Diamondback Energy (FANG) Q2 2026 earnings call transcript

Thank you, Grace. Good morning, and welcome to Diamondback Energy's second quarter 2026 conference call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback's website. Representing DynoVac today are Case Vanthaus, CEO, Danny Wesson, COO, Jerry Thompson, CFO, and now Bartman, 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 in businesses. We caution you that actual results could differ materially from those that are indicating these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's values with 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 released issued yesterday afternoon. I'll now turn the call over to Case.

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

Yeah, Neil, you know, I think it's been pretty hard to predict what's going to happen globally over the last couple months. You know, certainly our opinion and the data shows that, you know, inventories are draining, you know, not only on the oil side but on the product side. And, you know, absent permanent demand destruction, which, you know, we're hopeful is not the case, you know, those inventories are going to have to be refilled. And, you know, we can debate at what price those inventories need to be refilled, but I do think that helps us, you know, get some confidence that there's a bid for – a longer-term bid for oil to, you know, refill those inventories and meet, you know, global demand.

So in general, you know, I think that does skew us towards the decision to, you know, grow production versus hold production flat. You know, we were the first to respond to the price signals in March to, you know, increase our production for the year, you know, by 3% or 4%, you know, versus original plan. You know, the team executed on that very, very quickly to where we are today, you know, up, you know, somewhere around 4% from where we started the year. And, you know, I think the goalposts are for us, you know, going into next year, you know, do we hold production flat, which we're kind of doing from these higher elevated levels right now in Q3, or do we, you know, grow organically off of this number in a capital-efficient way?

And, you know, right now the model spits out, you know, some form of, you know, low single-digit organic growth, you know, while maintaining capital efficiency and running, you know, five frat crews consistently throughout the year. So I think in today's environment, you know, betting on the need to refill inventories, that's probably where our head is today.

But, you know, as you've seen in the past, Diamondback can react quickly to the positive or the negative. And I think in this environment, it's prudent to be able to do that. So there's a lot of uncertainty out there, Neil. I think, you know, our bet is that, you know, these global inventories, including SPRs, are going to need to be refilled. And that should be a positive for Diamondback shareholders and Diamondback's growth trajectory.

Yes, I mean, I think, you know, slide 10 is the most important slide in our deck when it comes to the technical aspects of our business and how we're, you know, making capital allocation decisions in the field. So, you know, it's been in there for a couple of quarters now, and, you know, we've put in some data on year-to-date performance, and clearly, you know, we're having a good year in 2026 so far.

You know, and I kind of steal a comment from one of our competitors, because I think his comment's smart in that, you know, this is kind of a stacked innovation, you know, play, right? We've done a lot of things in terms of well construction, well targeting, stimulation, and that's leading to better results. And we didn't get here overnight, right? We started by drilling wells in 30 days. Now we're drilling them in five. But our culture and our organization is a continuous improvement culture that has led to these results today. So, you know, high level, you know, we try to blend the best mix of most walls per section right on the bottom left of that slide, multiplied by the most production per well.

And clearly, you know, Diamondback operates at the lowest cost per well, and that should generate or does generate the most NPV per section or acre or asset, you know, in the basin. And, you know, we're very proud of that, and we've got to keep working on that to continuously improve the business.

Al, do you want to add anything on what we've changed and done over the last couple of years? Yeah, I mean, like you said, I think it's really about maximizing the return on every DSU, every well that we put in a DSU, Neil. I mean, the specifics, you know, when you think about well construction, doing larger tubulars that allows us to flow the wells back more aggressively, you know, on the stimulation side, stage architecture and perforating, and then on the targeting side, you know, the technical teams taking a deep dive, looking at how we target every well within the DSU, I think is what we're seeing leading to the outperformance on the page here.

Yeah, so it's a lot of little wins, Neil. You know, we've got to stack up those little wins and keep doing that to maintain our position.

Yeah, Neil, anything is relief compared to Q2. So we're happy to see these new pipes start to flow. We've seen some announcements from both Energy Transfer and Whitewater that the two big pipes are moving forward.

You know, that's resulted in Waha being positive for the whole month of July and certainly a nice tailwind for us and for our shareholders in the near term. But, you know, I'll take it a little higher level because I think, you know, I think we believe in the gas mega theme. It's not, you know, core to Diamondback's value proposition, but it can be additive to, you know, the amount of oil we produce And in general, I think that means, you know, us owning more space to the Gulf Coast, and we can debate where that needs to go in the Gulf Coast. But certainly the large demand centers are going to be along those pipelines for either, you know, power projects or data centers.

And then, you know, the rest of the gas that gets to the Gulf Coast is going to, you know, cross the docks in the LNG terminals. And, you know, I think I'm not smart enough to figure this out today, but, you know, the question is going to be how much demand can the world, you know, handle from an LNG perspective, because we're certainly going to have enough supply coming out of the U. S. on the LNG side. And to fill that, you know, I think the Permian is going to play a big role, and I think Dynaback is going to play a big role. So, you know, our gas production continues to outperform expectations. I think that will continue over the next, you know, 10-plus years, and therefore we need to have more contracted space to more markets to be in the conversation when the LNG optakers need supply.

So, you know, we're meeting new people in that world and building relationships because I do think kind of the wellhead to water gas strategy has to be part of the Diamondback proposition. On top of that, we also believe in the power of data center mega theme, and we have a project that we've been working on, and Jerry's going to give you some color on where we are.

Yeah, Neil, great question. For some background, we and our IPP partner put together what we view as a very unique bridge-to-grid solution on our 30,000-acre Bryant Ranch location, ultimately to deliver scalable, reliable power near Midland, Texas. We have secured distributed power generation, remediated land, and directed access to dedicated NAC gas and water supply. All of this should allow us to provide a shovel-ready development project delivering first gas as soon as the back half of 2027 through the use of behind-the-meter resip units. Beyond this initial phase of power generation, we are working to secure grid-connected power as soon as 2028 via batch zero. We believe we are well positioned within the batch zero queue and are awaiting ERCOT spinal determination regarding project eligibility for the next interconnection study as soon as they're meeting on August 20th.

We are closely monitoring communication out of Austin and remain confident in a project like ours with low water use and new generation, ultimately meeting batch zero standards. We'll give the market a larger update once we've signed definitive documentation with a hyperscaler, but are confident in the direction that this project is going.

Yeah, you know, Neil, I'll add one thing. I was in a room with a lot of the tech world about a year and a half ago. It's kind of a mix of energy and tech. And, you know, the energy side of the equation kind of got laughed out of a room when we suggested to come to West Texas and build behind the meter.

And, you know, someone that was in that meeting called me last week and reminded me of that and said, I'm coming to West Texas and I want to build behind the meter. So I do think we offer a lot of opportunity out here. At the end of the day, Diamondback's going to stay in our lane, which is produce the molecules, provide the surface, provide the water, provide the industry know-how.

We're not a power company. We're not a data center company, but we certainly can play an important role in this ecosystem that's coming together.

Yeah, so let me just frame the goal, right? The goal for us is to maximize and capitalize on the option value that is inherent in this business, right? We live in a very volatile business where things can change overnight. And, you know, we felt that a formula or any sort of restriction on capital allocation, you know, does not allow for the maximization of that option value. So, you know, that's why we, you know, last quarter as prices rose, we said, listen, and we're not going to commit to returning a minimum percentage of free cash just because we have to. And we removed that minimum commitment.

And, you know, there was a lot of discussion on the call about it. There was a lot of discussion in the couple days afterwards, you know, with shareholders explaining our case, and they were very supportive. And, you know, since then I have not heard a lot about it from long-only shareholders. They've been supportive. And then you look at what we did right So we did allocate a little bit to the buyback in Q2 as weakness stepped in at the end of the quarter We allocated a little bit to the buyback here in Q3 You can see that those numbers that we're willing to buy back at have gone up.

But we also reduced net debt by $1.6 billion. And, you know, that translates to $5.60 a share of value that went from the debt side of the equation to the equity side because in my mind, our NAV didn't go down much in the second quarter. In fact, it went up. So I think it's more about look at what we've done versus what we're going to do. And I do think investors know that we will lean in on the buyback when it presents itself. You look at a year like 2025, we bought back over 5% of our stock. I wish it was 10%, right? And now I think we're positioning the balance sheet to be in a position where we actually can lean on it to buy back shares.

when the cycle turns in this volatile business. So really just trying to make the right capital allocation decision every day. And just like the stacked innovation in the field, if we can stack up those wins on return of capital, I think that's a long-term win for our shareholders.

Hey, Scott, Danny. You know, great question. I think, you know, it's multiple different things. I'll let Al, you know, talk on the technicals. But I think, you know, just the biggest driver has been really an improvement in our ability to market our gas locally. You know, as the GMPs have continued to mature their systems and build in redundancy, and we've worked with our gathering and processing partners to add split connects in really strategic areas, we've really improved on our, you know, our flaring metrics, and thus we've improved in our gas processing and selling gas.

You know, it doesn't feel good to sell it at a negative price, but, you know, we've gotten to a point where we've really gotten a lot better at marketing the gas downstream. And that's the biggest needle mover, and, you know, I'll let Al cover any other of the, you know, technical background on the gas number.

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

Yeah, another good question. I think, you know, we have optics into some inflation, you know, mainly tied to some of our consumables. Obviously, we've talked about fuel costs in the past with, you know, the rise in commodity prices, and, you know, that's still here. Thankfully, our biggest fuel consumption would be on the completion side with the frack fleets, but all of our frack fleets are currently electric fleets. So we've kind of mitigated that inflation hurdle through utilizing the electric fleets.

You know, what we're seeing in the future, casing prices in the back half of the year are going to come up. That's really the big needle mover. we think it's about one, a little over 1% of our total well cost in inflation. So not much. And we think we can offset it with efficiency gains. You know, it's a little early to talk about 27. But, you know, I think somewhere around, you know, a billion to a little bit over a billion dollars a quarter run rate to hold production flat is reasonable with what we see today. But, But, you know, if we continue to add rigs in the U. S. , and, you know, I think we're up 60 rigs from the bottom.

If we continue to go, and there's some forecast out there up to 80-ish rigs being picked up, you know, we anticipate we're going to see some more pressure. But, you know, time will tell. And what happens in the gas basins along with what happens in the oil basins, you know, what activity does. And, you know, as we get closer to 27, we'll be able to talk to you guys more about what we anticipate inflation to do. But right now, that's where we're at. And, you know, we're going to try and fight the variable cost side of it, like we've always done, and drive efficiencies to reclaim any inflation we see on the consumable side.

Yeah, Rune, I mean, stepping back to earlier this year, we did a big reveal in our Barnett position. Since then, that position has continued to grow, continued to block it up as well so that we can have, you know, longer lateral development as we start developing the position aggressively, you know, basically now. You know, our first four-well pad in Spanish Trail has been drilled and will be completed in the next couple months. So, you know, it'll be interesting to see, you know, full-section results kind of end of the year, end of next year.

Obviously, with the Viper Minerals, that's going to be a very high-return project, and that will also give us a really good idea into the cost side, right? I mean, since the beginning, it's been a couple wells here, a couple wells there. We haven't done a full section with an E-Fleet simul-frack crew getting the cost down on the completion side.

I will say, you know, we're seeing winds on the drilling side. I think we're more on our front foot than anybody else in the basin on barnet exposure and drilling costs. And, you know, they're getting closer to $400 a foot. I think we have, you know, 5% or 10% to go. There have been a couple wells below $400 a foot. But, you know, I think we expect to consistently get to around that $400 or less per foot number to make, you know, returns competitive with the base plan.

Got it. Got it. Okay.

Yes, I mean, just like, you know, we think the gas power AI theme is a mega theme. I think on the oil side, you know, enhanced recovery or improving recoveries out of this basin is going to be a mega theme as well. on the oil front. You know, I think generally, you know, given our size and scale and asset base, we certainly need to be, as we said in the letter, we need to be in our front foot on this. I don't think we need to be tip of the spear, but we certainly need to be spending dollars to understand what's happening. And that project, you know, kicked off last year with our first surfactant program where we learned a lot.

And I'll let Al update you on what we're seeing today and what we expect in the future. But my high level is, you know, you're going to hear a lot about all this kind of stuff from large operators over the coming years.

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

Yeah, I think there's two ways to think about it. I think it either reduces your base decline or it's a replacement of capital for something that's higher returning.

To date, we've only done remedial work where we go back in existing well bores to learn about this treatment process, but we are now also incorporating it into some of our pads where we have on the new well side, where we have a control half of the section and a surfactant half of the section. So, you know, moving with haste and learning a lot pretty quickly here.

Hey, John. Yeah, thanks. Great question. We, you know, we continue to try and push the, you know, manufacturing mode kind of mindset with regards to the surface operations on the completion. And, you know, I think there's 24 hours in a day, so I don't think the team's going to quit until they can get to a point where they're pumping a full 24 hours. But in reality, there is maintenance associated with the equipment on location and, you know, every piece of redundancy costs money. So there's a balance between, you know, adding more equipment out there to get redundancy and how many hours in a day you're pumping. And, you know, that's been the fight with the team on, you know, doing trimul frack work versus simul frack work and those things.

But, you know, they continue to look at how do they push efficiency, push pumping hours, push rate to get more done in a single day. You know, I think we've seen some pads that we've, you know, we've broached the 5,000-plus foot a day on average. and I think that's kind of the next bogey for us is how do we get to, you know, achieving 5,000 feet per day across all of our crews every day.

And so I do think that's achievable and something that we can hopefully talk about in the next year or so when they get to that point. But, you know, they're working on it. They're applying new technology at the surface and, you know, continues to get better.

Yeah, very little, John. I mean, you know, we're continuing the Barnett leasing play with our partners at Double Eagle, so that's continuing onward. And, you know, I'd say outside of that, I've actually been very pleased that the team has been finding, you know, call it $20 to $100 million deals to either net up or, you know, extend laterals or block up our position.

And they've been finding them pretty consistently. I mean, about, you know, kind of one sizable deal a quarter. And I think, you know, looking into Q3, we've got another couple small ones. So, you know, those don't get headlines, but they add up, right? All of this ties into, you know, our corporate NAV, you know, higher working interest, longer laterals, you know, should result in a higher stock price.

You know, done with cash, which is important, John. And the thing I say about the Barnett position we built we built that at a very low cost of entry with cash That position is worth multiples of that today That should just accrue directly to shareholders.

Good morning, Phil. I'm curious, when you look at the mid-cycle NAV, which I think you mentioned earlier, you feel like went up during the quarter, obviously oil price is the main driver here. I think you can serve the leaves around 65. But the question is more just how much do you think some of the operational improvements and resource expansion initiatives you've achieved can contribute to a higher NAV plus just more volumes or growth?

So just wondering how meaningful overall these are based on your assessments to value and whether improvements to the business can contribute to the thought process around intrinsic value and future capital returns. Yeah, that's a great question. You know, they 100% do, and I'll take you down a little bit down memory lane here. You know, we put our buyback program in place post-COVID at, you know, I think Q3 of 2021, and we told investors we were going to buy back shares at a mid-cycle price at a rate of return above our cost of capital.

And that initial top was $90 a share. And, you know, here we are five years later. We've obviously done a lot in terms of M&A. The asset base has expanded, you know, from a zone perspective. You know, things like the Barnett, things like Joe Mill, middle sprayberry, you know, weren't big things in 2021. Upper sprayberry, obviously the cost structure, the lateral lengths. I mean, everything that the team has done in terms of execution in the field, but also adding to the asset base in an accretive manner, has resulted in that top going up significantly, you know, more than doubling since that moment. So, you know, people ask me what's the future value creation opportunities for Diamondback, and, you know, you look back five years ago and you say we doubled the value of the company at the same parameters, right?

We've stuck to our guns on what we think mid-cycle is from a price perspective. We've stuck to our guns on what the rate of return is. But the rest of the business has driven those improvements, and I expect that to continue.

Yeah, Philip, it's Jerry. A great question. I think the biggest driver for us is just having a new in-basin egress solution for NatGas. You know, we're setting aside $200 to $250 million a day for this project. And you think about contract structure, ideally you're getting something that's like a law plus with a floor and for us you know based off of what we've seen over the past couple of quarters this would provide a material uplift you're exactly right as it relates to the other revenue streams this could have a material benefit for deep blue of which we own 30 percent there's some land proceeds that likely could come through the door either as a one-time payment or structured as a royalty and you know these are just kind of scratching the surface of what we're seeing.

So really excited about it, but I think NatGas is the one that we're focused on.

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

Yeah, so great question. We haven't completed the six wells that we've drilled thus far. We're still in the middle of developing that pad. I think, you know, on the drilling front, it was certainly, you know, a success for us. You know, some things that we learned and some challenges we saw, but, you know, we still saw, you know, lower per foot well costs than drilling standalone 7,500 footers.

You know, we've completed some U-turn wells that we inherited from an acquisition, and those were short 5,000-foot U-turns to 10,000-foot total lateral length, and everything went great on the completion front with those. But, you know, this will be our first fully developed Diamondback pad. We just haven't gotten it on production yet, but as far as the pad we inherited productivity-wise and execution-wise, you know, it was in line with what we would see from a regular, you know, straight 10,000-foot well.

Yeah, I think if you look at the top line, top X number, you know, the dollars were actually flat quarter over quarter. So the LOE beat was driven by, you know, the production beat. I think, you know, the team has done a really remarkable job of fighting off some of the cost pressures we're seeing from power, from water, and doing the things that they can do, the little things they do, to save, you know, a dollar here and there that adds up. And, you know, I think we're still going to see, you know, I don't think we're going to see LOE trend down in the back half of the year. I think we like that kind of circling that $6 number or a little higher.

But, you know, I think if we continue to see volume outperformance, we could see some upside to that number. But, you know, I do believe that some of this inflation stuff we have on power and water and tubulars, you know, will flow through on the top line LOE number as well. So, you know, the team feels pretty confident in that $6 range, you know, but, again, that denominator is a pretty big number. So, you know, it was just a great quarter on the productivity front and helped drive the beat on OpEx.

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

Yeah, both good questions. I think there's a near-term discussion and a long-term discussion on both of them. I think on the debate of taking productivity and reducing CapEx or increasing production, I think today in today's market, we made that decision to spend more within our budget, but growth is the output. I think there's going to be a debate throughout the years. Some years it's going to be obvious to grow organically, in some years, you know, are going to be like 2025 and 2024, where it made sense to cut the CapEx and return more cash to shareholders. So I think we'll maintain flexibility there, Doug. And, you know, I think that also then ties to your other question, which is, you know, where are we prepared to take the balance sheet?

And, you know, I think that there's some near-term aspects that we want to cover, right? We want to put enough cash on the balance sheet to take care of our 2026s, which are callable in a couple months, and also be prepared to take out our 2027s. And that puts us in a position where we could build cash beyond that to tackle the maturity tower we have kind of in the 2029 to 2032 timeframe. So, you know, I'm certainly not afraid to put some cash on the balance sheet.

I think it's a good idea and it's prudent at this point in the cycle because we know that you know cycles turn and you know the one thing I will say to give investors comfort is you know we're not building cash here to do you know big cash deals and and you know blow up the balance sheet you know doing deals that's not what we're here for we're here to you know growth still want to grow the business and look at opportunities but if you look at our history of how we've done M&A it's very rarely been a significant amount of cash in any of these deals.

Thanks, Doug.

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

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

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

Yeah, Paul, we got you.

I think on the other businesses, you know, I certainly don't have any power value in our NAV. You know, we do have a good amount of midstream value with our deep blue investment. You know, it's been interesting to watch multiples expand on the, you know, the water side of the equation as I think more attention gets brought to that business line in this basin. So, you know, I think we're going to be very money ahead on that investment. But all of that ties up together. and a reduced share count and a lower debt-dead value pops out of a higher per share value.

Gabe, good question. I mean, we haven't seen anything yet in terms of constraints on our system. I mean, I think what this means is, you know, you have to have significant capacity. You have to have a large interconnected system. You know, the days of, you know, one or two SWDs being hooked up to a system, you know, makes no sense. And, you know, I think we have that valuable partnership with Deep Blue, where they are investing capital to loop certain lines, connect certain areas, add SWD capacity to make sure that those issues don't happen to us.

You know, the water discussion is certainly getting a lot more attention in this basin. You know, I think the Delaware Basin, obviously, given the amount of water produced there, is, you know, working to solve these problems probably sooner than the Midland Basin will need to. But I think there's a lot of lessons and a lot of learnings that we're following from what those businesses are doing over there or companies are doing over there that we can translate over here. But in general, I would say Deep Blue has used the asset base that we gave them with Diamondback as the anchor customer and done a great job adding third-party business and also working to connect the system and improve it.

I think generally the number will go up slightly, but within that number, the mix will move. As we get to large-scale barnet development in areas where we don't have existing infrastructure, we're going to have to build new batteries, and we're working on that design and making that design tailored towards what a barnet well looks like versus what Wolfberry wells look like.

As in any deal or any expansion, infrastructure capital is higher in the beginning and then reduces. but I think generally that number is close with a little bit of upside next year.

Thanks, Gus. Thank you.

Thanks, Terry.

Yeah, I mean, I think generally, you know, high level, it's been the combination of how Endeavor was doing things and how we were doing things and finding the best of both on the equip side. I don't know if Danny or Al, you want to have any details. I mean, a lot of it's driven by just extending lateral lengths, right? I mean, that's the biggest lever we have to pull, and, you know, it's one of the reasons why we're starting to lean into some of the U-turn development, because, you know, we talk about a lot of, like, what is the efficient frontier for lateral lengths, and can we get to a point where, you know, our average lateral length continues to creep up beyond 12,000 feet, and, you know, it just drives so much more efficiency.

And so that's really what you're seeing. The biggest change is just, hey, you know, a little longer laterals and you need the same flow lines and same tubing and all that for that well. It just drives down your per foot cost. And I think some things have come out of the scope as well. So, you know, we're always looking at each little line item, but, you know, Danny's point is, you know, the equip piece and the infrastructure piece, that's nonproductive capital, right? And we want to minimize the non-oil producing capital in our CapEx budget.

Yeah, Derek, great question. And really, it's figuring out which rock types and lithologies, the technology, the specific surfactant technology we're applying works best in and where we're seeing the best returns. And then looking at the overall portfolio of the thousands of wells that we operate, where are those rock types situated? And then thinking about sort of the chemical composition of the surfactant and which ones are working best and which different rock types. And so that's sort of the ongoing process. And like I said earlier, I think we're really just early innings on this and the team's learning a lot. And the initial results that we're seeing from this 12-wheel package are really promising. But we're going to learn a lot from these 12 and apply it to the next group of wells that we do in the future.

And, you know, I think this is something that, like Case talked about earlier, where we could see some shallowing of the decline rate and then the decision on, you know, do we take capital out of the system or do we lean in? But, yeah, overall, that's sort of the details of where we are today.

Thanks, sir.

Yeah, I mean, listen, I think it's been – it's probably not our place to comment on geopolitical events and instead focus on, you know, global inventories. And, you know, I think the relationship between inventories and price has broken down a little bit over the last couple months, but I think that's probably because there's noise in the system. Someone smarter than me explained the market as basically a sine wave because of everything that's happened and everything's been disrupted.

And at times there's going to be heightened volatility on the upside and heightened volatility on the downside with, you know, a steady state, you know, far from a possibility today. So I think, you know, generally chasing headlines over the last three months has been exhausting. and I think we've decided to just kind of put our head down and believe that crude oil that comes out of inventories today has to be replaced tomorrow and over a multi-year period that should result in a bid for oil for a longer period of time here.

And perhaps you could also talk about what, you know, the other side of the equation there, what you're seeing in productivity trends in the Wolf Camp D. Yeah, so, you know, from a cost perspective, the team had a budget of like 350, 360 a foot, and their stretch goal was to drill wells at 300 a foot, and they're actually hitting their stretch goal, so that does improve the returns of the Wolf Camp D. You know, what has brought more Wolf Camp D into our program is that when we merged with Endeavor, you know, they had some acreage in kind of the sweet spot of the Wolf Camp D, kind of Midland County, eastern Midland County, versus where, you know, our prior asset base didn't have as much upside.

But, you know, in general, you know, as these other zones get more airtime, you know, I want you to pay attention to productivity. Because traditionally, if someone brings in, if a company brings in a lot of secondary zones that they hadn't been developing to date, you know, their productivity per foot takes a hit. And our productivity per foot while adding these zones has been consistent to now up this year. So credit to the team, but I think it's also just a combination of a larger asset base with more places to allocate capital post-endeavor.

Thanks, Charles.

Yeah, I mean, while there's no capital being allocated to the Delaware this year, There are some interesting things happening over there.

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

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

Thanks, Leo.

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