10 per well and looked at it at the time of the deal, our next 5 years at the time of the deal was going to improve by almost 20%. And I think what you're seeing in Slide 8 is that synergy coming through because not only did we get bigger, but we got better when we did that deal. And Al do you want to talk about '26?

Yes, David. I think if you look at the '25 well performance and compare that back to '23 and '24, it's very consistent. And as we look forward to '26, we expect that to be very consistent with the '24 and '25 program.

Kaes, I was wondering if you could start a little bit on the efficiency gains front and maybe elaborate a little bit on your further improvements on the drilling side and love to get a little bit more insights on this continuous pumping design that you're now implementing on your houses fleets? And what could that do for your dollar per foot, which I think has been in that $550 to $580 range in the Midland Basin?

Yes. Let me give you some high level and then pass it to Danny. But from a high-level perspective, this year, well costs have come down even in the face of steel tariffs hitting our business to the tune of about 20% on our steel costs. So it's a credit to the team that with the headwinds of something we can't control, steel tariffs hurting us, we've been able to find ways to increase efficiencies even without service costs kind of plummeting throughout the year. So Danny, I don't know if you want to give some detail on continuous pumping and the drilling side.

On the drilling side, we've been focusing on achieving more consistent performance from our top 10% of wells. This quarter, we managed to have about 1 out of every 10 wells completed in under 5 days, compared to just 1 or 2 in previous quarters. We are improving in our ability to deliver impressive drilling results and are working to reduce the average days from spud to total depth. Regarding completions, we are excited about our continuous pumping efforts. Although we are not forecasting any significant cost savings at this time, we anticipate that increasing the lateral footage completed daily on a pad by 20% will lead to some savings. However, estimating that now is challenging due to the additional equipment and setup needed for continuous pumping operations.

But I do think the one thing that continuous pumping and more lateral footage per day does for us is it improves the cycle times and gets any production that we've watered out when we go in and frac in a contiguous field, that production comes back online faster. And that's kind of one of the key benefits that will accrue to our shareholders over the long haul.

Super interesting. My follow-up is, Kaes, you brought back Slide 25, which is on power gen and some of the opportunities perhaps for Diamondback just given your surface acreage, your natural gas output in West Texas as well as the fact that you do consume power for your own internal operations. Wondering thoughts on bringing back that slide and maybe just an update on your corporate development activities around this important topic, at least for investors.

Yes, Jere is going to give you all the details, Arun. I would just say, generally, we did that for a reason, and we're starting to get a lot more confidence in what could be an interesting story for Diamondback's development and gas pricing over the coming years.

Yes. Good observation, Arun. Last week, you may have seen that we committed up to 50 million a day of our nat gas to competitive power ventures for their new 1.3 gigawatt Basin Ranch power plant in Ward County. We expect this to be operational in 2029. This was done under a long-term supply agreement with pricing indexed to ERCOT. And we view it as a creative in-basin egress solution for our natural gas supply. And although in this particular scenario, it is low volumes, we feel it's a small piece and a much larger story for us, which is consciously moving away from Waha. And for reference there, by year-end 2026, we expect Waha exposure to be down to just over 40% of gas sales as compared to a little over 70% today. And additionally, we continue to work on other power projects that could potentially use cheap Diamondback gas and surface, deep blue water, and near-term generation solutions to bring data centers to the Midland Basin. And as I mentioned last quarter, it's a long process, but we look forward to updating the market when we have a firm project to discuss.

And Kaes, maybe I get you to share your perspective on where we are with the macro. I think you indicated in the letter, you think we are at the yellow light right now. So maybe spend some time thinking about how you're thinking about the moving pieces as we move into 2026.

Yes, Neil, I mean, we spent a lot of time, I think more time than ever this year on the macro. Unfortunately, we did have to put the yellow light in the release for the third time in a row. I would just say, generally, the outlook kind of remains murky. I think, fortunately, it's a debate on the supply side. And it seems that, that debate will be resolved sometime in the next couple of quarters. But a couple of things, right? I would say our attitude is we don't control the price of the product we produce. And as an organization, we have 1,700 people focused on producing more oil with less cost every day, and that's what they've done, right? We've been able to generate more free cash this year, 15% more per share despite oil prices being down 14%. So I kind of turn the tone from, 'Hey, this isn't great to we're going to figure it out and find a way because I think the longer this kind of murky macro lasts, the better things will be on the other end.' And Diamondback, in my mind, is going to be one of the long-term winners of whatever the macro presents to us.

I have a follow-up question regarding mergers and acquisitions. There are two parts to this. First, you've done an excellent job of divesting non-core assets. I'm curious if there are additional opportunities within your portfolio. Last quarter, there was quite a bit of discussion regarding your stance on not being a seller, but I believe you provided clarification on that matter. I'd appreciate your thoughts on these two points.

Yes. I think on the noncore sales, first off, credit to Jere and the team. We sold $1.5 billion of primarily 90% non-E&P producing assets at higher multiples than we trade. And that, in my mind, accrues straight to the balance sheet, puts our debt load in a good position for whatever the next couple of quarters may hold. So I think we've exhausted the majority of it. Viper, as you might know, also executed a noncore or non-Permian asset sale with a good number that we'll talk about in a couple of hours. But all-in-all, I feel really good about being able to execute on these in a challenging macro at good valuations. And then on the other side of the question, we get that question a lot on our position in the industry. And I think generally, Diamondback has the most coveted asset base in North America, and that's a very privileged position to be in. But we didn't just fall into it, right? We had to earn it acre by acre. And so we take a lot of pride in our execution and our execution machine and what that means for long-term shareholder value.

Circling back on the macro, I mean everyone's gotten more capital efficient this downturn. Maybe it takes until '27, but curious how you see a green light scenario playing out for the Permian broadly. Can you just talk about how less capital efficient it is to grow first stay and maintenance as we saw in 2022? And do you think the industry has the capacity to really accelerate if called upon?

Yes, Phil, that's a good question. We're discussing this, but I truly believe the industry can handle it. The key factor is how capital efficient it is. My view is that when the time comes for a green light, which seems likely to happen as crude prices return to the $70 to $80 range, the capital expenditures will yield a much higher return compared to when oil is at $60. Additionally, this spending will occur on a balance sheet and share count that have both decreased. That's our perspective. We're definitely seeing good returns at $60, but we also recognize that increasing crude supply in a clearly oversupplied market raises the question of just how oversupplied it is, making it an unwise choice at this time.

Okay. Great. And then coming back to Slide 8 here in the deck, I mean, we did note that your relative ranking on well productivity improved versus the peers. The question is more when you look at benchmarking on average wells per section, how much of FANG's leadership do you think can be attributed to you guys just have more core acreage, maybe less power, less Southern Midland exposure where you have peer zones? Or do you think peers are still leaving behind quite a bit of child wells targeting best zones, which you also have unique perspective in given the Viper?

Yes, actually listen, I think high level, geology matters a lot, right? And is a huge driver. As we develop our acreage, we have different patterns in different areas. And even across a couple of miles, things change very, very quickly. But I think the high-level takeaway, and I can let Al give some more details, though, the high-level takeaway is if you multiply wells per section times well productivity per well, you're getting more oil per section or per DSU at a lower cost structure. I think that means more PV per acre, and we got a lot of acres to do that on. Anything you want to add there, Al?

Yes, Phillip, I think, generally, definitely agree with you there, Kaes. You look at geology obviously matters and Diamondback's position within the basin is very favorable. But I think if you dig into the details there, you'll find differences in development styles between operators just within similar geology. And I think we feel like the Diamondback development style is differential and really optimizes the return for every DSU and every dollar that we're investing there.

I'm going to return to the theme around traffic lights. If I contrast the weeks where you wrote the 1Q shareholder letter around the weeks after Liberation Day versus you writing the shareholder letter now, the difference is Liberation Day was new. It was very kind of unusual strange environment. And right now, we're just kind of in a normal typical oil down cycle, and therefore, you have more confidence in taking that CapEx right. Is that CapEx up. Is that a fair assessment?

Yes, Bob, I think that's fair. Naturally, we don't like change, especially when it's sudden and unexpected. I wouldn’t describe Liberation Day as a black swan event for our industry, but it was certainly an unexpected shift compared to what we anticipated at the start of the year. High level, we were concerned about the demand shock that Liberation Day's numbers suggested. Fortunately, that didn't materialize in terms of trade and global commerce, but it remains to be seen. Overall, we became more comfortable with demand and experienced less of a supply shock. This is why I said that we need to accept the situation and focus on finding ways to generate more profit, despite the macro challenges. Additionally, I hope that once we emerge from this cycle, our long-term shareholders will reflect on how Diamondback navigated this downturn, no matter how severe it may be. If they see that we maintained our balance sheet, repurchased shares, paid dividends, and managed to keep production stable, that would serve as a testament to our new business model that emphasizes low reinvestment rates and high free cash flow. Our business will always have some volatility, but our actions throughout this cycle may have helped reduce that volatility.

Very clear. On the follow-up, you are achieving just over four zones per well, with the key contributors being the Middle Spraberry, Lower Spraberry, and the Wolfcamp A and B. Year-to-date, 6% of your wells are producing from other zones. Is this part of a development strategy or an exploration strategy? Are you gaining insights, or are you simply incorporating that additional zone into your established production model?

Yes. I mean Al can give some details. At high level, most of that is moving into development. There are zones we've tested, but zones like the Upper Spraberry and the Wolfcamp D starting to get more capital while seeing less impact on overall productivity, I think, is a good thing for inventory duration.

Yes, Bob, it's really a combination of both of those strategies, like Kaes mentioned, the Upper Spraberry, Wolfcamp D, where those zones are prospective, we're really allocating capital to those and co-developing them with the more traditional sort of co-development zones within the Midland Basin. I think the other piece of that is a resource expansion story and looking at some of the deeper zones like the Barnett and the Woodford and delineating those around the basin. And, yes, I think we're really excited about the results of those two zones and have some really promising well performance that will be public coming pretty soon.

Kaes, you obviously mentioned you hit your target asset sales. At this point, how do you view the equity ownership of those various interests you have? And maybe specifically on Deep Blue, where there are future capital calls, like strategically, does it make sense to own them? Is there a monetization opportunity there?

Yes, I believe the strategy at Deep Blue is progressing very well. They have done an excellent job of developing the third-party business, which we might not have pursued if it were fully owned by Diamondback. Overall, we are satisfied with our 30% ownership. There seems to be growing market interest in water and water management across the basin, which is beneficial for valuations. Additionally, I see potential opportunities for Deep Blue concerning water for power requirements and some surface use management we can collaborate on with our partners at Diamondback. Overall, we are pleased with the 30%. At some point, this business will either be monetized or change from being a major private investment. For now, they are generating substantial value behind the scenes.

Got it. And the capital range you generally get for maintenance, any kind of equity interest capital call would be sort of included in that? Or would that be outside of that?

That'll be outside of that, but we haven't seen one of those in a long time.

Got it. Okay. And my follow-up question is just about targeting zones and what you're all doing. But with 2026, is there any shift in activity allocation across acreage regionally within the Midland, or does the Delaware get attention? Do zones such as the Woodford and Barnett receive more focus as well?

Yes, I think at the high level, the Delaware is going to get less attention even than this year. We're pretty well held over there. And most of the development sits further down in our development stack. But I do think you'll continue to see, like you can see on Slide 15, the average percentage by zone in the Midland Basin continue to evolve with new zones being added in. And the challenge for the team is continuing to improve well productivity despite adding what people perceive as lower quality zones. But I do think we also have some more Barnett and Woodford tests and we look forward to a full kind of asset update on that zone at some point next year. Al, do you want to add anything on testing those zones?

No, I think that's right. I mean I think you'll see us continue to delineate those zones around the Midland Basin. And for '26, I would expect that percentage to tick up kind of like you've seen over the past couple of years as we figure out where the best well performance is throughout the basin and allocate capital appropriately.

I want to follow up on the topic of maintenance capital at $925 million per quarter. Wondering if you can put some definition around that because headline production has moved around quite a bit in the last 18 months. So what is the associated maintenance oil production level maybe on an operated basis associated with that? And then is this spend level inclusive of all the ratable non-D&C spend?

Yes, Kalei, I mean, high level, right, it's some range of Q4. We recognize that if the company stays flat for the following year, which is maybe the base case today, we'll see what happens in the next couple of months. We recognize that the Street likes to take Q4 numbers and multiply them by four. And that's kind of why we put capital out there where it is. I still think there's a lot of things that could go our way, efficiencies, steel prices, et cetera, that we have no visibility into today. But high level, total DC&E plus non-DC&E CapEx is going to be somewhere in that range of outcomes we put out for Q4 multiplied by four. And I think if you normalize to where we were going into the year, right, last year, we were going to spend $4 billion for nearly 500,000 barrels of oil a day, and now we're going to spend somewhere in the range of less than that for about 510,000 barrels of oil a day. And I think I put that capital efficiency up with anyone as well as any year outside of this year in Diamondback's history.

We definitely do like modeling by multiplying by four. For my second question, I appreciate that there's a lot of uncertainty around the '26 oil macro. But you guys do have a very large DUC backlog that gives you a lot of flexibility to shape a range of production outcomes for next year. So can you give us an update on where you expect to be with that backlog at year-end? And then talk about activating that. Do you intend to reach into that bucket as you kind of reset the efficiency in your frac operations through what you guys are calling continuous drilling? Or do you actually need to add another frac to tap all those opportunities?

On the continuous pumping aspect, the exciting part is that we are likely using one less crew on an annual basis. Regarding the DUC backlog, with oil prices remaining stable throughout the year and our efficiencies improving, we have actually drilled more wells than we initially anticipated. We are still in a strong position to utilize that DUC lever if necessary. There is a lot happening behind the scenes to ensure we execute flawlessly and meet our targets; what may seem easy externally is quite challenging internally. I believe that maintaining the DUC backlog provides us with a structural advantage, especially given our size and scale, and we are installing pipelines at costs comparable to the COVID era, making this a worthwhile use of capital.

Kaes, in your shareholder letter, you mentioned the benefits of the Sitio acquisition for Viper and the potential M&A market for minerals and royalties. I wonder if you could just kind of expand on the benefits you see to FANG beyond just the cash flow contributions for the minerals.

Yes, I think, I won't say for the first time, but I do think there's a huge asset at Viper that pays dividends at FANG that's not just royalty interest, and that's this private data, right? We have private well level data on half of the wells in the Permian. I mean probably every major development or every major change in development is something we can see on a private level. And I think for the engineers that allows us to study others faster than anybody else. It also allows us to change how we do things faster than anybody else. And I think as the basin evolves, companies are going to be testing different things, some riskier than others and some things are going to work and some things aren't, and we can replicate that very quickly at scale at Diamondback. Al, do you want to add anything to that?

I believe it's a significant advantage, as Kaes mentioned, to have access to private data that enables us to understand not only the development activities of other operators but also their well-level performance and returns. This sets us apart from any other data source available.

I appreciate the details you provided. For my follow-up, you mentioned that currently, 70% of your gas volumes are going to Waha, and you anticipate that by the end of 2026, this will decrease to 40%. Could you explain where that gas will be redirected if it's not going to Waha?

Yes, we will be connected to two new pipelines next year. Currently, we have sufficient capacity on Whistler and Blackcomb, and what is the WhiteWater pipeline that will be available next year?

Blackcomb.

Sorry, one Whistler, Matterhorn today. Blackcomb comes on next year, that's another probably 200, 250 a day. And then post Energy Transfer buying WTG, which we were an investor in, we've decided to work with them and commit some gas to that Hugh Brinson pipeline going east. And I think we've also then saved some gas to potentially go west should one of those pipelines get built and we have an opportunity to put gas on it or contribute a good amount of gas to a power project. And I think our investors demand us to do better on our gas realization and we've listened to them, and I think it's coming.

I wanted to go back to the question about the core inventory and the co-development. Obviously, when you talk about core, I think we've touched on this a couple of years ago, and I just wanted to get an update. When you talk about core, you're generally talking about your best inventory, but in the co-development, you're obviously bringing in lower than Tier 1 locations, I guess. So when we think about the 10 years of core inventory, what does that look like on a development cadence? In other words, is it 14, 15? Or how do you think about it?

Yes, I'll let Al explain what we consider to be core. Overall, we are completing about 500 wells a year and have around 5,000 to 5,500 core locations, which I view as sub-40 inventory. While there are additional inventory options that could emerge at higher oil prices, this is the inventory we would analyze for acquisitions and the inventory we are actively developing today.

Yes, Doug, when we consider how to design a Development Spacing Unit, we prioritize the zones with the highest rate of return first. We also assess the zones that we can co-develop without interfering with the high-return areas. Our approach to the Development Spacing Unit focuses on optimizing the landing points in the zones being developed, ensuring that we do not compromise the well performance of other lower-tier horizons while developing the core zones. We aim to optimize our efforts to avoid leaving behind underperforming wells that we would later have to revisit, as they would suffer significantly from an economic perspective.

Yes. It's a use it or lose it situation like given the tank nature of the Midland Basin. And I think as Danny would say, we drill every fourth well for free relative to peers, and that allows us to add those zones and developments where others are not.

So would that uplift the 10 years to a bigger number then? Or is that included in the 500 per year?

It's a dynamic number, right? I mean there's going to be more wells added to it next year. I think the Barnett and Woodford will probably, given recent results, be, in my mind, a Tier 1 development zone. There needs to be more well control and proof, but that's what we're working on every day. Yes, we have outlined the new pipelines that we will be using once they begin operations at the end of 2026. To provide some context, our company has grown primarily through acquisitions, which means much of the land we acquired was already allocated to the sister midstream companies of our upstream division. We have been addressing that issue. With Endeavor, we have a significant amount of flexibility to make choices that can push us further downstream, which has been advantageous. We now have the scale necessary to engage with various pipelines to access different markets. Our focus will be on ensuring we have a diverse range of markets downstream, along with the exciting potential of the power kicker as a benefit. Long-term, I believe we are making the right decisions. The next 12 months may not be ideal, but we've safeguarded ourselves with hedges since we cannot control the molecules downstream. However, that situation is changing.

I just had a quick follow-up on the continuous pumping. Just wondering how many fleets it's deployed on today? And I think you're running five if memory serves and sort of how many will be rolled out in the next couple of quarters as you get to full deployment?

Geoff, yes, we're running two today and planning on converting the additional fleets as soon as possible, as soon as we can get all the equipment lined out. So hopefully, in the next quarter. And anticipate that we'll probably kind of run four full-time fleets with the fifth fleet bouncing in and out as needed in a maintenance type scenario.

Excellent. Could you provide an update on the base production work you discussed last quarter? Have there been any changes or improvements in what you're observing?

Yes. We continue to allocate capital into working over wells, older wells and optimizing the PDP tail and been really excited about some of the stuff we've seen, some of the results we've seen out of our acidization, oxidation, stimulation work. We're also trialing some other chemistries that we're doing some stimulation work downhole with and seeing some encouraging results early on. We don't have enough data yet to really talk about anything, but we continue to focus on optimizing the tail and deploying capital there. And we feel like it's some of the highest return capital we can spend, albeit not large numbers. But if we can do the work to delineate what's working, we can scale it and hopefully become a significant part of our capital deployment in forward years.

Yes, I think that's also huge potential upside is as some of this work gets done and developed, can you lower your reinvestment rate? Can you move more dollars from the D&C side to post-completion work or production work and lower that capital need to replace your production every year. And I kind of said something in the letter, never underestimate the American engineer, and we got a lot of engineers here working on the tail end of our production as that becomes a much more important part of our plan here.

You guys laid out certainly the case for yellow light and certainly talked about a bit how you might get back to the green light. I was hoping you could provide maybe a little bit more commentary on what you would kind of view a red light scenario as you roll into 2026 at this point in terms of kind of costs and oil prices, any kind of high-level sort of indications to help would be great.

Yes, Leo, it's really just about the oil price, right? If we start seeing consecutive months in the $50 range and a month with oil near $50, everyone should evaluate their plans and consider whether to defer capital at these prices. Fortunately, given Diamondback's current position, we don't need to be the first to make that decision. We can assess it behind the scenes. So far this year, we've been executing at $63 oil with a reinvestment ratio of 36% to 37%. That's a very solid position to be in. Our dividend is not at risk; in fact, it likely has room to grow. Our balance sheet is strong, we are managing our maturities, and our costs are at COVID lows. Overall, we're doing everything necessary to be prepared for tougher times while also ready to excel when conditions improve.

Okay. And then obviously, the yellow light scenario, you guys have detailed kind of a number of strategies. I wanted to kind of get a sense, just given the low reinvestment rate, obviously, kind of how other uses of capital may come into play here. The buybacks were very healthy this quarter, which is certainly nice to see. But also wanted to see if you think in the yellow light scenario, perhaps other type of acquisitions, bolt-ons or whatever may emerge that also could benefit the company. So maybe just talk a little bit about M&A use of kind of free cash flow there. And it certainly seems like the buyback is going to continue to stay pretty healthy. I just wanted to confirm that.

Yes. I believe the main use of free cash is still the base dividend. The second priority is buying back about 1% of our public float each quarter, which also requires free cash for other initiatives. After that, the main focus would be to continue paying down debt. We are still pursuing some small acquisitions here and there. There are significant projects we are working on that may not involve cash but are very value-enhancing. We are not remaining idle; there are numerous opportunities for us ahead. We are fortunate to maintain a high working interest in all our developments. Viper is continuing to expand its business. However, regarding large mergers and acquisitions, I believe Diamondback will be more selective. You may have noticed some deals occurring without our involvement, and I think we are in a strong position.

Kaes, just curious that if we're looking at your program today, what percentage of the well that you are in the 3 miles or longer? And if we're looking at over the next several years based on your existing land position, how that program may shift? Second is that one of your much larger person is talking about their proprietary technology using a lightweight proponent and that will help them to improve their recovery rate maybe by, say, up to 30%. I want to see if you guys have looked at that out there? Is there anything similar in the market you can deploy or test it or that this is truly proprietary that, that's really nothing out there that you guys will be able to deploy?

Yes, Al can take the longer laterals and talk about what we've been working on. I'll take the second one.

Paul, yes. So looking at the '25 plan, 3-mile laterals and longer. It makes up about 20%, 25% of the total program. And really, I think the exciting part is kind of pushing to those extended laterals, right? So about 6% of the total is actually 17,500 or 20,000.

Yes. I think we've done some things on the longer laterals with different casing designs and pumping plans to improve results on the longer laterals over time. And then on your second question, listen, I think it's great that there's a lot of technology being tested out in the basin. I wouldn't sleep on our ability to continue to test different technologies to not only improve recoveries on the front end, but also as wells deplete, increasing those recoveries longer that Danny talked about later in the tail and maybe some other things that we're working on as a group that we look forward to updating the market on. But I'd just say, Paul, in Slide 8, the results speak for themselves, and we're very proud of what we do at the cost structure we execute at. And those are the decisions we make to maximize returns and NPV per section.

Great. And on my first question, when you're saying that it's 20%, 25% of 3-mile plus for 2025 over the next several years that how that progress is going to look like?

Yes, it continues to grow, and we keep pushing lateral length. One thing we are observing is how some competitors in the basin are innovating with lateral length in drilling units using U-turn wells and J-hook wells. We are considering how we can apply this to longer drilling units to extend lateral lengths beyond 3 miles. They are currently converting a 5,000-foot drilling unit into a 10,000-foot unit, but we are really contemplating if we can take a 10,000-foot unit and make it a 20,000-foot unit. As operators continue to push the boundaries, we will monitor their progress and adopt this technology quickly if we can do it successfully while also reducing breakeven costs.

Do you think that you can get to, say, 50% over the next 5 years?

Never doubt us, but I think today, it's hard to...

You have a lot of front engineers.

Yes. However, I believe that next year we expect lateral lengths to increase, and we will continue to work on trades and other strategies to maximize their length.

Thanks, everybody, for taking the time today. We're always available to answer any questions you might have, and we'll talk to you in a few quarters or in a quarter.