Diamondback Energy, Inc. (FANG) Q2 2026 Earnings Report, Transcript and Summary

Good day, and thank you for standing by. Welcome to the Diamondback Energy Second Quarter 2026 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the call over to your host today, Adam Lawlis, VP of Investor Relations. Adam, please go ahead.

Thank you, Grace. Good morning, and welcome to Diamondback Energy's Second Quarter 2026 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; Jere Thompson, CFO; and Al Barkmann, Chief Engineer. 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.

Good morning, everyone, and I hope everybody read our shareholder letter last night. It continues to get good feedback from the investment community. And as we've done over the last couple of years, we're just going to move straight into Q&A. So operator, please open the line up for questions.

[Operator Instructions] Our first question comes from the line of Neal Dingmann with William Blair.

Happy birthday Kaes, from me and the coach. Turning to my first question. I really want to talk about your macro view, specifically, your remarks last night. You seem to indicate your thoughts that worldwide inventory levels will remain low for the foreseeable future. So as such, am I correct in thinking that you all will continue to strategically grow production well into '27, given this low inventory backdrop and positive oil backdrop?

Yes, Neal, I think it's been pretty hard to predict what's going to happen globally with -- over the last couple of months. Certainly, our opinion and the data shows that inventories are draining not only on the oil side, but on the product side. And absent permanent demand destruction, which we're hopeful is not the case, those inventories are going to have to be refilled. And we can debate at what price those inventories need to be refilled, but I do think that helps us get some confidence that there's a bid for -- a longer-term bid for oil to refill those inventories and meet global demand. So in general, I think that does skew us towards the decision to grow production versus hold production flat. We were the first to respond to the price signals in March to increase our production for the year by 3% or 4% versus original plan. The team executed on that very, very quickly to where we are today, up somewhere around 4% from where we started the year. And I think the goalposts are for us going into next year, do we hold production flat, which we're kind of doing from these higher elevated levels right now in Q3, or do we grow organically off of this number in a capital-efficient way. And right now, the model spits out some form of low single-digit organic growth while maintaining capital efficiency and running 5 frac crews consistently throughout the year. So I think in today's environment, betting on the need to refill inventories, that's probably where our head is today. But as you've seen in the past, Diamondback can react quickly to the positive or the negative. And I think in this environment, it's prudent to be able to do that. So there's a lot of uncertainty out there, Neal. I think our bet is that these global inventories, including SPRs, are going to need to be refilled. And that should be a positive for Diamondback shareholders and Diamondback's growth trajectory.

Great points, Kaes. And then just secondly, turning to well productivity, definitely shown on your recent Slide 10. To me, what seems most intriguing there is not only the high productivity you have, but you're doing this by -- I'm looking at the left side of the slide also why it sort of seems like maximizing value. You're targeting the most zones, wells per section and I think what you all would say probably the most appropriate completion levels. So I'm just wondering, could you talk about how you're able to sort of target these, the leading productivity, while maximizing value.

Yes. I mean, I think Slide 10 is the most important slide in our deck when it comes to the technical aspects of our business and how we're making capital allocation decisions in the field. So it's been in there for a couple of quarters now, and we've put in some data on year-to-date performance. And clearly, we're having a good year in 2026 so far. And I kind of kind of steal a comment from one of our competitors because I think his comment is smart in that this is kind of a stacked innovation play, right? We've done a lot of things in terms of well construction, well targeting, stimulation and that's leading to better results. And we didn't get here overnight, right? We started by drilling wells in 30 days. Now we're drilling them in 5. But our culture and our organization is a continuous improvement culture that has led to these results today. So high level, we try to blend the best mix of most wells per section, right on the bottom left of that slide, multiplied by the most production per well. And clearly, Diamondback operates at the lowest cost per well, and that should generate or does generate the most NPV per section or acre or asset in the basin. And we're very proud of that, and we got to keep working on that to continuously improve the business. Al, do you want to add anything on what we've changed and done over the last couple of years?

Yes. I mean, like you said, I think it's really about maximizing the return on every DSU, every well that we put in the DSU, Neal. I mean the specifics when you think about well construction, doing larger tubulars that allows us to flow the wells back more aggressively on the stimulation side, stage architecture and perforating. And then on the targeting side, the technical teams taking a deep dive, looking at how we target every well within the DSU, I think is what we're seeing leading to the outperformance on the page here.

Yes. So it's a lot of little wins, Neal. We got to stack up those little wins and keep doing that to maintain our position.

Our next question comes from the line of Neil Mehta with Goldman Sachs.

I guess the first question is just on the gas side. Waha has firmed up a little bit. So just how are you thinking about egress out of the basin recognizing this is probably a problem that will percolate again. But does this create some near-term relief? And then as you think about your gas strategy in general, maybe you can -- it's a good opportunity for you to update the market on where you stand around the data center side and the power side of your business.

Yes, Neil, anything is relief compared to Q2. So we're happy to see these new pipes start to flow, and we've seen some announcements from both Energy Transfer and WhiteWater that the 2 big pipes are moving forward. That's resulted in Waha being positive for the whole month of July and certainly a nice tailwind for us and for our shareholders in the near term. But I'll take it a little higher level because I think we believe in the gas mega theme. It's not core to Diamondback's value proposition, but it can be additive to the amount of oil we produce. And in general, I think that means us owning more space to the Gulf Coast, and we can debate where that needs to go in the Gulf Coast. But certainly, the large demand centers are going to be along those pipelines for either power projects or data centers. And then the rest of the gas that gets to the Gulf Coast is going to cross the dock in the LNG terminals. And I think I'm not smart enough to figure this out today, but the question is going to be how much demand can the world handle from an LNG perspective because we're certainly going to have enough supply coming out of the U.S. on the LNG side. And to fill that, I think the Permian is going to play a big role. And I think Diamondback is going to play a big role. So our gas production continues to outperform expectations. I think that will continue over the next 10-plus years. And therefore, we need to have more contracted space to more markets to be in the conversation when the LNG offtakers need supply. So we're meeting new people in that world and building relationships because I do think kind of the wellhead to water gas strategy has to be part of the Diamondback proposition. On top of that, we also believe in the power of data center mega theme, and we have a project that we've been working on, and Jere is going to give you some color on where we are.

Yes, Neil. Great question. For some background, we and our IPP partner have put together what we view as a very unique bridge-to-grid solution on our 30,000-acre Bryant Ranch location, ultimately to deliver scalable, reliable power near Midland, Texas. We have secured distributed power generation, remediated land and directed access to dedicated nat gas and water supply. All of this should allow us to provide a shovel-ready development project, delivering first gas as soon as the back half of 2027 through the use of behind-the-meter recip units. Beyond this initial phase of power generation, we are working to secure grid connected power as soon as 2028 via Batch Zero. We believe we are well positioned within the Batch Zero queue and are awaiting ERCOT's final determination regarding project eligibility for the next interconnection study as soon as their meeting on August 20. We are closely monitoring communication out of Austin and remain confident in a project like ours with low water use and new generation, ultimately meeting Batch Zero standards. We'll give the market a larger update once we sign the definitive documentation with the hyperscaler, but are confident in the direction that this project is going.

Neil, I'll add one thing. I was in a room with a lot of the tech world about 1.5 years ago. It's kind of a mix of energy and tech. And the energy side of the equation kind of got laughed out of the room when we suggested to come to West Texas and build behind the meter. And someone who was in that meeting called me last week and was -- and reminded me of that and said, "I'm coming to West Texas, and I want to build behind the meter." So I do think we offer a lot of opportunity out here. At the end of the day, Diamondback is going to stay in our lane, which is produce the molecules, deal with the -- produce -- provide the surface, provide the water, provide the industry know-how. We're not a power company. We're not a data center company, but we certainly can play an important role in this ecosystem that's coming together.

Yes. That's a really helpful update, and we'll stay tuned for more. And then Kaes, just maybe give the market an update around how you're thinking about return of capital. I think you adopted a little bit more of a flexible strategy or way of updating the market. How do you approach it in 2Q? How are you thinking about the balance of the year? And talk about that in the context of your largest shareholder, too.

Yes. So let me just frame the goal, right? The goal for us is to maximize and capitalize on the option value that is inherent in this business, right? We live in a very volatile business where things can change overnight. And we felt that a formula or any sort of restriction on capital allocation does not allow for the maximization of that option value. So that's why we -- last quarter, as prices rose, we said, listen, we're not going to commit to returning a minimum percentage of free cash just because we have to. And we removed that minimum commitment. And there's a lot of discussion on the call about it. There was a lot of discussion in the couple of days afterwards with shareholders, explaining our case, and they were very supportive. And -- since then, I have not heard a lot about it from long-only shareholders. They've been supportive. And then you look at what we did, right? So we did allocate a little bit to the buyback in Q2 as weakness stepped in at the end of the quarter. We've allocated a little bit to the buyback here in Q3. You can see that those numbers that we're willing to buy back at have gone up. But we also reduced net debt by $1.6 billion. And that translates to $5.60 a share of value that went from the debt side of the equation to the equity side because, in my mind, our NAV wasn't -- didn't go down much in the second quarter. In fact, it went up. So I think it's more about look at what we've done versus what we're going to do. And I do think investors know that we will lean in on the buyback when it presents itself. If you look at a year like 2025, we bought back over 5% of our stock. I wish it was 10%, right? And now I think we're positioning the balance sheet to be in a position where we actually can lean on it to buy back shares when the cycle turns in this volatile business. So really just trying to make the right capital allocation decision every day. And just like the stacked innovation in the field, if we can stack up those wins on return of capital, I think that's a long-term win for our shareholders.

Our next question comes from the line of Scott Hanold from RBC Capital Markets.

I was wondering if you could delve into some of the production performance a little bit. You all are delivering more than -- oil barrels than I guess guided to, but nat gas is really outperforming. And can you just give us a sense of why you think that is? Are you just being conservative with gas expectation? Or is there any kind of zone targeting that's different that would cause that? And where do you see that going moving forward?

Scott, it's Danny. Great question. I think it's multiple different things. I'll let Al talk on the technicals. But I think just the biggest driver has been really an improvement in our ability to market our gas locally. As the G&Ps have continued to mature their systems and build in redundancy, and we've worked with our gathering and processing partners to add split connects in really strategic areas. We've really improved on our flaring metrics and thus, we've improved in our gas processing and selling gas. It doesn't feel good to sell it at a negative price, but we've gotten to a point where we've really gotten a lot better at marketing the gas downstream. And that's the biggest needle mover. And I'll let Al cover any other of the technical background on the gas number.

Yes, not really much in terms of well selection in this quarter associated with the gas production. We brought on a couple of pads in the southern end of the Midland Basin that were a little higher GOR, but that really didn't drive the beat on gas. It's really related to what Danny mentioned before. But with the targeting of the Barnett, and the Barnett becoming a bigger portion of the development plan moving forward, I would expect to see that number kind of creep up a little bit.

And then my follow-up is, if you can give us some -- a lens into what you're all seeing on the oilfield service cost front, any kind of inflation pressures? And when you look at this higher production base you're running at, when you think about like -- I don't know if it's good to think about like just kind of a steady-state maintenance pace exiting this year? Like what is the quarterly capital run rate you all see right now?

Yes, another good question. I think we have optics into some inflation mainly tied to some of our consumables. Obviously, we talked about fuel costs in the past with the rise in commodity prices, and that's still here. Thankfully, we -- our biggest fuel consumption would be on the completion side with the frac fleets, but all of our frac fleets are currently electric fleets. So we've kind of mitigated that inflation hurdle through utilizing the electric fleets. What we've seen -- what we're seeing in the future, casing prices in the back half of the year are going to come up. And that's really the big needle mover. We think it's about 1% -- a little over 1% of our total well cost and inflation. So not much, and we think we can offset it with efficiency gains. It's a little early to talk about '27, but I think somewhere around $1 billion to a little over $1 billion a quarter run rate to hold production flat is reasonable with what we see today. But if we continue to add rigs in the U.S., and I think we're up 60 rigs from the bottom, if we continue to go and there's some forecast out there up to 80-ish rigs being picked up, we anticipate we're going to see some more pressure. But time will tell and what happens in the gas basins, along with what happens in the oil basins, what activity does. And as we get closer to '27, we'll be able to talk to you guys more about what we anticipate inflation to do. But right now, that's where we're at, and we're going to try and fight the variable cost side of it, like we've always done and drive efficiencies to reclaim any inflation we see on the consumable side.

Our next question comes from the line of Arun Jayaram from JPMorgan.

I was wondering if you could provide an update on what's going on in the field with the Barnett. It looks like you're running 3 or 4 rigs targeting that play right now in the basin. But I was just kind of interested on your focus on reducing cost, call it, from $1,000 a foot to $800? And how you plan to lean into that program in 2027?

Yes, Arun. I mean stepping back to earlier this year, we did a big reveal on our Barnett position. Since then, that position has continued to grow, continue to block it up as well so that we can have longer lateral development as we start developing the position aggressively, basically now. Our first 4-well pad in Spanish Trail has been drilled and will be completed in the next couple of months. So it will be interesting to see full section results kind of end of the year into next year. Obviously, with the Viper minerals, that's going to be a very high-return project. And that will also give us a really good idea into the cost side, right? I mean since the beginning, it's been a couple of wells here, a couple of wells there. We haven't done a full section with an e-fleet simul-frac crew getting the cost down on the completion side. I will say, we're seeing wins on the drilling side. I think we're more on our front foot than anybody else in the basin on Barnett exposure and drilling costs. And they're getting closer to $400 a foot. I think we have 5% or 10% to go. There have been a couple of wells below $400 a foot, but I think we expect to consistently get to around that $400 or less per foot number to make returns competitive with the base plan.

Got it. Got it. Okay. And then my follow-up, I was wondering if you could give us some details on how the enhanced oil recovery program. I know you did a pilot of 50 wells, and I think you're expanding that pilot to another batch of wells. Maybe just give a little bit of an update on what kind of well productivity improvement you've seen from chemicals and surfactants? And do you plan to evolve that program into new completions?

Yes. So I mean, just like we think the gas, power, AI theme is a mega theme, I think on the oil side, enhanced recovery or improving recoveries out of this basin is going to be a mega theme as well on the oil front. I think generally, given our size and scale and asset base, we certainly need to be -- as we said in the letter, we need to be on our front foot on this. I don't think we need to be tip of the spear, but we certainly need to be spending dollars to understand what's happening, and that project kicked off last year with our first surfactant program where we learned a lot. And I'll let Al update you on what we're seeing today and what we expect in the future. But my high level is you're going to hear a lot about all this kind of stuff from large operators over the coming years.

Yes, Arun, we -- so we executed a 12-well project this quarter and are in the process of flowing those wells back currently. The initial results are very positive. And I think we're going to take the learnings from this batch of wells in terms of what rock type, what reservoirs this technology is really suitable for and take those learnings and apply it to the next group of wells that we'll be doing in Q3. So I think we're just scratching the surface on the potential for this technology, and we're really excited about it going forward.

Yes. I think there's 2 ways to think about it. I think it either reduces your base decline or it's a replacement of capital for something that's higher returning. To date, we've only done remedial work where we go back in existing wellbores to learn about this treatment process, but we are now also incorporating it into some of our pads where we have -- on the new well side, where we have a control half of the section and a surfactant half of the section. So moving with haste and learning a lot pretty quickly here.

Our next question comes from the line of John Freeman with Raymond James.

You highlighted a number of impressive operational achievements in the letter. And the one that really stood out for me is just that first full quarter of continuous pumping over 21 hours of average pumping time per day, which is kind of hard for me to even wrap my head around. But just sort of what's like achievable there? I mean like is it like in a couple of years? Or are we going to be talking about something that's boring on close to like 24 hours or something? Just trying to understand what's even -- what's achievable there.

John, yes, thanks. Great question. We continue to try and push the manufacturing mode kind of mindset with regards to the surface operations on the completion. And I think there's 24 hours in a day. So I don't think the team is going to quit until they can get to a point where they're pumping a full 24 hours. But in reality, there is maintenance associated with the equipment on location and every piece of redundancy costs money. So there's a balance between adding more equipment out there to get redundancy and how many hours in a day you're pumping. And that's been the fight with the team on doing trimul-frac work versus simul-frac work and those things. But they continue to look at how do they push efficiency, push pumping hours and push rate to get more done in a single day. I think we've seen some pads that we've broached the 5,000-plus foot a day on average. And I think that's kind of the next bogey for us is how do we get to achieving 5,000 feet per day across all of our crews every day. And so I do think that's achievable and something that we can hopefully talk about in the next year or so when they get to that point. But they're working on it. They're applying new technology at the surface and it continues to get better.

And then just one housekeeping item. It looks like there was some bolt-on sort of acquisitions during the quarter. It looks like kind of net of divestitures like $385 million. Is there any production that was associated with those transactions? Just anything else we should be aware of?

Yes. Very little, John. I mean, we're continuing this -- the Barnett leasing play with our partners at Double Eagle. So that's continuing onward. And I'd say outside of that, I've actually been very pleased that the team has been finding, call it, $20 million to $100 million deals to either net up or extend laterals or block up our position. And they've been finding them pretty consistently. I mean, about kind of one sizable deal a quarter. And I think looking into Q3, we got another couple of small ones. So those don't get headlines, but they add up, right? All of this ties into our corporate NAV, higher working interest, longer laterals should result in a higher stock price. I think we're done with cash, right? Done with cash, which is important, John. And the thing I'll say about the Barnett position we built, we built that at a very low cost of entry with cash. And that position is worth multiples of that today, and that should just accrue directly to shareholders.

Our next question comes from the line of Phillip Jungwirth at BMO.

I'm curious when you look at the mid-cycle NAV, which I think you mentioned earlier, you feel like went up during the quarter. Obviously, oil price is the main driver here. I think you conservatively use around $65. But the question is more just how much do you think some of the operational improvements and resource expansion initiatives you've achieved can contribute to a higher NAV plus just more volumes or growth. So just wondering how meaningful overall these are based on your assessments to value and whether improvements in the business can contribute to the thought process around intrinsic value and future capital returns.

Yes, it's a great question. They 100% do, and I'll take you down a little bit down memory lane here. We put our buyback program in place post-COVID at, I think, Q3 of 2021, and we told investors we were going to buy back shares at a mid-cycle price at a rate of return above our cost of capital. And that initial top was $90 a share. And here we are 5 years later, we've obviously done a lot in terms of M&A. The asset base has expanded from a zone perspective, things like the Barnett, things like Jo Mill, Middle Spraberry weren't big things in 2021, Upper Spraberry. Obviously, the cost structure, the lateral lengths. I mean everything that the team has done in terms of execution in the field, but also adding to the asset base in an accretive manner has resulted in that top going up significantly, more than doubling since that moment. So people ask me what's the future value creation opportunities for Diamondback. And you look back 5 years ago, and you say we doubled the value of the company at the same parameters, right? We've stuck to our guns on what we think mid-cycle is from a price perspective. We've stuck to our guns on what the rate of return is. But the rest of the business has driven those improvements, and I expect that to continue.

That's great. And then on the shovel-ready power project, where is the most value creation for Diamondback on a project like this? Is it more utilizing the surface acreage, the gas supply deal or partnering on the data center cooling, which I assume would be deep blue, but let me know if you're thinking of it otherwise. And any color you could provide around the distributed power piece that you referenced earlier?

Yes, Phillip, it's Jere. A great question. I think the biggest driver for us is just having a new in-basin egress solution for nat gas. We're setting aside 200 to 250 million a day for this project. And you think about contract structure, ideally, you're getting something that's like a Waha plus with a floor. And for us, based off of what we've seen over the past couple of quarters, this would provide a material uplift. You're exactly right. As it relates to the other revenue streams, this could have a material benefit for Deep Blue, of which we own 30%. There's some land proceeds that likely could come through the door, either as a onetime payment or structured as a royalty. And these are just kind of scratching the surface of what we're seeing. So really excited about it. But I think nat gas is the one that we're focused on.

Yes. I think the one thing I'd say is we -- this is the first step in what I think will be a long process, right? This is us planting our flag, proving we can do this. We can make money for our shareholders, but also partner across this tech space. And I think it can be repeatable. You get one of these done. You have a blueprint to get round 2, round 3. And if you hear the numbers that the tech guys throw about in terms of what kind of power needs they have, this could be meaningful over time for Diamondback.

Our next question comes from the line of Kevin MacCurdy with Pickering Energy.

I guess for the first question, I'll stick on the operation front. Maybe you can expand a little bit on what you saw on productivity and costs on the U-turn wells and how you might be integrating that into your plan heading forward?

Yes. So great question. We haven't completed the 6 wells that we've drilled thus far. We're still in the middle of developing that pad. I think on the drilling front, it was certainly a success for us. There are some things that we learned and some challenges we saw, but we still saw lower per foot well cost than drilling stand-alone 7,500 footers. We've completed some U-turn wells that we inherited from an acquisition, and those were short 5,000-foot U-turns to 10,000-foot total lateral length and everything went great on the completion front with those. But this will be our first fully developed Diamondback pad. We just haven't gotten it on production yet. But as far as the pad we inherited productivity-wise and execution-wise, it was in line with what we would see from a regular straight 10,000-foot well.

Great. And as a follow-up, maybe I'll hit on LOE. It looked like it fell below $6 a barrel and partially drove the EBITDA beat this quarter. You kind of talked about some of the reasons for that. Is there anything structural in there for that to continue? Or how are you viewing LOE for the rest of the year?

I think if you look at the top line OpEx number, the dollars were actually flat quarter-over-quarter. So the LOE beat was driven by the production beat. I think the team has done a really remarkable job of fighting off some of the cost pressures we're seeing from power, from water and doing the things that they can -- they do the little things they do to save $1 here and there that adds up. And I think we're still going to see -- I don't think we're going to see LOE trend down in the back half of the year. I think we like that kind of circling that $6 number or a little higher. But I think if we continue to see volume outperformance, we could see some upside to that number. But I do believe that some of this inflation stuff we have on power and water and tubulars will flow through on the top line LOE number as well. So the team feels pretty confident in that $6 range. But again, that denominator is a pretty big number. So it was just a great quarter on the productivity front and helped drive the beat on OpEx.

Yes. But I'd also say that the KPIs that we track that the team can control on LOE look as good as they've ever looked. And as well as some of the things we've done in the field post Endeavor integration, integrating 2 large field organizations takes a little longer than the office, but we're starting to see the benefits of that in terms of moving to a pump by exception company, a lot more automation. I think that AI is helping Diamondback in the office today, but I think AI is going to be an -- and automation are going to be very big drivers of the production base either shallowing or costing less to maintain.

Our next question comes from the line of Doug Leggate with Wolfe.

Kaes, I've got a couple of things. The first one, I want to take you back to your first comment about the trade-off between the balance sheet and your buybacks. I think you've been more vocal than most about avoiding procyclical share buybacks. But you could make -- you could do some serious damage to your balance sheet with the kind of free cash flow you're generating. So my question is, where are you prepared to take that to in terms of building cash on the balance sheet as opposed to going after debt redemptions, but actually just sitting cash to reduce net debt? That's my first question. And my follow-up very quickly is the capital efficiency is extraordinary. Your latest type curves are significantly above 2025. You've run through a number of reasons why that's happening. My question is, would you take the capital efficiency and lower your spending in '27? Or would you take the incremental production and keep the CapEx flat? And I know you talked a little bit about growth, but just curious on the trade-off between those 2 things as well.

Yes, both good questions. I think there's a near-term discussion and a long-term discussion on both of them. I think on the debate of taking productivity and reducing CapEx or increasing production, I think today -- in today's market, we made that decision to spend more within our budget, but growth as the output. I think there's going to be a debate throughout the year. Some years, it's going to be obvious to grow organically and some years are going to be like 2025 and 2024, where it made sense to cut the CapEx and return more cash to shareholders. So I think we'll maintain flexibility there, Doug. And I think that also then ties to your other question, which is where are we prepared to take the balance sheet. And I think that there's some near-term aspects that we want to cover, right? We want to put enough cash on the balance sheet to take care of our 2026s, which are callable in a couple of months and also take out our -- be prepared to take out our 2027s. And that puts us in a position where we could build cash beyond that to tackle the maturity tower we have kind of in the 2029 to 2032 time frame. So I'm certainly not afraid to put some cash on the balance sheet. I think it's a good idea, and it's prudent at this point in the cycle because we know that cycles turn. And the one thing I will say to give investors comfort is we're not building cash here to do big cash deals and blow up the balance sheet doing deals. That's not what we're here for. We're here to grow -- we still want to grow the business and look at opportunities. But if you look at our history of how we've done M&A, it's very rarely been a significant amount of cash in any of these deals.

Our next question comes from the line of Geoff Jay with Daniel Energy Partners.

Just wanted to follow up on what you said earlier, Kaes, about the deployment of AI and like predictive maintenance and remote sensing, et cetera. How far down the pike are you on that? And I guess, what's the time line look like to you kind of for the deployment of those technologies out there to try to even improve your uptime?

Yes. I'll let Chad or Danny give the details. I mean, I think on all of this stuff, we're in the first inning, right? There's just -- there's so much that we can spit ball and debate internally what could happen. I mean I think in 5 years, we're going to look back and say, we were such rookies at all this stuff, and it's going to be a huge help to our production base. But Chad, anything we're doing and seeing?

Yes. We're really excited about the progress, but it is incredibly early. We're tackling it first on artificial lift and using the AI and the automation to help manage that optimization on a day-to-day process, which is going really, really well for us. And then the team is doing a great job just managing downtime with some of these tools, and that's been an incredible value add. So still very early, but lots of room to run.

Yes, it's kind of a numerator/denominator thing, right? The lower downtime, lower spend, lower decline rate, okay, then we don't have to spend as much capital to sustain production. So I mean, just a 1% move in that decline rate which we've been fighting for a long time, it can make a big difference.

Our next question comes from the line of Paul Sankey with Sankey Research.

Can you hear me okay?

Yes, Paul, we got you.

Kaes, you mentioned the NAV. You were kind of coy about it, but you said that the NAV went up more or less during the quarter. Can you just talk a little bit more about how you think about the NAV now, particularly, first of all, obviously, on the upstream performance side. I don't know if you want to throw the oil price in there, but also the other businesses and whether or not it's still a key driver of buyback attractiveness?

Yes. I mean, high level, we try to keep price constant, right? Reducing your NAV by changing price, I don't think is the right way to look at it. So I think generally, Q2, we obviously generated a significant amount of free cash flow above that mid-cycle price. So that helps NAV. But I also think as we're looking at type curves and well performance and the Barnett development, the Barnett moved from something that had like a couple of hundred million dollars of value in our NAV to now a couple of billion. And so I think as those things continue to develop and we refine our analysis, the NAV should continue to go up if we're doing our job. I think on the other businesses, I don't -- certainly don't have any power value in our NAV. We do have a good amount of midstream value with our Deep Blue investment. It's been interesting to watch multiples expand on the water side of the equation as I think more attention gets brought to that business line in this basin. So I think we're going to be very money ahead on that investment. But all of that ties up together and a reduced share count and a lower net debt value pops out of a higher per share value.

Our next question comes from the line of Gabe Daoud with Truist.

Kaes, I was hoping maybe you could get a little more color on just the last point that you hit on, on the water side. Is there anything that you're seeing just given some of the changes the RRC has made to injection. Are you seeing any constraints at this point or maybe concerned about constraints moving forward?

Gabe, good question. I mean, we haven't seen anything yet in terms of constraints on our system. I mean, I think what this means is you have to have significant capacity. You have to have a large interconnected system. The days of 1 or 2 SWDs being hooked up to the system makes no sense. And I think we have that valuable partnership with Deep Blue, where they are investing capital to loop certain lines, connect certain areas, add SWD capacity to make sure that those issues don't happen to us. The water discussion is certainly getting a lot more attention in this basin. I think the Delaware Basin, obviously, given the amount of water produced there is working to solve these problems probably sooner than the Midland Basin will need to. But I think there's a lot of lessons and a lot of learnings that we're following from what those businesses are doing over there or companies are doing over there that we can translate over here. But in general, I would say, Deep Blue has used the asset base that we gave them with Diamondback as the anchor customer and done a great job adding third-party business and also working to connect the system and improve it.

That's helpful. And then just a follow-up. I think this year, you had non-D&C spend of $600 million across some science and midstream. Just curious how does that change into '27? Does the Barnett require any incremental midstream or facility spend that maybe we're not thinking of? Or is the answer there, no?

I think generally, the number will go up slightly. But within that number, the mix will move. As we get to large-scale Barnett development in areas where we don't have existing infrastructure, we're going to have to build new batteries. And we're working on that design and making that design tailored towards what a Barnett well looks like versus what Wolfberry wells look like. So as in any deal or any expansion, infrastructure capital is higher in the beginning and then reduces. But I think generally, that number is close with a little bit of upside next year.

Our next question comes from the line of Derrick Whitfield with Texas Capital.

Congrats on a solid update this quarter. I wanted to start on the operational front. Can you speak to some of the design changes you incorporated this quarter to drive lower equipment cost per well?

Yes. I mean, I think generally, high level, it's been the combination of how Endeavor was doing things and how we were doing things and finding the best of both on the equip side. I don't know, Dan or Al, you have any details.

I mean, a lot of it is driven by just extending lateral lengths, right? I mean, that's the biggest lever we have to pull. And it's one of the reasons why we're starting to lean into some of the U-turn development because we talk about a lot, like what is the efficient frontier for lateral lengths and can we get to a point where our average lateral length continues to creep up beyond 12,000 feet and it just drives so much more efficiency. And so that's really what you're seeing. The biggest change is just a little longer laterals, and you need the same flow line and same tubing and all that for that well, it just drives down your per foot cost.

And I think some things have come out of the scope as well. So we're always looking at each little line item. But Danny's point is the equip piece and the infrastructure piece, that's nonproductive capital, right? And we want to minimize the non-oil-producing capital in our CapEx budget.

Great. Makes sense. And as my follow-up, maybe I wanted to touch back on the EOR question from earlier. Could you speak to the lessons you guys have learned so far and how you're thinking about broadening this program as you look out beyond the first 50 wells?

Yes, Derrick. Great question. Really, it's figuring out which rock types and lithologies, the technology, the specific surfactant technology, we're applying where it works best in and where we're seeing the best returns. And then looking at the overall portfolio of the thousands of wells that we operate, where are those rock types situated and then thinking about sort of the chemical composition of the surfactant and which ones are working best in which different rock types. And so that's sort of the ongoing process. And like I said earlier, I think we're really just early innings on this, and the team is learning a lot and the initial results that we're seeing from this 12-well package are really promising. But we're going to learn a lot from these 12 and apply it to the next group of wells that we do in the future. And I think this is something that like Kaes talked about earlier, where we could see some shallowing of the decline rate and then the decision on do we take capital out of the system or do we lean in. But yes, overall, that's sort of the details of where we are today.

Our next question comes from the line of Charles Meade with Johnson Rice.

I wanted to go back to your shareholder letter and your theme of volatility and see if you maybe share your view on the macro. We've been living in the world with a lot of volatility. But I'm curious -- we see some this morning, but I'm curious, do you think that stopping the bombing and opening the Strait of Hormuz is what's going to kind of end the volatility? Or do you -- are you anticipating that there's been some structural changes in the oil market that even if we do get these agreements that we're going to be living with more volatility going forward?

Yes. I mean, listen, I think it's been -- it's probably not our place to comment on geopolitical events and instead focus on global inventories. And I think the relationship between inventories and price has broken down a little bit over the last couple of months, but I think that's probably because there's noise in the system. Someone smarter than me explained the market as basically a sine wave because of everything that's happened and everything that's been disruptive. And at times, there's going to be heightened volatility on the upside and heightened volatility on the downside with a steady state far from a possibility today. So I think generally, chasing headlines over the last 3 months has been exhausting. And I think we've decided to just kind of put our head down and believe that crude oil that comes out of inventories today has to be replaced tomorrow. And over a multiyear period, that should be -- that should result in a bid for oil for a longer period of time here.

Got it. And then Second question on the Wolfcamp D. You wrote about that in your shareholder letter that you've been driving down costs there. And if I look at Slide 11, it's actually interesting. That looks like the Wolfcamp D is actually the biggest rate of change from '25 to '26 as far as your lateral footage. So I'm curious, two things, which direction does the causality work there? Are you getting the cost down because you're just -- you're drilling more of them and learning more? Or is it the other way around that you're drilling more because you've gotten the cost down? And perhaps you could also talk about what -- the other side of the equation there, what you're seeing in productivity trends in the Wolfcamp D?

Yes. So from a cost perspective, the team had a budget of like $350, $360 a foot and their stretch goal is to drill wells at $300 a foot, and they're actually hitting their stretch goal. So that does improve the returns of the Wolfcamp D. What has brought more Wolfcamp D into our program is that when we merged with Endeavor, they had some acreage in kind of the sweet spot of the Wolfcamp D kind of Midland County, Eastern Midland County versus where our prior asset base didn't have as much upside. But in general, as these other zones get more airtime, I want you to pay attention to productivity because traditionally, if someone brings in -- if a company brings in a lot of secondary zones that they hadn't been developing to date, their productivity per foot takes a hit. And our productivity per foot while adding these zones has been consistent to now up this year. So credit to the team, but I think it's also just a combination of a larger asset base with more places to allocate capital post Endeavor.

Our next question comes from the line of Leo Mariani with ROTH.

I think there really hasn't been much in the way of Delaware Basin activity over the last handful of quarters. Can you just give us an update kind of what's planned for that asset? Is that just going to kind of sit there and kind of slowly decline over time? Is it something you're going to look to get back after kind of later on down the road? Just any color would be great.

Yes. I mean, while there's no capital being allocated to the Delaware this year, there are some interesting things happening over there. We've done some farm-outs in the second Bone Spring in our ReWard position. Those produced some really good results that unlocked some inventory that we probably didn't think was as competitive a couple of years ago as it is today. We see a lot through our Viper lens. And I'll tell you the leasing in the Delaware for Viper has been significant year-to-date. There's a kind of a Delaware Woodford trend that is getting a lot of attention, some big wells. They're expensive wells, but big wells, and some leasing going on there. So there's stuff going on beneath the waves, but no major capital allocated there this year or likely next.

Okay. And then just on EOR, I know it's kind of early days, and you guys are still analyzing results. But at this point, do you think that you've had clear economic benefit and leased some of the wells out there, maybe not all of them. I know it works better on some versus others. But are you convinced that there's economic benefit in terms of incremental capital that's gone into some of those existing wells?

Yes, 100%. We just got to figure out -- we got to learn about what's happening. Some wells saw zero uplift, some wells saw production triple or quadruple versus where they were before. And the average was somewhere in the range of 150 to 200-barrel a day well going up by 100 to 150 barrels a day, but the dispersion is just so wide. And so I liken it to a Wolfcamp B frac in 2014 versus a Wolfcamp B frac today. These are Wolfcamp B fracs from 2014, and we got to figure out what's going on beneath the surface. And I think with the quality of the data and our ability to process it as quickly as we can today is going to allow for continuous improvement.

This concludes the question-and-answer session. I would now like to turn the call back over to Kaes Van't Hof, CEO, for closing remarks.

Well, thanks, everyone, for the time and the questions. We again used up a full hour. I continue to be impressed with the analyst community. So thank you for the time.

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