Diamondback Energy (FANG) Q3 2026 Earnings Call: Low Reinvestment and Barnett Growth

Diamondback Energy’s (NASDAQ: FANG) Q3 2026 earnings call centered on capital discipline, Permian Basin development and emerging growth opportunities in enhanced oil recovery, natural gas infrastructure and power projects. Management kept the operating plan in “green light” mode but deferred a formal 2027 plan until February.

Key Takeaways

• Diamondback reported a 32% reinvestment rate, with management estimating a roughly 30% full-year rate using the referenced strip pricing.
• Consolidated debt has declined by approximately $4 billion over the past year. Management intends to preserve balance-sheet capacity for investments and potential share repurchases during weaker commodity cycles.
• A normalized operating program of 19–20 rigs and about five frac crews is the current baseline. If maintained in 2027, completed lateral footage would be broadly flat with 2026’s 6.44 million feet.
• Barnett development is moving from geological delineation toward full-field development. Management said costs near $850–$900 per foot could support returns and present values above the core program in selected areas.
• Current oil recovery is about 10%. Management believes 11% could be achievable within the next few years, while a 1–2 percentage-point improvement could add 50,000–100,000 barrels per well.
• The company expects Permian gas to become more valuable over the next decade as LNG and power demand shift the basin from supply-push toward demand-pull conditions.

Key Financial Data

Business and Operational Performance

Permian focus and capital efficiency

Diamondback intends to remain focused on the Permian Basin rather than diversify into unfamiliar regions. Management said its 1,700 employees concentrate on improving productivity, costs and resource recovery within the basin.

The company emphasized that development design, well targeting and its cost structure allow it to capture about 90% of the idealized value of analyzed drilling units. Management contrasted this with the risk of value degradation from returning later to drilling units and creating parent-child well interference.

Barnett development

The Barnett is progressing toward full-field development, particularly around Spanish Trail and other deeper areas with favorable resource quality and reservoir pressure. Diamondback expects obligation drilling in 2027, but said the economics support co-development rather than drilling only to retain acreage.

Four or five full-section developments are expected to begin production over the next three to four months. Early flowback from the initial development was described as encouraging.

Longer laterals, shared infrastructure and faster drilling are expected to reduce unit costs. Management identified approximately $850–$900 per foot as an important range at which selected Barnett projects can compete with or exceed the core program on capital efficiency.

Recovery improvement and chemical EOR

Diamondback is testing surfactants and other chemicals in completions and remedial work. The program remains at an early stage, with significant variability across chemicals, reservoir conditions and deployment methods.

Management said even a 1–2 percentage-point increase from the current 10% recovery factor could add 50,000–100,000 barrels per well. The company has created a dedicated internal group and plans to allocate $50 million–$100 million to this work within a capital budget of more than $4 billion.

Natural gas, LNG and power infrastructure

Diamondback has secured pipeline capacity closer to end markets and is discussing potential arrangements with LNG participants that hold offtake or transportation capacity but need physical gas supply. Management does not currently plan to lead long-dated LNG infrastructure commitments, but sees potential transactions that better connect its gas molecules with downstream demand.

At the Brian Ranch power project, the company has remediated the land, secured equipment and arranged water and gas. Final agreements remain the main gating item. Management indicated that mobile generation is likely to provide the fastest initial power solution, with longer-term alternatives possible later.

AI and automation

Diamondback is deploying autonomous, self-optimizing artificial-lift systems to reduce downtime, compression requirements and labor intensity. The remaining roughly 1,000 plunger-lift wells are expected to be connected within months.

The company is also using drone technology to identify field issues before dispatching personnel. Longer term, management sees the largest potential AI gains in subsurface evaluation, completion design and well productivity, although these applications remain at an early stage.

Management Guidance

Management’s current operating baseline is approximately 19–20 rigs and five frac crews. The program is intended to remain level-loaded and generate some organic growth, although quarterly well timing may create variability.

Diamondback expects fourth-quarter spending to remain near the discussed $1 billion-plus range. Management said that maintaining oil production near the upper end of the range should be possible while offsetting some inflation through efficiencies. Achieving growth in 2027 would likely require somewhat higher spending, particularly if oil remains around $100 per barrel and service costs rise.

A formal 2027 plan is expected in February. Management said completed lateral footage would be broadly flat with 2026 if the company continues running approximately 19 rigs and five frac crews.

Risks and Watch Items

• Service-cost inflation could increase if oil prices remain near $100 per barrel, particularly for consumables and oilfield services.
• Commodity prices remain volatile; management cited a $60-per-barrel oil-price swing during Q3 alone.
• Chemical EOR results remain variable, and broader deployment depends on further field testing and economic validation.
• Barnett development data are still limited, particularly for full-section co-development and optimized completion designs.
• The Brian Ranch power project still requires final agreements before a final investment decision can advance.
• Large-scale M&A is more difficult amid front-month commodity volatility and prices above Diamondback’s mid-cycle assumptions.

Analyst Q&A Highlights

Capital allocation: Management plans to prioritize the base dividend, debt reduction and opportunistic security repurchases. The dividend is designed to remain protected below $40-per-barrel oil, while balance-sheet capacity could support share buybacks during a future downturn.

2027 outlook: Management said it is preparing the business for downside scenarios despite personally leaning toward a “higher for longer” oil-price environment. No formal plan will be issued before the normal February update.

Barnett economics: Better geology, reservoir thickness and pressure have supported strong early productivity. Management expects longer laterals, shared facilities and execution gains to improve costs as development scales.

Permian gas growth: Diamondback has higher-gas-content inventory but has not needed to prioritize it. Management said dedicated gas drilling would require greater control over processing, transportation and downstream pricing across the value chain.

Recovery potential: Management believes moving from 10% to 11% recovery is achievable within a few years. Reaching materially higher recovery levels, potentially toward 20%, would require further technological progress over the next decade.

Full Earnings Call Transcript

Complete Earnings Call Transcript

Management Remarks

Operator

Good day and thank you for standing by. Welcome to Diamondback Energy's Third Quarter 2026 Earnings Conference Call. [Operator Instructions] 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.

Adam Lawlis

Thank you, Stephen. Good morning. and welcome to Diamondback Energy's Third 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 out 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.

Kaes Van't Hof

Thank you, Adam. I hope everybody read our much longer shareholder letter last night. A couple of key mega themes we've been thinking about a lot in the Permian, but also a regular update on the business. So I think we'll just go straight into Q&A.

And operator, please open the line for questions.

Operator

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

Question-and-Answer Session

Neal Dingmann

My first question is just on your reinvestment rate, specifically, just wondering, do you all think about sort of maybe capital allocation, perhaps even when you give your growth plans differently given your leading 30% reinvestment rate, I mean given how low that is, I'm just wondering what -- how that changes in your thought process when you all said in the plans?

Kaes Van't Hof

Yes, Neal, I mean, I think there's 2 big pieces of capital allocation within Diamondback. First is, let's drill our best stuff first, right? We've been very good at that for a long time now. And we spend a lot of time finding the best projects in our portfolio and that is the baseline for the capital plan and the output that is the free cash and the reinvestment rate. I would say on the reinvestment rate side, it's interesting, Diamondback 32%, I think at strip yesterday, it was a 30% reinvestment rate for the year. That's below super majors and super majors have refining crack spreads that are at all-time high. So I think the E&P investor from 2018 or 2019 would fall out of their chair seeing an oil and gas company. E&P, shale company, reinvested at 32%. So we're very, very proud of that. That's a combination of, one, that capital allocation in the field; two, the lowest cost structure in the basin that we're continuing to drive down; but then three, we know that the market is volatile. We know that front month commodity prices have been all over the place throughout this year. I think we saw a $60 a barrel swing in Q3 alone. And so our best protection is to keep that reinvestment rate low, generate a ton of free cash and then allocate that free cash appropriately to what the market is giving us. And I would expect that reinvestment rate to stay low, capital discipline to remain and us to allocate that free cash to the right side of the balance sheet.

Neal Dingmann

No. That makes a lot of sense. And then just my second question, maybe a little more qualitative just get asked a lot on the Steven -- maybe Steven's family, specifically with the Steven's family. Can you talk about your or even Diamondback's relationship with the family?

Kaes Van't Hof

Yes. I think we have a great relationship with the family across the board as well as myself and the team personally. I think anytime you have a shareholder that owns that many shares. They deserve all the attention that they need. We go see them every quarter and talk to them. Obviously, they have sold down a good amount of shares this year. And we recognize that, that sometimes weighs on the shares, and we've tried to support buying back shares in the aftermarket. But at the end of the day, the family is a long-term believer in the story, that's why they did the deal with us. I think if you look at the success of the Endeavor transaction, none of us would take that back. But I do think one thing we talked a little bit about governance in the shareholder letter and just like within Diamondback, we're kind of beyond talking about legacy Endeavor and legacy Diamondback we're kind of one -- we're one team rolling forward here in Midland, Texas. The same goes for our Board. And we have now have an 11-person board, 2 members are technically designated by the family not. But at the end of the day, that's just one more now moving forward. So we're happy with the size of the Board. We're happy with the family, and I think the feeling is mutual.

Operator

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

Neil Mehta

Yes. And thanks for these 3 mega themes. I think it gives us stuff to key off of this morning. I just wanted to spend some time on improving recovery. So you indicated you're at about 10% of the oil in place is being extracted today. Kaes, how do you see that evolving over time? And can you talk about some of the components you talked about in the letter around development completion in EOR? And then as you kind of tie that into the Permian, the Permian is producing, call it, 6.7 million barrels a day, so about half of America's oil production year-to-date. How do you think about the growth of the basin broadly in that context?

Kaes Van't Hof

Yes, Neil, that's a great question. And I think the key is some of these things that were probably more theory in the last couple of years are becoming reality. And we're big believers in stacking up the little wins here at Diamondback. If you think about what we've done mechanically above ground drilling wells starting at 30 or 40 days. Now we're at 4 or 5 days. That didn't happen overnight. And I think the theme on improving recoveries isn't going to happen overnight. But if we're thinking about the 2030s and beyond, there are some things that are being tested in the field that are starting to look like successes. And I think the completion technology continues to improve. I think we're able to sense more and see more downhole than we used to. But then you also have some things like surfactants or chemical EOR that are starting to have some positive use cases, whether it's on the front end and the completion or in the remedial jobs that we've been trying over the last 1.5 years, 2 years. and we're starting to learn a lot more about it and improve our process and move from a theoretical process to something we can model. And I think that should -- if you go to your macro comment, that should either allow the basin to grow more or be able to do this longer. And one of the key points of the mega themes that we put out there is that we're not just thinking about Diamondback for the fourth quarter or for 2027. We're thinking about Diamondback for the 2030s in this basin for the 2030s. And I think spending capital and time and intellectual capital today is going to be rewarding for our shareholders for the long term.

Neil Mehta

No. It was interesting that the letter kind of really focused in on the Permian and your confidence into the next decade because one of the questions we often get from your investors is should Diamondback diversified beyond the Permian. But I'd love your perspective on this because you kind of are at a fork in the road as it relates to that. Is this kind of indicating that you want to stay a Permian pure play?

Kaes Van't Hof

Yes. I mean, listen, we want to know what around the world could outcompete us in terms of productivity and returns. And we have looked and seen plays that get attention, whether it be in Canada, shale plays in Argentina, some of the international stuff starting to get attention. And I kind of go back to my golden rule, which is no, you don't know. And I do know that Diamondback is a basin expert. We spend every day, 1,700 people spend every day trying to get better at what we do in the Permian Basin, and we don't spend a lot of time thinking about other places outside the basin. Now with the mega themes, I think that means there are other avenues to grow the business throughout the basin, like our Mineral business, some of the stuff we're doing on the midstream side. Obviously, the infrastructure data center way, we think we can kind of be at the center of that and add value to that process. But at the end of the day, I think our investors would rather us spend the extra $100 million on surfactant tests to improve our overall recoveries and duration than go explore outside the basin that we don't know as well. And I think that core competency should result in continued long-term outperformance.

Operator

Our next question comes from the line of David Deckelbaum of Stifel.

David Deckelbaum

I was hoping just to for this year, you guys kind of guided towards the higher end of capital guidance. It looked like there's some cycle time improvements and perhaps a little bit of added activity. Your comments were that well cost inflation is roughly being offset heading into next year that you're at least asking your team with trying to offset well cost inflation with efficiencies. I guess as we think about that $1 billion and change level for 4Q. Is that a reasonable starting point as we think about '27 and still obtaining that kind of single-digit growth number?

Kaes Van't Hof

Yes, David, I'll give you some high level, and then Daniel will give you what he's seeing in the field. I think we've kind of implied last quarter that we're starting to see some inflation on the consumable side of the business. We're basically guiding the same CapEx in Q4 as essentially we ended up in we think that we can probably hold oil production flat at the higher end of that range going forward and fight off some inflation with efficiencies. But I think if we want to grow next year, which is still very much TBD based on the macro, we have to spend a little more -- a little more than the range that we put out for Q4 and I don't know, Dan, you want to talk about what you're seeing?

Daniel Wesson

Yes. I mean I think we're price takers, right? And we've said that before, but our focus has always been on controlling what we can control and fighting the variable cost day in and day out and trying to do that better than everybody else. And we always look for value, whether that's execution value or value in our procurement strategy. And what our service partners can bring us differential to anybody else. And we're going to continue to do that through '27 if there's an inflation cycle, which at $100 oil, you can expect that there's going to be probably an inflation cycle that comes through on the service side. We're going to do what Diamondback has always done and fight the variable cost side of that and look for ways to offset some of that through execution or business relationships. But it's to be determined yet on what 2027 is going to look like with regards to the service sector and the inflation that's coming through. I think there's a lot of volatility in the marketplace today kind of see what happens post what's going on today in the U.S. and throughout the end of the fourth quarter and look forward to updating you guys early next year.

David Deckelbaum

Appreciate that, Danny. Perhaps if we can talk about the Barnett a little bit. You guys showcased some pretty impressive results, particularly in and around its Spanish Trail area. I am curious as we think about '27 and beyond, when does the Barnett become more of a development-oriented program versus HBP? Or should we think about '27 as more of satisfying HBP commitments on the Barnett side before really endeavoring to high grade where activity goes?

Kaes Van't Hof

Yes. So on me that we haven't updated the market on some of our best results to date in the Barnett. We're still trying to lease around those areas. And obviously, us releasing these wells now today is going to bring a lot of attention to those areas. Fortunately, we've gotten as much acreage, almost as much acreage as we can, although the play continues to grow. And I would just say what was once a geologic success is now turning into meaningful value for the company, and we're moving into kind of full field development. And Al, I don't know if you want to give some color on what we're up to in Q4 and next year.

Albert Barkmann

Yes, David, that's -- when you look at Slide 11 there in the deck, we provided a locator map on the bottom right to kind of go along with the well results that we released. And what I would say is we do have some obligation drilling coming up in '27. Most of that obligation drilling is focused in and around where we released these well results of the stars that you're seeing kind of on the western side of the basin. And so what we're doing is we're leaning into sort of the co-development in those areas just because the returns and the well performance are robust enough to compete, especially in areas like Spanish Trail, which is up by our Lela start there in [indiscernible] with the Viper ownership, that's very competitive with core development. So we call those efficiency wells, so just leaning into sort of areas where we've got to go satisfy obligations, but we want to codevelop, so we don't leave children wells behind.

Operator

Our next question comes from the line of Jeoffrey Lambujon of TPH Research.

Jeoffrey Lambujon

Maybe just a follow-up on the Barnett commentary. As you make that move from delineation to full field development that you talked about, can you talk about what's going to change from an on-the-ground operational perspective as it relates to well cost? Over China, are you focused on, whether it's pad size, lateral length, shed facility we have you? And would those do you see moving the needle most towards that well cost target for the program?

Daniel Wesson

Yes, Jeff, good question. I think it's all of the above. Obviously, that lateral length is -- the biggest not we can turn on the dollar per foot basis just moving the denominator longer, and we intend to utilize the lessons we've learned in the channel development and exploit those things into the deep development to drill longer laterals, shared infrastructure across the surface acreage will benefit on the infrastructure capital that you need to deploy to develop those deep zones and then -- just generally, when I look at what is going on, and we're really early still in the development phase of the Deep zones. But when I look at what's going on from the drilling group, you can see marked improvements in every whole section here whether it's getting our intermediate strings to bottom faster or drilling the curve faster are in the lateral. It's -- everything is getting a little bit faster. So I continue to expect that on a like-for-like well that we'll see efficiencies continue to accrue to us in those deep horizons. It's just hard to talk about it today because we just don't have a whole lot of data set -- a whole big data set to look at. But I can tell you that it is looking better quarter-over-quarter.

Jeoffrey Lambujon

Perfect. That makes sense. And then for my follow-up, I just wanted to focus on some of those avenues to grow the business while focusing in the Permian that you mentioned First, on some of the gas and LNG commentary. As you think about the path forward for Diamondback and controlling more molecules downstream on this front as you think about doing business with those potential counterparties, what's a good deal look like for you guys in your view, whether you can speak term price linkages or volume commitments? And then kind of similar line of questioning on the tower side. On the first project, how are you feeling about the gating items to FID? Is there anything you can share just on latest discussions around that?

Albert Barkmann

Yes. So I think they kind of try together, we're going to try to find the best deals across the board for Diamondback shareholders. I think on the LNG side, shareholders have not owned Diamondback to date to be the tip of the spear and taking on 15-plus year commitments to get LNG facilities built. But I think as we've studied the market, you have a lot of LNG demand and maybe some question marks on where the supply is going to come from and you have a lot of counterparties that have taken out a lot of space that are long offtake and short molecules, and we're obviously very long molecules and I think likely to be longer gas molecules over the next 5, 10 years. And so we've taken out a lot of space on pipelines to get to these closer to the end markets and start to have real conversations with the large players in the LNG space. And I think there's win-wins. I think we have to explore what those could be. We tend to be able to get deals done. But I do think it's interesting, there's a lot of LNG players that have taken out even space on some of the pipelines that we're on that don't have the gas supply. So I think generally, we said in the letter, the basin moving from supply push to demand pull whether it be power or LNG should be a good thing for the owner of the molecule long term. And when it comes to our power project, I'll let Jere give an update and then I can say some high-level things.

Jere Thompson

Yes. I mean I think the biggest thing like to mention last quarter is we're close. We've got a unique project on Brian Ranch that is show already. We've remediated the land. We secured the equipment, and we've got water and gas teed up and ready to go. So we're really just dotting the eyes, crossing the Ts on final agreements, but very excited to we are in this position and feel like we should be able to talk more about it soon.

Kaes Van't Hof

And I think I'll just add to what I've learned from a macro perspective, and this is why we put it in the letter, assuming a friendly Texas regulatory environment, Texas has a chance to continue to grow its economy significantly through the development of this infrastructure and a company like Diamondback out in West Texas can aid in that process, whether it's we own surface, we control gas. We can work with midstream partners to get to sites. We have a good idea on site selection. And I think we can figure out ways to get deals done and make things move faster than they have to date. And if you talk to the tech world, they move pretty fast. But Diamondback has moved pretty fast over the last 15 years, too. So I think there's a natural intersection there. I think we have a role to play. I think for our investors, they need to know that we're still going to stay in our lane on what we're good at, but be able to get things across the finish line. And I think just from a Midland and from a West Texas and an employment perspective, a lot of fears about AI and automation in the oilfield and what that's going to do for employment. And part of the message in the mega theme is this could be the next wave of continued GDP growth in this region as well as a higher paying employee base that gets retrained to work on some of these projects. And for instance, Diamondback put $1 million into Midland College to form a new program for the electrical side of the business. And I think that's important. And I think the community should realize that we've got a lot left to do, and there's going to be decades of growth ahead of us and it just might look a little different than the last 10 years of shale development.

Jeoffrey Lambujon

Perfect. It sounds like a lot of all around good there. I really appreciate the detail, and we're looking forward to hearing more on all those fronts.

Operator

Our next question comes from the line of Bob Brackett of Bernstein Research.

Bob Brackett

Following up on the gas commentary. I guess these are mega themes. These are not spot market updates. Can you talk about the time horizon over which you see this potential demand pull or the market being short of physical molecules? Are we thinking 2030, mid-2030s, not next month?

Kaes Van't Hof

I don't think it's next month, Bob. You're very astute in that observation, but I think we've become a much larger company that has had to start thinking about downstream markets and end markets versus where the next well is going to get drilled. And I think part of the reason we discussed this is obviously, we committed to a good amount of production to solitude that project got off the ground and fund it within a couple of months. So it kind of just shows that the supply is going to be there, but also the people that are taking out space on the other side of these pipes are also looking for supply, too. So we've looked at kind of all the U.S. basins, and it's interesting to see what Toby and Jeremy and EQT, you're talking about in the Northeast and demand increasing up there. I think we see the same in Texas and obviously, the LNG is all announced. So the gas has come from somewhere. And if you can't build from the Northeast down south and the Haynesville can't meet this 10, 20, 25 Bs of demand, it's got to come from the Permian. And I think that we kind of see that coming, obviously, not next month, but during periods of time over the next decade for Permian gas is going to increase in value.

Bob Brackett

Very clear. Quick follow-up. On the Barnett wells you disclosed on the recent results, they look like they're all sitting in the deepest part of the basin or the greatest depth down to the top of the Barnett. Is that for a reason? Do you think that, that horizon works as you move toward the shelf edge?

Scott Hanold

Yes, that's a good point there, Bob. I think this is one of the deeper parts of the basin, there are some maybe slightly deeper parts as you kind of move to the north. But overall, yes. I think it's the combination of the resource quality that we've got in this area and the deeper higher bottom haul pressure that's helping us with higher rates. And I think part of the reasoning behind where we put our acreage position together over the past 4 or 5 years is we knew where the resource was the thickest and going to be the best and that's why we put together the leasing program in areas that we did, and we're maybe a little coy with the well performance up until today.

Operator

Our next question comes from the line of Josh Silverstein of UBS.

Joshua Silverstein

A lot of focus on debt reduction over the past year. On a consolidated basis, you're down about $4 billion. Is the idea to keep using the stronger oil price environment, to your advantage on the balance sheet to try to save the capacity for the buybacks when and if oil prices do decline?

Kaes Van't Hof

Yes. I mean I think in the simplest way, that's what we're trying to do. Obviously, opportunities come up, investments come up having the balance sheet to be able to do that without impacting long-term shareholder returns is a good place to be. I would say -- but with the free cash that we're generating kind of quarter in, quarter out, we're really just trying to take what the market gives us. And obviously, we talked about Q3 a $60 swing in oil price, well, in July, when we had oil price weakness, we bought back shares in August, we paid our dividend. And in September, we saw weakness at the end of the quarter again and bought back shares. And then here we are, early October, we had kind of rates flow out, okay, markets given us long-dated bonds well below par, so we lean in and buy back bonds. So really just trying to make the right capital allocation decision every day with the #1 decision we made, continuing to increase the base dividend still well protected below $40 a barrel oil price I think there's still room for that to grow. And as the balance sheet strengthens, it should naturally grow. But also having the balance sheet capacity to do what is, in my mind, the holy grail of an E&P, which is lean on your balance sheet to buy back shares at the right point in the cycle. And we're clearly not at that point today. I hope we never get there. But I think we're prepared for anything with this free cash wave coming to Diamondback shareholders.

Joshua Silverstein

Got it. And then one for me on just on the data center milestones. I was curious when and if you're taking power generation capacity. And that was also kind of curious how you might be able to use fiber as part of this as well. given maybe a different cost of capital there or a drop-down opportunity. It seems like that would be certainly an interesting opportunity for you guys.

Kaes Van't Hof

Yes, I think, the projects and the projects in this basin have kind of moved to the mobile power side of things, just to get power as quickly as possible. So I think you can expect that from us and what we're trying to do out here. Obviously, I don't know if that's the long-term solution, but I do think there's going to be ways to grow these projects over time with more long-term power solutions given the amount of gas that we have out here. And then on the Viper question, I think that's interesting. I think I think we could debate if Viper has a lower cost of capital right now than Diamondback. I think the market hasn't rewarded Viper as much as it should have this year. But I think, first and foremost, we've got to get this project signed up and then how we monetize that is tomorrow's discussion.

Operator

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

John Freeman

I believe in the Barnett, you'll recently started flowing back your initial kind of full section development there. Should we sort of think of it as like maybe when you get more fulsome results on that, maybe sometime first half '27. Is that sort of the main sort of determinant at this point on whether that kind of 5 rig kind of activity kind of run rate potentially would accelerate? I mean, obviously, the costs are already doing a really good job of kind of on a leading edge or to kind of getting around that 800-foot target. So is it more just trying to get an understanding of what it looks like on a full section development basis.

Kaes Van't Hof

Yes, John, I mean, it's flowing back right now, and it looks good early time. So nothing that scares me or scares the team from continuing to push on I think we have 4 or 5 full section developments coming on over the next 3 or 4 months. So we're happy to update the market on that and the performance. I think as you see in Slide 11, the individual wells are obviously well above the average, and we're not going to model a type curve that's the best parent well in the basin. So I think there's room for improvement on full section development overall relative to that type curve as well as the cost side. And I think the key message here is, again, the geologic success is actually turning into a lot of value for our shareholders here.

John Freeman

That's great. And then just one more follow-up also on the Barnett. I believe one of the other things you've looked at is potentially being able to lower the cost per foot fairly meaningfully is maybe looking at reducing the completion intensity, maybe something similar closer to the kind of core Wolfberry design. Is that anything that you all have done any pilots on yet? Or just that's in the future?

Kaes Van't Hof

Yes. Let me give you the simple answer is, early on in these developments, we kind of gold play everything and then start to work our way down. And Danny, you can kind of give you some color on some things we're thinking about.

Daniel Wesson

Yes. I mean, I think that's a great question. It's something we certainly are looking at. I think like Kaes said, we don't want to undercapitalize these first delineation of full second development. So we're trying to make sure we have a sufficient completion that we're not questioning whether something was completion driven in the results. I think as we get further into development mode, we'll start looking at what's the right sized jobs for the spacing that we are developing a section at, and these are going to be wider spaced wells than what you'd see in our core development. So I wouldn't expect to see the job sizes in line with what we pump in like a Spraberry well. But you might see a tailor back to or look, it could even possibly go up higher. It's just all dependent on what's right for the development in the spacing and maximizing NPV at a certain rate of return.

Operator

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

Scott Hanold

I was wondering, Kaes, you appear to be a bit cautious on 2027. Just give us a sense of like is there something you worry about on the oil price? And you've got the inventory. You clearly have the execution and capabilities to grow in this high-priced market. And we do have like a 24-month curve that's above your mid-cycle price. So can you just give us the way you think about like the future in the next couple of years for Diamondback and why you think like a starting point is kind of flattish growth with potentially some minimal growth upside?

Kaes Van't Hof

Yes. I wouldn't say I'm necessarily cautious personally, but I think it's always good to prepare the company for a swing to the downside. It's never it's not a good way to run an E&P just to be a permeable. So I would say, given what we've seen in terms of global inventories, in terms of shipping rates in terms of what we've seen on the shuttle trade and how much we're spending to get ships through the Street and the overall geopolitical instability, I'm probably more in the higher for longer camp personally, but we prepare the business to keep our cost structure low and execution in perfect shape because the inevitable can happen. And I think 2026 is a great example of that. Every analyst calling for [ $55 ] or lower oil and we've averaged [ $95 ]. So I think we're just -- we've always prepared our business for a lower price environment. We've always kind of shined in a lower price environment. But I think there's just still some uncertainty over the next couple of months, and there's just not a need for us to put out a formal 2027 plan because we always end up doing that in February. And that's where my head's at the Board has that.

Scott Hanold

Okay. Understood. And just a follow-up question is -- my follow-up question is on the Solitude pipeline. As we start thinking about like capital spend over the next year or 2 for Diamondback, you projects like this, where does that capital ultimately falls that could be part of the budget? Or does that sort of fall into some sort of an equity affiliates?

Kaes Van't Hof

Yes. So I'll give my high-level thoughts. I think it's going to roll through the equity affiliates and you think about Diamondback this year, and I've given this stat out a office last quarter, Diamondback corporate is going to pay $2 billion or nearly $2 billion of cash taxes this year in a U.S. market that's only going to pay $400 billion of cash taxes to the government. So we're 0.5% of the cash tax spend in the country this year, which is a wild statement. And that's why we're kind of implying an investment in something like Solitude investment in Power Gen in the basin. These can be really good investments for Diamondback shareholders and outside the traditional CapEx budget, but that also defer some taxes over here because we are paying a lot of taxes at Diamondback.

Operator

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

Phillip Jungwirth

Slide 10 is always great, and you added an NPV per section graph here. I was hoping you could just explain the developers undeveloped part where Diamondback is 89% just because it's maybe not intuitive why saying is so much higher than peers in the low 60s when wells per section average zones aren't terribly different and you have another peer that's bit more comparable to you with fewer zones targeted. So -- and also just why don't you think peers can kind of replicate what you're doing here on the development side design? Or maybe it's just acreage quality or just how properties were developed historically?

Kaes Van't Hof

Yes. That's a great question, and it's a very, very important slide. In my mind, it's the most important slide of the deck and probably the most misunderstood slide on the investor side. So I'm glad you're bringing it up. I think high level, all of our equities have the implied value of our production and the implied value of the upside and the undeveloped inventory that we have to prosecute of which Diamondback has a significant amount. I think what that slide is proving is we're proving that, that upside -- that upside is translated to cash flow that goes into your pocket whereas some peers have implied upside that remains at risk to be developed. And that's the parent-child issues throughout the basin. And then the last point I'll say, and Al can give you the details, is it proves that an acre in our hands is worth more than an acre than someone else's. And that's been the key to Diamondback's success to date, lowest cost structure, most number of wells per section at good productivity should generate more NPV per section and per AGR that goes in your pocket. And I might have stolen your answer, but anything you want to add to that? .

Albert Barkmann

No. Great question, Philip. The only thing I would add there is I think at a high level, the way to think about that chart is on the right-hand side, the full bar is effectively the idealized value of the issues that were analyzed for this chart. And the dark red that fills up that full bar, that's the PV that was captured during the development of those DSUs. And so like Kaes is saying they're effectively through the way that we develop the way that we target these wells and via our cost structure we're able to capture 90% of the idealized value of the DSUs, whereas a similar peer, peer 3 that's right below us has similar acreage quality but are only capturing 61% of the total value of the DSUs. 39% is remaining value. But like we mentioned, that value is exposed to degradation risk when you return to the DSUs and deal with parent-child overfill, underfill type development.

Phillip Jungwirth

Yes. That's great detail. And yes, we have noticed your well productivity is higher this year, which is not a broad-based trend we see across the basin. But the second question is, I thought it was interesting that 79% of Viper's capital had been deployed to proprietary or market deals and the McElroy Ranch purchase was pretty significant. I was just hoping you could expand on the go-forward opportunity set for Minerals just because it seems like a real advantage for Diamondback. I assume we don't see this in the traditional E&P space? And just while we're on the topic, can you just touch on how you see M&A for Diamondback now, recognizing you're good at it with a long track record, but we're also above mid-cycle as far as commodity prices.

Albert Barkmann

Yes. We some -- I'll go through Diamondback first. We gave some commentary about Diamondback's ground game. And I would say Diamondback's ground game is still is still impressive, and we're still getting deals done. It's just probably not as large relative to the size of the enterprise. But -- and so we're going to continue that going forward. I do agree with you, M&A is tough in this type of volatility, especially the front month volatility. So I'm probably particularly public to public or large-scale M&A seems harder to get done in this environment than easier. On the Viper side, the alternative is Viper has a balance sheet that was able to do a deal like the McElroy Ranch with cash. And that's where I think we differentiate ourselves on the Viper side. And I think if you look at like how we've been looking at those deals, front month may be high back into the curves below $70, you can kind of run a scenario at $70, $75 crude and generate a reasonable NAV rate of return. So that's kind of how we're thinking about it. at both companies. Obviously, I think the opportunity set has been brighter at Viper, and we've kind of used the Viper balance sheet to get some significant deals done over the course of this year.

Operator

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

Derrick Whitfield

I wanted to start with AI for my first question. As you think about what you've accomplished with autonomous Lift and preventive maintenance initiatives, how would you characterize where the organization is along the AI machine learning adoption curve generally? And how would you quantify the upside you see associated with adoption in both development and production?

Albert Barkmann

Yes. So I'll start with kind of the company AI strategy and then give it to Chad to talk about some of the successes in the field. I kind of put the AI thesis or strategy at Diamondback in 3 buckets. The first is kind of the table stakes bucket of higher productivity per employee, menial tasks getting automated and taking making employees have more free time to do their work versus accomplish tasks. And that's happening across the board. I think the field is kind of the second -- the production side of the business is where we're starting to see real benefits of AI and automation today. Chad, you can talk about that. And then I think the Holy Grail, which we have some very smart people working on is how can AI impact the subsurface and productivity. And whether that's completion design, completion technology, subsurface evaluation, all of that could be the $1 billion or multibillion-dollar wins on the AI side. But Chad as seen some wins in the field. He's going to talk about a couple of them.

Chad McAllaster

Yes. Really, we're taking a multifaceted approach to the deployment of AI. And when you think about our production operations organization, we've been focusing on the self optimizing of our artificial lift solutions and starting there. We put an example in the notes about plunger lift, really the success we're seeing there because the deployment there is working really, really well. Those are totally autonomous, self-optimizing solutions and yielding both the savings in terms of manpower and the amount of compression that we're using to a solution. So we're just carrying that board across every form of artificial lift that we have out there. and seeing a lot of success from various trials and demonstrations that we're doing. And then you leverage that into how we use our people. And we also put an example in there, we're moving into some drone technology that we can ultimately move our folks from having to go hunt for issues in the field. So we identify those upfront, and we deploy them to go fix and address issues. And so it's a much better usage of our personnel allows us to scale the business much more effectively. And so we're doing that in the production upside and then that same type of efforts carrying through every discipline in the company across our operations on its drilling completions name. So it's still our early innings, and we've got a lot of runway to go, but we're excited with where we're standing today.

Derrick Whitfield

Great. So exciting guys. Kaes, I wanted to come back to EOR with my follow-up. If your base recovery is 10%, how much incremental recovery could surfactants add? Is it another 1% to 2%? And another question just to make sure I understand the distinction or difference perhaps. Is there a difference between the factors that you guys are talking about and what you're hearing from Chevron with advanced chemicals?

Kaes Van't Hof

Yes, Derrick, great, great question, man. I think it's TBD on how much incremental recovery can you get you -- we test a lot of chemicals in the lab with core and fluids that are from the reservoirs. And some of the results that you get in the lab work are pretty impressive, right? But I think the thing that we're excited about is even a 1% to 2% uplift in recovery factor would represent a 50,000 to 100,000 barrel per well uplift, which is -- would obviously be very meaningful to Diamondback. So yes, I think that's sort of TBD on that. And in terms of the chemicals that we're testing, we've tried in the lab, trialed a lot of different chemicals, chemicals that are very similar to what other operators are doing some things that we're doing recently that are sort of more in-house developed, and we're really excited about those as well. So we're kind of across the board. I think like we mentioned in the note, there's a lot of variability in the results. And so we're trying to hone in on the specific chemical compositions that were the different techniques, how we deploy them in the field. And so there's a lot of variables remaining to -- for us to optimize. But overall, I think just being early innings we're very excited about the results that we're seeing.

Daniel Wesson

Yes. I think one thing from a strategy perspective, we've highlighted this group. We've created a new group within Diamondback. They get a lot of airtime with us, they're getting a lot of capital to try things because I think, again, it's going to be important, and it's going to improve not only productivity but also longevity.

Operator

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

Douglas George Blyth Leggate

Kaes, I wonder if I could come back to the Barnett. The productivity, obviously, the early productivity looks pretty impressive. The capital and moving in the right direction. I'm trying to understand at what point do you get to full field development to the point where you're sustaining capital directionally moves either up or down as that mix changes. In other words, better productivity, but more expensive wells. What does that mean for your sustaining capital when the Barnett is a permanent part of the mix?

Daniel Wesson

Well, I think as the costs come down, Doug, and the NPV per well is higher than the base plan as that works through the system, if we keep improving results, which I expect, and I think we -- you would expect that should improve sustaining capital more on a push basis, it should extend our ability to maintain sustaining capital around where it is today. So that's kind of how I would frame it. Al, anything to add there?

Albert Barkmann

Yes, Doug, I think when you look at Slide 11, here, we show some equivalent fees on rate of return in PV and just kind of gross capital efficiency I think the balance and one thing to keep in mind here is these are idealized analyses, right? And so we're using sort of base assumptions of 100% working interest and one quarter royalty to do this analysis. We've got areas across the basin, right, where we own minerals that are going to make those developments look more advantaged with the areas that are going to be high graded that we know we see a little better well performance, right? So I think sort of the target that I would look at specifically to your question, once we get to the $900 -- kind of $850 to $900 range on a dollar per foot basis. That's really where you see those kind of metrics the 12- to 18-month gross capital efficiency rate of return and then PV is already well in excess of the core program. So we know the resources there in the codeveloped sort of initial phases. We see costs kind of in the $900 a foot range, and that's without any of the efficiencies that Danny mentioned previously. So we're very excited about the program, and they are going to be areas that compete for capital today.

Douglas George Blyth Leggate

That's helpful. It sounds like less wells for the same result basically. So good for capital efficiency as a punch line, it sounds like. I guess my follow-up is a quick accounting question. Obviously, pretty elevated oil prices, a little deferred tax. Are you now in a full cash tax position? Should we think of that as being the case on a go-forward basis?

Daniel Wesson

Yes. I mean, we've been there for years now. And I think when you compare where we are versus peers, we've been paying a much higher overall tax rate for a while. I think they're all going to have to catch up and have to live with our world with higher cash taxes. But yes, we're paying our fair share, Doug.

Operator

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

Kevin MacCurdy

Maybe coming back to the magazine on gas, you obviously are going to get a cash flow benefit from higher Waha prices. But are there any operational inventory uplifts from the higher gas prices like maybe are there parts of your acreage program that you haven't drilled due to the prices, which may be in the drilling Q and coming years?

Daniel Wesson

Yes, we certainly have that in the inventory. It just hasn't been something we've had to or try to drill to date. So I think that you're going to see across the basin, a lot higher gas cuts in certain zones in certain areas, and we have some of it. We just haven't had to drill it yet.

Kevin MacCurdy

Okay. That's fair. And then it looks like to us that OpEx was the driver of the EBITDA beat for the quarter. You talked a little bit about the LOE earlier, but maybe on the GP&T side, what was driving the lower guidance there?

Daniel Wesson

GPT is really kind of a mix between your gas realization and cost, depending on how much gas we take in kind. So I would say the beat that we're most focused on is the stuff we can control control, which is LOE, but on the GPT side, it's really just a mix between realizations and how much GPT you pay.

Operator

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

Unknown Analyst

I had a quick follow-up on the AI optimization of artificial lift. I mean you referenced sites in manpower compression, but what about productivity uplift from that?

Kaes Van't Hof

Yes. That's a great point. We are definitely seeing the productivity uplift in the downtime minimization as you have storms and so forth to come through. And so when you think about the effects on -- our teams are just doing a fantastic job controlling costs and somewhat of an inflationary environment. But the other side of that equation on the volume side, the technology is helping, but the responsiveness of our teams to managing the downtime and coupling that with the benefit you get from AI, autonomous controls has been a huge win for us.

Unknown Analyst

And roughly how long do you think to get the remaining 1,000 plunger lift wells online with this? Is it a matter of weeks, months, quarters?

Daniel Wesson

It's just a matter of months to get those up and running.

Operator

Our next question comes from the line of Betty Jiang of Barclays.

Wei Jiang

Appreciate all the comments earlier about the chemicals EOR. Just a follow-up on that, like where do you think you are -- what inning you are in terms of understanding that technology and feeling comfortable about a broader deployment? And maybe just how much capital do you think will be appropriate to be putting into that technology right now?

Kaes Van't Hof

Yes. I mean I think we just throw the first pitch, Betty. This is like a Wolfcamp B frac in Upton County in 2012, right, compared to where we are today. So we're -- I think our investors would like us to continue to spend capital here. It's not a huge dollar amount, $50 million to $100 million total across over $4 billion budget. But I think that capital will be well spent. And as we learn more, just like anything at Diamondback, if it works and gets better, it will attract more capital.

Wei Jiang

Makes sense. And then for my follow-up, I want to ask about just the activity cadence and how to think about the normalized development program going forward. There's a lot of further that came online in the last couple of quarters. And then 4Q, at least based on the guidance implied a lower completion quarter on a footage basis. And through all that oil is roughly flat. I know there's a lot of nuances that goes behind the lumpiness? Maybe just how to think about how these periods fit together, maybe any lag between the TI and the production contribution. And then how do you think about like will it be a normalized completion cadence on a maintenance level basis?

Kaes Van't Hof

Yes. I mean I think the base case is around 19 to 20 rigs and around the 5 frac crews consistently. I think that's where our heads out right now and whether that spits out 120 tills in the quarter or 140 is just going to be dependent upon when those wells are popped. But in general, we're running a very level loaded program that should spit out some organic growth.

Operator

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

Gabe Daoud

I was hoping I can maybe follow up on Bay's question just on '27 and Kaes, an earlier comment you made in the call around CapEx. So if you were to run the 5 crews through '27, is that the high end of 4Q CapEx number, the [ 10 50 ], is that what we should expect for quarterly CapEx in '27? Or is it a bit higher to get that low single-digit growth?

Kaes Van't Hof

Yes. I don't know, Gabe, today, there's still a lot of variables out there. I'd probably say at $100 oil, it probably is a little higher, but we'll see what happens over the next few months.

Operator

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

Arun Jayaram

I was wondering if we could go back to Slide 11 and talk a little bit about Diamondback's results relative to the industry for the Barnett because the gap relative to peers looks to be greater than for the kind of core Midland Basin program. I'm wondering if you could just maybe comment on what you think the drivers of that? Is that better rock or what you're doing from a completion standpoint? And then maybe just talk a little bit about the plant shipped in the full development mode. As you mentioned, I think the Barnett at is about 20% of drilling activities as we stand here today.

Kaes Van't Hof

Yes, Arun, I think just generally, the team had a very specific strategy on where they wanted to target as I've said many times in this call, we're basing experts. We know we just think about this basin day in, day out, and we had a thesis that seems to be proving out in the geology, and I think that separation will continue.

Arun Jayaram

Understood. Understood. And then as a follow-up, case, if you ran kind of 5 frac crews 19 rigs or so in 2027, ballpark, how much footage would that kind of generate relative to the 6.44 million foot of completed lateral this year? .

Kaes Van't Hof

Yes, relatively flat to this year, Arun.

Arun Jayaram

Relatively flat. Okay.

Operator

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

Charles Meade

As to you and your team, and I want to say I always enjoy your unvarnished comments in this format. One quick follow-up on the Barnett. I think you mostly addressed this, but just one other dimension perhaps. It sounds like the big determinants of this productivity you're seeing or reservoir energy in the thickness. So you're choosing the best places. But is there anything else that has surprised you guys? Or do those 2 factors explain most of this uplift that we're seeing?

Kaes Van't Hof

I mean, I think I think geology drives the day, right, Charles. And we picked some really good spots to get going here. I think we're learning the aerial extent of that was funded via Diamondback's cash flow and done at very low acreage prices and on a full cycle basis, this is probably one of the best investments we've ever made.

Charles Meade

That's a good characterization. And then Kaes, this -- I'm going to actually go out on a limb a little bit here, and so feel free to punt if you'd like. But your comments on the gas macro and saying that this is becoming more of a demand pull. The way I interpret that is it's kind of put in the phrases like, look, we're doing [ 1.5 billion ] a day without even trying. And so assuming you had the price signal and you wanted to try -- what could -- what do you think you could grow your gas volumes by year-over-year? My first guess would be somewhere around 10% or 15%, which would be a doubling in like 5 or 6 years. But what would your guess be?

Kaes Van't Hof

Yes. I don't think that's a bad number. I think what we would need to see, though, and need to control is more of the value chain, right? So it's not just what you're receiving at the wellhead, it's what's the processing costs, what's your cost to move it down the pipe and then what's a buyer buying it at. So I think we're probably still a long way from drilling for gas specifically. I think it's naturally just going to happen. But if you were to drill for gas specifically out of this basin, you got to think more like a gas company that has more of the value chain under their control.

Operator

Our last question comes from the line of Leo Mariani of ROTH.

Leo Mariani

Wanted to follow up on the comments just around improved recoveries. Obviously, you're talking about roughly 10% currently. Do you think you can actually move the needle on that number or it actually goes, like, say, closer to 11%. Is that a this decade event? Or do you think of that as more of something that could happen in, say, the first part of the 2030?

Kaes Van't Hof

I mean I think 11% is achievable in the next couple of years. The question is how do you get from 10% to 20% and obviously, a much larger oil companies talked about that in this basin. And I think there's probably some use cases that are working in a lab or early tests in the field that give me some hope that, that's probably possible in the next decade. But I think strategy-wise, Leo, we have the longest duration inventory in the basin at the lowest cost structure. So we're going to be the last company that has to try this stuff. And if this these methodologies become better rate of return than what we have left to drill, then we'll pivot to allocating more capital to them. But I think what we've built inside the business is the most flexibility to try these things or have to do these things last versus try them and learn from them today.

Leo Mariani

Okay. It certainly makes sense. And then just to kind of be clear on your comments just around thoughts going forward. I mean, presumably, you're still in fully in green light mode here today. At this point in time, I know '27 is TBD. But at least for now, it doesn't seem like anything that's moving you guys off green light in the near term.

Kaes Van't Hof

Yes, that's right. I mean it's been a couple of months or a couple of quarters since the stop light went into retirement, but we're still in the green light.

Operator

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

Kaes Van't Hof

Well, thanks, everybody, for the time, a new record, 65 minutes, and I appreciate everyone making the effort. So thank you for your interest, and we're available to answer any questions if you have any.

Operator

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