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 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 will now turn the call over to Kaes.

Thank you, Adam. Hope everybody read our much longer shareholder letter last night.

A couple key megathemes we've been thinking about a lot in the Permian, but also our regular update on the business. I think we'll just go straight into Q&A, and operator, please open the line for questions.

Morning, Kaes, team, nice quarter. Kaes, my first question just on your reinvestment rate, specifically, just I was 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?

Given how low that is, I'm just wondering how that changes in your thought process when you are setting the plans?

Neal. I think there's the two 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.

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, was a 30% reinvestment rate for the year. That's below supermajors, and the supermajors have refining crack spreads that are at all-time highs.

I think an E&P investor from 2018 or 2019 would fall out of their chair seeing an oil and gas company, an E&P shale company, reinvest at sub-30, 32%. 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. 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's giving us.

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.

No, that makes a lot of sense. Then just my second question, maybe a little more qualitative, just get asked a lot on the Street, maybe Stevens family, specifically, with the Stevens family, Kaes, can you talk about your or even Diamondback's relationship with the family?

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 sometimes weighs on the shares, and we've tried to support buying back shares in the aftermarket.

At the end of the day, the family's 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. 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 one team rowing forward here in Midland, Texas. The same goes for our board.

We now have an 11-person board. Two two members are technically designated by the family, nine, not.

At the end of the day, that's just one board now, moving forward. We're happy with the size of the board, we're happy with the family, and I think the feelings mutual.

Great comments. Thanks, Kaes.

Thanks, Neal.

Good morning, Kaes and team, and thanks for these three megathemes. I think it gives us stuff to key off of this morning.

I just want to spend some time on improving recovery. We indicated you're at about a 10% of the oil in place is being extracted today.

Kaes, how do you see that evolving over time? Can you talk about some of the components you talked about in the letter around development, completion, and EOR?

Then as you kind of tie that into the Permian, the Permian is producing call it 6.7 million barrels a day, about half of America's oil production here today, how do you think about the growth of the basin broadly in that context?

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 years are becoming reality. We're big believers in stacking up the little wins here at Diamondback.

If you think about what we've done mechanically aboveground, drilling wells starting at 30 or 40 days, now we're at 4, 5 days, that didn't happen overnight. 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.

I think the completion technology continues to improve. I think we're able to sense more and see more downhole than we used to.

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 in the completion or in the remedial jobs that we've been trying over the last year and a half, 2 years. 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.

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. One of the key points of the megathemes 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 and this basin for the 2030s. I think spending capital and time and intellectual capital today is going to be rewarding for our shareholders for the long term.

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 diversify beyond the Permian? 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 you want to stay a Permian pure play?

Listen. We we we want to we want to know what around the world could outcompete us in terms of of productivity or returns.

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 get attention. I kind of go back to my golden rule, which is know what 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 megathemes, I think that means, there are there are other avenues to grow the business throughout the basin, like like our mineral business, some of the stuff we're doing on the midstream side, obviously, the infrastructure, data center wave.

We think we can kind of be at the the center of that and add value to that that process. 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.

I think that that core competency should result in, continued long-term outperformance.

Thanks, Kaes.

Thanks, Neil.

Thanks, Kaes and team. Appreciate you guys taking my questions.

Thanks, David.

For this year, you guys kind of guided towards the higher end of the 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 tasking your team with trying to offset well cost inflation with efficiencies. I guess as we think about that 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?

David. I'll give you some high-level, and then Danny will give you what he's seen in the field.

I think we 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 Q3.

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 than the range that we put out for Q4. I don't know, Danny, you want to talk about what you're seeing?

I think we're price takers, right? We've said that before.

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. 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.

We're going to continue to do that for '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's always done, and fight the variable cost side of that and look for ways to offset some of that through execution or business relationships.

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.

We kind of see what happens post what's going on today in the US and throughout the end of the fourth quarter, and look forward to updating you guys early next year.

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 that 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?

Yeah. It dawned on me that we hadn'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 almost as much acreage as we can, although the play continues to grow.

Now, 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. Al, I don't know if you want to give some color on what we're up to in Q4 and next year.

David. 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 to the stars that you're seeing kind of on the western side of the basin. What we're doing is we're leaning into sort of the codevelopment in those areas just because the returns and the well performance are robust enough to compete, especially in areas like Spanish Trail, which is by our Lila star there in orange on slide 11, with the Viper ownership.

That's very competitive with core development. We call those efficiency wells, 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.

Appreciate the color, guys.

Thanks, David.

Morning, guys, and thanks for taking my questions. Maybe just to 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 costs, which items are you focused on, whether it's pad size, lateral length, shared facilities, what have you, and which of those do you see moving the needle most towards that well cost target for the program?

Jeff, good question. I think it's all of the above.

Obviously, that lateral length is the biggest knob we can turn on the dollar-per-foot basis, just moving that denominator longer. We intend to utilize the lessons we've learned in the shallow 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. 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 hole section there, whether it's getting our intermediate strings to bottom faster or drilling the curve faster, ROP in the lateral.

Everything's getting a little bit faster. I expect that on a like-for-like well that we'll see efficiencies continue to accrue to us in those deeper horizons.

It's just hard to talk about it today because we just don't have a big data set to look at, but I can tell you that it is looking better, quarter-over-quarter.

Perfect. No, that makes sense.

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, and 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 to term, price linkages, or volume commitments?

Then kind of similar line of questioning on the power 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?

Yeah. I think they kind of tie together, right?

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 in taking on 15-plus-year commitments to get LNG facilities built.

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. We're obviously very long molecules, and I think likely to be longer gas molecules over the next 5, 10 years.

We've taken out a lot of space on pipelines to get closer to the end markets and start to have real conversations with the large players in the LNG space. 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.

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.

I think generally we said it 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. When it comes to our power project, I'll let Jere give an update, and then I can say some high-level things.

I think the biggest thing, like we mentioned last quarter, is we're close. We've got a unique project on Bryan Ranch that is shovel-ready.

We've remediated the land. We've secured the equipment, and we've got water and gas teed off and ready to go.

We're really just dotting the i's, crossing the t's on final agreements, but very excited that we are in this position and feel like we should be able to talk more about it soon.

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.

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.

If you talk to the tech world, they move pretty fast, but Diamondback's moved pretty fast over the last 15 years, too. 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.

I think, just from a Midland and from a West Texas and employment perspective, a lot of fears about AI and automation in the oil field and what that's going to do for employment. Part of the message in that megatheme 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.

For instance, Diamondback put a million dollars into Midland College to form a new program for the electrical side of the business. I think that's important, and I think the community should realize that we 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.

Perfect. That was great, guys.

Sounds like a lot of all-around good there. Really appreciate the detail and looking forward to hearing more on all those fronts.

Thanks.

Thanks, Jeff.

Good morning. Following up on the gas commentary, I guess these are megathemes.

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, 20 mid-2030s? Not next month?

I don't think it's next month, Bob. You're very astute in that observation.

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's going to get drilled. I think part of the reason we discuss this is obviously we committed to a good amount of production to Solitude.

That project got off the ground and funded within a couple months, kind of just shows that the supply's 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. We've looked at kind of all the US basins, and it's interesting to see what Toby and Jeremy and EQT are 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. The gas has to come from somewhere, and if you can't build from the Northeast down south, and the Haynesville can't meet this 10, 20, 25 B's of demand, it's got to come from the Permian.

I think that we kind of see that coming, obviously, not next month, but during periods of time over the next decade where Permian gas is going to increase in value. No,

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?

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, yeah. I think it's the combination of the resource quality that we've got in this area and the deeper, higher bottomhole pressure that's helping us with the higher rates.

I think part of the reasoning behind where we put our acreage position together over the past 4, 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.

Very clear. Thank you.

Thanks, Bob.

Thanks. Good morning, guys.

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

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 and quarter out, we're really just trying to take what the market gives us.

Obviously, we talked about Q3, a $60 swing in oil price. 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. Then here we are early October, we had kind of rates blow out.

Market's given us long-dated bonds well below par, we lean in and buy back bonds. Really just trying to make the right capital allocation decision every day, with the number-one 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. 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.

We're clearly not at that point today. I hope we never get there.

I think we're prepared for anything with this free cash wave coming to Diamondback shareholders.

Got it, thanks. Then one for me 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 Viper as part of this as well, given it maybe different cost of capital there, a drop-down opportunity. Seems like that would be certainly an interesting opportunity for you guys.

I think the projects in this basin have kind of moved to the mobile power side of things just to get power as quickly as possible. 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. Then on the Viper question, I think that's interesting.

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.

I think, first and foremost, we got to get this project signed up, and then how we monetize that is tomorrow's discussion.

Good morning. Thank you.

I believe in the Barnett y'all recently started flowing back your initial kind of full-section development there. Should we sort of think of it as maybe when you get more fulsome results from that, maybe sometime first half '27, is that sort of the main sort of determinant at this point on whether that kind of five-rig kind of activity kind of run rate potentially would accelerate?

Obviously, the costs are already doing a really good job. We're kind of on a leading edge, already kind of getting around that $800-a-foot target.

Is it more just trying to get an understanding of what it looks like on a full-section development basis?

John. It's flowing back right now, and it looks good.

Early times, nothing that scares me or scares the team from continuing to push on. I think we have four or five full-section developments coming on over the next 3 or 4 months.

We're happy to update the market on that and the performance. I think as you see in Al's 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.

I think there's room for improvement on full-section development overall relative to that type curve as well as the cost side. I think the key message here is, again, the geologic success is actually turning into a lot of value for our shareholders here.

That's great. Then just one more follow-up also on the Barnett.

I believe one of the other things y'all have 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 kind of core Wolfcamp A design. Is that anything that y'all have done any pilots on yet, or just that's in the future?

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

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-section development. We're trying to make sure we have a sufficient completion that we're not questioning whether something was completions-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're developing the section at. These are going to be wider-spaced wells than what you'd see in our core development, I wouldn't expect to see the job sizes in line with what we pump in like a Sprayberry well.

You might see us tailor it back some or look, it could even possibly go up higher. It's just all dependent on what's right for the development and the spacing and maximizing NPV at a certain rate of return.

Thanks, guys. Appreciate it.

Thanks, John.

Good morning. Thanks.

I was wondering, Kaes, you appear to be a bit cautious on 2027. Just give us a sense of is there something you worry about on that oil price, and you've got the inventory, you clearly have the execution and capabilities to grow in this high price market, and we do have a 24-month curve that's above your midcycle price.

Can you just give us the way you think about the future in the next couple years for Diamondback, and why you think a starting point is kind of flattish growth with potentially some minimal growth upside?

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 not a good way to run an E&P just to be a permabull.

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 strait, 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. I think 2026 is a great example of that.

You had every analyst calling for $55 or lower oil, and we've averaged $95. I think we've always prepared our business for a lower price environment.

We've always kind of shined in a lower price environment. I think there's just still some uncertainty over the next couple 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 and the board's head's at.

Understood. My follow-up question is on the Solitude pipeline.

As we start thinking about capital spend over the next year or two for Diamondback, where does that capital ultimately fall? Is that going to be part of the budget, or does that sort of fall into some sort of an equity affiliates?

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 lot this last quarter.

Diamondback corporate is going to pay $2 billion or nearly $2 billion of cash taxes this year in a US market that's only going to pay $400 billion of cash taxes to the government. We're 0.5% of the cash tax spend in the country this year, which is a wild statement.

That's why we're kind of implying an investment in something like Solitude, an 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 defers some taxes over here, because we are paying a lot of taxes at Diamondback.

Understood. I think a lot of people have that same problem.

Agreed.

Thanks, good morning, guys.

Morning.

Slide 10 is always great, and you added an NPV per section graph here. Was hoping you could just explain the developed versus undeveloped part, where Diamondback's 89%, just because it's maybe not intuitive why Fang 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 a bit more comparable to you with fewer zones targeted.

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?

Hi. 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, 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 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. 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 in 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 acre that goes into your pocket.

I might have stolen your answer, but Al, anything you want to add to that?

No, great question, Phillip. The only thing I would add there is, I think at a high level the way to think about that chart that's on the right-hand side, the full bar is effectively the idealized value of the DSUs that they 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.

Like Kaes is saying there, effectively through the way that we developed, 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. Now that 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.

That's great detail. We have noticed your well productivity is higher this year, which is not a broad-based trend we see across the basin.

The second question is I thought it was interesting that 79% of Viper's capital have been deployed to proprietary or off-market deals, and the McWhorter Ranch purchase was pretty significant. 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. 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 midcycle as far as commodity prices?

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 impressive, and we're still getting deals done.

It's just probably not as large relative to the size of the enterprise. 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. 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 McWhorter Ranch with cash, and that's where I think we differentiate ourselves on the Viper side. I think, if you look at how we've been looking at those deals, the front month may be high, back end of the curves below $70, you can kind of run a scenario at $70, $75 crude and generate a reasonable NAV rate of return.

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.

That's great. Thank you.

Thank you.

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

Thanks, Derrick.

Wanted to start with AI for my first question. As you think about what you've accomplished with autonomous lift and preventative 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?

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 three buckets.

The first is kind of the table stakes bucket of higher productivity per employee, menial tasks getting automated, and making employees have more free time to do their work versus accomplished tasks. 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's going to talk about that.

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 billion or multibillion-dollar wins on the AI side. Chad seen some wins in the field.

He's going to talk about a couple of them.

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. Starting there, we put an example in the note about plunger lift.

Really, the success we're seeing there is the deployment there is working really, really well. Those are totally autonomous, self-optimizing solutions and yielding both a savings in terms of manpower and the amount of compression that we're using in that solution.

We're just carrying that forward across every form of artificial lift that we have out there and seeing a lot of success with the various trials and demonstrations that we're doing. Then you leverage that into how we use our people, and we also put an example in there of what we're moving into some drone technology so that we can ultimately move our folks from having to go hunt for issues in the field to we identify those up front, and we deploy them to go fix and address issues.

It's a much better usage of our personnel, allows us to scale the business much more effectively. We're doing that with production offside, and then that same type of effort carrying through every discipline in the company across our operations, whether it's drilling, completions, you name it.

It's still early innings, and we've got a lot of runway to go, but we're excited with what we're seeing today.

Great, sounds 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%?

Another question just to make sure I understand the distinction or difference perhaps, is there a difference between the surfactants that you guys are talking about and what we're hearing from Chevron with advanced chemicals?

Derrick, great question, man. I think it's TBD on how much incremental recovery can you get.

We've tested a lot of chemicals in the lab with core and fluids that are from the reservoirs. Some of the results that you get in the lab work are pretty impressive, right?

I think the thing that we're excited about is even a 1 to 2% uplift in recovery factor would represent a 50 to 100,000 barrel per well uplift, which would obviously be very meaningful to Diamondback. 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 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.

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 work, the different techniques, how we deploy them in the field.

There's a lot of variables remaining for us to optimize, but overall, I think just being early innings, we're very excited about the results that we're seeing.

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.

Terrific, great update, guys.

Thanks for having me on, guys. Kaes, I wonder if you can bite to the Barnett.

The early productivity looks pretty impressive. The capital's moving in the right direction.

I'm trying to understand, at what point do you get to full-field development to the point where your 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?

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 you would expect, that should improve sustaining capital or, on a push basis, it should extend our ability to maintain sustaining capital around where it is today. That's kind of how I would frame it.

Al, you have anything to add there?

Doug, I think, when you look at slide 11 here, and we show some equivalencies on rate of return, NPV, 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? We're using sort of base assumptions of 100% working interest and 1/4 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. There are areas that are going to be high-graded that we know we see a little better well performance, right?

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 of the 12 to 18-month gross capital efficiency, rate of return, and then PV is already well in excess of the core program. We know the resources there in the codevelop 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. We're very excited about the program, and there are going to be areas that compete for capital today.

That was helpful. Sounds like less wells for the same result, basically.

Good for capital efficiency is the punch line, it sounds like. I guess my follow-up is a quick accounting question.

Obviously, pretty elevated oil prices, 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?

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 of higher cash taxes, but yeah, we're paying our fair share, Doug.

All right, fair point. Thanks, fellas.

Thank you.

Hey, thanks for taking my question. Maybe coming back to the megatheme on gas, you obviously are going to get a cash flow benefit from higher Waha prices, but are there any operational or inventory uplifts from the higher gas prices?

Maybe are there parts of your acreage program that you haven't drilled due to the prices, which maybe in the drilling queue in coming years?

We certainly have that in the inventory. It just hasn't been something we've had to or tried to drill to date.

I think that you're going to see across the basin a lot higher gas cuts in certain zones and certain areas, and we have some of it. We just haven't had to drill it yet.

That's fair. 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?

GP&T is really kind of a mix between your gas realization and your GP&T cost depending on how much gas we take in kind. I would say the beat that we're most focused on is the stuff we can control, which is LOE, but on the GP&T side, it's really just a mix between realizations and how much GP&T you pay.

Appreciate it. Thanks, Kaes.

Thanks, Kevin.

Hey, guys. I had a quick follow-up on the AI optimization of artificial lift.

You reference savings in manpower, compression, but what about productivity uplift from that?

That's a great point. We are definitely seeing the productivity uplift and the downtime minimization as you have storms and so forth come through.

When you think about the effects on LOE, our teams are just doing a fantastic job controlling costs in somewhat of an inflationary environment. The other side of that equation, on the volume side, the technology's helping, but the responsiveness of our teams to managing the downtime and coupling that with the benefit you get from the AI autonomous controls has been a huge win for us.

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?

Just a matter of months to get those up and running.

Excellent. Thank you, guys.

Thanks, Geoff.

Hi, good morning. Thank you for taking my question.

Thank you. Appreciate all the comments earlier about the chemicals, EOR.

Just a follow-up on that, in what inning you are in terms of understanding that technology and feeling comfortable about a broader deployment? Maybe just how much capital do you think will be appropriate to be putting into that technology right now?

I think we just threw the first pitch, Betty. This is like a Wolfcamp B frac in Upton County in 2012, right, compared to where we are today.

I think our investors would like us to continue to spend capital here. It's not a huge dollar amount, $50 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'll attract more capital.

Makes sense. Then for my follow-up, wanted to ask about just the activity cadence and how to think about a normalized development program going forward.

There was a lot of footage that came online in the last couple quarters, and then 4Q, at least based on the guidance, implied a lower completion quarter on a footage basis, and then 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 two periods fit together, maybe any lag between the till and the production contribution, and then how to think about what would be a normalized completion till cadence on a maintenance level basis?

I think the base case is run 19 to 20 rigs and run the five frac crews consistently. I think that's where our head's at right now, and whether that spits out 120 tils in a quarter or 140 is just going to be dependent upon when those wells are popped.

In general, we're running a very level-loaded program that should spit out some organic growth.

Got it, makes sense. Thank you.

Thanks, operator. Thanks, guys.

Thanks for taking my questions. Was hoping I could maybe follow up on Betty question just on '27, and Kaes, an earlier comment you made in the call around CapEx.

If you were to run the five crews through '27, is that the high end of 4Q's CapEx, a number, the 1050? Is that what we should expect for quarterly CapEx in '27, or is it a bit higher to get that low single-digit growth?

I don't know, Gabe, today. There's still a lot of variables out there.

Probably say at $100 oil, it probably is a little higher, but we'll see what happens over the next few months.

Good morning. Thanks for taking my question.

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, cuz the gap relative to peers looks to be greater than for the kind of core Midland Basin programs. 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? Then maybe just talk a little bit about the plan shift into full development mode, as you mentioned, I think, the Barnett is about 20% of drilling activities as we stand here today?

Arun. I think just generally, the team had a very specific strategy on where they wanted to target.

As I've said many times on this call, we're basin experts. We just think about this basin day in and day out, and we had a thesis that seems to be proving out in the geology, and I think that separation will continue.

Understood. Then as a follow-up, Kaes, if you ran kind of five frac crews, 19 rigs or so in 2027, ballpark, how much footage would that kind of generate relative to the 6.4 million foot of completed lateral this year?

Relatively flat to this year, Arun.

Relatively flat, okay. Great.

I'll turn it back. Thank you.

Thanks.

Good morning, Kaes, 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've mostly addressed this, but just one other dimension perhaps. It sounds like the big determinants of this productivity you're seeing are reservoir energy and the thickness, you're choosing the best places.

Is there anything else that has surprised you guys, or do those two factors explain most of this uplift that we're seeing?"

I think geology drives the day, right, Charles? We've picked some really good spots to get going here.

I think we're learning the areal extent of what's good, and I think if we take it back to 30,000 feet, this is a play that was funded via Diamondback's cash flow and done at very low acreage prices and on a full-cycle basis, this probably one of the best investments we've ever made.

That's a good characterization. Then, Kaes, I'm going to ask you to 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 demand-pull.

The way I interpret that is it's kind of, to put it in a phrase, it's like, look, we're doing a B and a half a day without even trying. Assuming you had the price signal and you wanted to try, 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 5 or 6 years, but what would yours guess be?

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?

It's not just what you're receiving at the wellhead, it's what's the processing cost, what's your cost to move it down the pipe, and then what's a buyer buying it at? I think we're probably still a long way from drilling for gas specifically.

I think it's naturally just going to happen. 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.

That's great detail. Thank you, Kaes.

Appreciate it.

Thanks, Charles.

Hey, guys. 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, where it actually goes 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 2030s?

I think 11's achievable in the next couple years. The question is, how do you get from 10 to 20?

Obviously, much larger oil companies talked about that in this basin, and I think there's probably some use cases that are working in the lab or early tests in the field that give me some hope that that's probably possible in the next decade. I think strategy-wise, Leo, we have the longest duration inventory in the basin at the lowest cost structure, we're going to be the last company that has to try this stuff.

If these methodologies become better rate of return than what we have left to drill, then we'll pivot to allocating more capital to them. 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.

That certainly makes sense. Then just to kind of be clear on your comments just around thoughts going forward, presumably, you're still fully in green light mode here today at this point in time.

I know '27's TBD, but at least for now, it doesn't seem like there's anything that's moving you guys off green light in the near term.

That's right. It's been a couple months or a couple quarters since the stoplight went into retirement, but we're still in the green light.

Okay. Thanks, guys.

Thank you.

Thanks, everybody, for the time. New record, 65 minutes and appreciate everyone making the effort.

Thank you for your interest, and we're available to answer any questions if you have any.