Diamondback Energy Inc (FANG) — Q4 2025 Earnings Call Transcript

Thank you, Corey. Good morning, and welcome to Diamondback Energy's Fourth Quarter 2025 Conference Call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback's website. Representing Diamondback today are Kaes Van't Hof, CEO; Danny Wesson, COO; Jere Thompson, CFO; and Al Barkmann, Chief Engineer. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Kaes.

Thanks, Adam, and welcome, everyone, to the fourth quarter earnings call. As usual, we will open up the line for questions. I hope everybody read the letter last night, a lot of good detail in there, and we look forward to discussing. So operator, please open the line for questions.

Thank you for jumping right into it. And no surprise, the area we want to dig into here is the Barnett case. And just talk about what you think the opportunity set is you are deploying more capital here in 2026, how you think about the potential returns associated with it and just the mix as well between oil and gas.

Yes, Neil, I'll give you some high-level thoughts and then turn it over to Al, but it's a pretty exciting reveal of our position in the Barnett. That's a position that was essentially almost zero acres a couple of years ago. We were able to grow that position without capital raises or press releases or buying the next private equity-backed entity. So I think overall, being able to build a position in our backyard that we understand very well is going to be very good for our shareholders long-term and good for corporate returns long-term. We're not having to pay $3 million, $4 million, $5 million, $6 million of stick to build this position. And that's a testament to the team having belief in the rock. And now that we've put the drill bit in the rock, we found that the returns look very good from a productivity standpoint. The next step is we have to get the cost down. We haven't really moved to full field development. That's going to start here in the second half of 2026 in earnest and pick up in the coming years. So I think it's a good time for us to reveal what we have. We're not done yet, but I wanted to show our investors what we've been up to. And that resource expansion is an important part of our overall story. I'm going to turn it over to Al for some details and what he's found from a technical perspective.

Yes, Neil, I think if you look at Slide 12 here in the deck, you can see we've shown the performance of our 2025 Barnett plan here relative to our core development plan. And I think the performance really stands out speaks for itself. And I think when we're able to get the cost down 20% kind of from where we are with our delineation wells here, we think these returns are going to be competitive. So we're pretty excited about the potential here, 900 gross locations, and I think we'll be allocating capital to the plan more going forward.

Yes. And that's a good follow-up, which is just talk about the product mix here. On Slide 12, you show that there is more gas that comes out of the Barnett, but actually, there's potentially more oil as well. So it's probably a little oilier than some of us would have thought. Just talk about how you're thinking about making sure that you're maximizing the liquids cut out of these barrels.

Yes. I think just looking at the absolute oil production, you can see that's even differential, right? And that's what we've got in the plot. The initial GORs are higher, right? So kind of in the 3,000 range. I think what's striking when you compare the 6-month cum oil and BOEs to the 12 months, you can see a flatter GOR profile relative to the core. So the GOR profile in the core zones ramps up a little faster. We're seeing a much flatter GOR profile through the 12-month period. So where your core zone is like 80% oil for that first 6 months, it goes down to about 75% oil. The Barnett plan that we're showing here is 67%, basically flat for the first 12 months. So a little different profile on the product mix. But overall, I think the oil productivity speaks for itself and is very competitive once we get the returns where we see them going.

Yes. And the only one thing I'd add is whether the timing is planned or not, we do have a Permian Basin that's going to have a lot of gas takeaway coming on in the 2027 to 2030 time frame. We're going to have to drill a lot of Barnett wells over that time period. The Barnett's a different type of lease. It's not held by vertical production or production in the core zone. So we've got a lot of drilling to do, but getting a good price for our gas and our liquids is going to be a benefit to returns in the 2027-plus timeframe.

It's Neal. Sticking with the Barnett, could you talk about the well economics there versus the Midland Basin? I guess what I'm getting at is I'm looking at Slide 12, it shows that your Barnett wells, you're talking about kind of a 36 MBOE per 1,000 foot 12-month cum versus 22 for the core Midland, yet you talked about maybe the $100 per lateral foot Barnett versus what are you down to, I think, $500 or $550 for the Midland cost. So curious how you're thinking about total returns, Barnett versus just the Barnett or the Midland average.

Yes. Why don't I hit the high level and let Danny talk about how we're going to get the cost down. High level, our core Midland development, which I would put as everything except the Wolfcamp D is close to about $510, $520 a foot. If we can get the Barnett down to $800 a foot and the Barnett oil production is 60% better on a first year cum than the core, then the returns start to get competitive. I think we're fortunate that the rock has been proven first and then the costs will need to come down. But Danny has a few examples of how we're going to do that.

Yes. I mean I think a lot of the cost reductions we're targeting are really just a decision to move to development mode and apply the techniques we've learned over the years developing what we call the Midland core with multi-pad development and simul-frac. Those things are really just a decision to go to that full-scale development and see those cost savings accrue to the Barnett development as well. On the drilling side, we've been pretty conservative in the drilling plan we laid out in the delineation wells, really just targeting successful wellbores. We have a lot of things we think we can apply in the drilling plans that we can cut a lot of cost out of the drilling part of the well. And also, we think the Barnett, the leasehold we've established in the Barnett sets itself up well for extended lateral development. So we're kind of targeting 15,000-foot laterals in the Barnett. It won't be everywhere, but we hope that the majority of the wells that we drill in that zone will be extended length laterals, 15,000 foot plus foot, which will also help drive down that per foot cost.

Great details. And then just secondly, my second is on inventory. And by the way, thanks for disclosing. I don't think any other companies have this kind of similar details around that. But I'm wondering, could you just address maybe talk about inventory replenishment and reinvestment in your existing asset base as it appears when you add the Barnett to your total drilled feet year-over-year only decreased minimally. So I'm just wondering how you're thinking about inventory replenishment and reinvesting going forward.

Yes. I mean, listen, we're in a depleting business, right? And we think about inventory every day. Diamondback was a company that went public with very little inventory and had to work for every stick that we added over the last 15 years. So it's something that's top of mind for me and for the team. And if you look at the inventory disclosure we put out, the team did a very good job increasing average lateral lengths last year, up by about 600 lateral feet on average, which is a big number for a big company. I think we're going to continue to try to add inventory where we can. If you notice, like I said earlier, all of this inventory was added and put in the plan without needing outside capital or press releases, all while still returning a ton of cash back to shareholders. So I think you should expect that to continue. I think we have a philosophy here that no deal on inventory in the Midland Basin should leave Midland or leave Diamondback without us taking a look at it. So we're highly focused on continuing to replenish our inventory. We recognize that it's not infinite. But I think we have a plan to continue to grow it.

My first one means to hit on the implications from some of the Barnett disclosure while also still keeping in mind legacy Midland core operations. We took note of the strong oil cums from both data sets in the slide as you guys have spoken to already. And obviously, the productivity for the Barnett looks strong as well on an absolute basis. So as you think about that, we were hoping you could speak to your outlook for corporate oil mix over time as you continue to develop your Midland Basin core inventory and work in more Barnett Woodford over time as well.

Yes. It's funny, Jeff. We have a $3.75 billion budget and $150 million is allocated to the Barnett, but it's getting all the airtime. But that's the market we live in. I think that means that investors trust the inventory that we have in the core, and they trust that we have enough of it. But at the end of the day, what the teams are doing on the core inventory, the vast majority of our budget is very impressive. Lateral lengths up year-over-year, productivity in a world where productivity is being questioned on a per-foot basis. In many basins, the team was able to increase productivity in 2025 versus 2024 on the oil side. That just means we're continuing to test things in terms of stage length, stage designs, where we're putting the drill bit, spacing, all the zones that we're developing, and the results kind of speak for themselves. I think generally, with the Barnett becoming a bigger piece of the capital pie, oil mix will go down over time, which is why we've tried to focus more on our gas marketing strategy and getting better realizations on that front because I think it can really help overall free cash and corporate returns after these pipes come on in the back half of 2026.

Perfect. That's very helpful. And then for my second question, I actually wanted to revisit something that's also not yet factored super meaningfully into guidance, at least for now, but is also exciting to think about, which is the hyperscaler and data center opportunity that you've spoken to in past quarters and on past calls and how Diamondback really offers the full suite of what a counterparty there would be looking for in terms of the surface acreage you added last year, the water supply potential, especially thinking about deep loop and, of course, gas or power from your upstream business. So I wonder if you could just get a refresh on how discussions are progressing there and how you're thinking about those opportunities in general.

Yes, Jere is going to take that one.

Yes. Jeff, you're exactly right. I mean we continue to be excited about the opportunity as we feel we have all the pieces for a very compelling project. And we're making progress on bringing data centers onto our surface position. I think as you think about Diamondback specifically, the biggest benefit here is our ability to structure a power purchase agreement that provides for material uplift to natural gas pricing. So just another creative tool in the toolbox for us as we are thinking about improving natural gas realizations, which we obviously highlighted in the deck and Kaes alluded to earlier. So a new meaningful in-basin egress solution for us. So we continue to make progress. We're excited about the opportunity. And when we have more to discuss publicly, we'll definitely do so.

Yes. I think the one thing I'd add there, Jeff, is we're not going to announce anything until it's completely binding and we can talk to our investors about what it means for them. There's been a lot of noise in this space. I still continue to believe that given our size and scale and expertise in the basin, we offer the full package and conversations have improved. But we're not going to talk about it in detail until we have those details, but a great question.

I'll also give the Barnett more airtime here. I appreciate you bringing resource expansion back to the E&P sector. But so the Midland Basin, it's obviously a large area. I was just hoping you could talk about how you see Barnett variability across either your or other operator wells across the northwestern side of the basin versus Southeast? And why do you think your Barnett well productivity has outperformed the industry to such an extent?

Yes. I think the big distinction that we see when you look at the map on Slide 12 here, the wells that are to the western side of the basin and actually up on the Central Basin Platform, which is really where the play began back in the late 2000-teens, that has lower maturity, so more within the oil window. But that comes along with lower bottom hole pressures. And so what we've seen in terms of 30-day IPs and 6-month cums is the well performance in that area where the play kind of kicked off is not as strong and robust as when you move down into the basin and you've got higher bottom hole pressures and you've got more gas in the system. So you're getting higher initial rates. I think the variability in GOR, we're still kind of delineating around the basin, especially as you move to the east and to the south. And so there is going to be variability in GOR. But I think one of the things that we really focused on from a technical standpoint is where can we find the best resource, the biggest resource and then the potential to drain the Barnett and the Woodford reservoirs with a single wellbore. We believe we've put together a really strong position in the best resource quality within the basin.

That's great. And then you called out Diamondback having nearly 2 decades of inventory at its 2026 pace. Last year, there was a lot of talk about peak Permian, who has inventory to grow, who doesn't. But for Diamondback, assuming a green light scenario, just how do you think about a sustainable growth rate that can be achieved for the company over a multiyear period given the depth of resource you have?

Yes. I mean, listen, I think it's highly dependent on the macro. But in general, it feels like investors over time want some form of growth. Now we've done it on a per-share basis for the last few years. At some point, organic growth is going to come into the equation. Unfortunately, we're still stuck in this yellow light and this stoplight analogy that we can't shake yet. But I think there's probably a world where if we can efficiently allocate capital and growth becomes the output, that's probably a good decision. I think for 2026, we're starting the year here still in this kind of quasi-yellow light where oil production is the input and then CapEx will be reduced if things go well and held steady if things go as planned. But it could be a world where we hold CapEx flat and see what growth comes out of it. But that day is not today. But there will be a time, and that's why every day, we think about inventory, inventory duration, inventory growth and things like the Barnett, which is getting a lot of airtime today, are accretive to that long-term duration story.

I also have a follow-up on the Barnett. Yes, just a follow-up on the Barnett. Looking at the 12-month cum plot on Slide 12, it looks like the average well is delivering just under 50% more oil cuts or mix over the first 12 months of the well. I just wanted to see if you could comment on your thoughts on what the Barnett would do for your oil growth over time because that's been just a question we've been getting just because there is a little bit higher gas you're getting, but the oil cut is higher than that. And if we could maybe translate that into an oil EUR for an average well based on your test so far?

Yes. I'll let Al give the EUR commentary. I think the one thing I would say is if you start to run these wells at $800 a foot or close to it, the rate of return relative to the base plan looks very comparable, but the PV is significantly larger. So we look at both of those things, PV and rate of return and try to find a nice balance there. But the key here is getting these costs down makes the returns competitive, particularly in areas with Viper minerals, but then the PV impact is huge. So from an NAV perspective, that's very positive. Now I'll turn it over to Al for some type curve commentary.

Yes, Arun. So that 50% uplift that you kind of see at the 12-month time frame roughly equates to the uplift that we see relative to the core zones on an EUR basis. So you think about our core zones, those are about 50 BO a foot in the Midland Basin. So right now, in the Barnett, we think we're pretty close to about 75 BO a foot for the ultimate recovery for those wells.

That's helpful, Al. Just on my follow-up, I was wondering, Kaes, in your shareholder letter, you mentioned how the company was testing for surfactants. And just give us a sense of how those pilot projects are going. Are you using surfactants in terms of your base production management? Are you testing those in terms of new completion activity? But give us a sense of what you're seeing thus far and how you're using those in terms of your development scheme?

Yes. It's early in the surfactant game, but it's exciting. We did a 60-well test in the second half of last year, a credit to the team to mobilize that quickly. This went from an idea in June to execution by December, and we got a lot of data coming in from those tests. We focused on the production side for now so that we can try to figure out which variables are working. I do think there's been some discussion about adding this to the front end on your completion. I think we're going to test that. We're also going to continue to test the production side of the business. From a high-level perspective, in my mind, this was something that no one talked about outside of papers, SPE papers 4 or 5 years ago, and now it's becoming something that can potentially be economic. I think that is why we put it in our last shareholder letter; never underestimate the American engineer because there's still a lot of oil in the ground in the Midland Basin and the Permian Basin that needs to be extracted. It just needs to be extracted economically, and that's what we're working on today. So Al, do you want to talk about the tests?

Yes. As Kaes mentioned, we conducted 60 treatments in the latter half of 2025. There has been considerable lab and technical work focused on designing the surfactant to match specific rock types and the surfactant variations we’re utilizing. While it’s still early in the results, we have observed some very promising outcomes in a few of the designated units where this was applied. The team is analyzing this information to refine the chemical composition and test design, aiming to better understand the factors that influence the program's performance.

Yes, I believe this is all a bonus. This represents additional production and reserves that we didn't expect a few years back. I would say this is the early stage of Wolfcamp B fracs, similar to what we saw in 2014. Looking at our progress over the last decade, we have come a long way. This is a highly technical team that will continue to work on finding solutions.

And I'm going to have to go back to the Barnett just because it seems to be the flavor of the day. If I compare your typical well, it's less than $600 a foot. You've got a path for the Barnett to get from $1,000 a foot to $800 a foot. But the top of the Wolfcamp versus the top of the Barnett are a couple of thousand feet apart. So not a whole lot of vertical depth. What's timing the drilling down there? Or is it on the completion side where those incremental costs are coming from? And what are some potential solutions?

Yes, Bob, thank you for your question. This operation requires a different approach compared to the Midland Basin core. In the Barnett, we are utilizing oil-based mud and adding an extra string of pipe in the vertical section of the well. We have been taking steps to reduce any potential operational risks as we explore this play. I anticipate that we will maintain a cautious approach as we transition into the development phase of drilling, while also looking for ways to reduce costs based on calculated risks. On the completion side, there will be additional expenses due to larger job sizes. We aim to drill four wells per section in the Barnett, which requires pumping larger volumes to achieve a greater simulated rock volume across those wells. Until now, we have mainly executed one or two well pads, focusing on single well or zipper fracs. As we advance, we will shift to full-scale development with four or eight well pads in the Barnett, employing simultaneous fracturing and continuous pumping, leveraging the insights we've gained from our experiences in the Midland Basin core over the years.

That's all very clear. A quick follow-up, if I could. One of your peers had talked last week about international opportunities. I'm curious where do international opportunities sit on your list of strategic priorities?

Yes, Bob, I mean, it's certainly low from a strategic perspective. I would say a company of our size should start to understand what else is out there around the world and really for the main reason of what else around the world could push us out on the global cost curve. We've spent a lot of time studying that. Obviously, there's different dynamics above ground and below ground around the world. What that's taught us is we have a very, very good long-duration inventory in the Permian Basin. And now there's things like the Barnett, surfactants, and all that kind of stuff that we're going to be talking about a lot over the next 3 to 5 years. That just points me back towards staying home. The Permian Basin has been very good to Diamondback, growing our position here. We're basin experts. There may be good rock around the world, but there are a lot of other issues that come with that rock. We've learned a lot about what's out there, but there's not a lot of action that we're focused on today.

You all had a really nice improvement in your leading edge completed feet per day at 4,500. Just maybe some thoughts on what's sort of embedded in the '26 plan and just where you all see that potentially getting to by year-end?

John, thanks for asking. Yes, I mean, the core program still continues to really shine. Kaes put some commentary in his shareholder letter around some of the continued efficiency improvement we're seeing on the drilling side and the completion side. On the completion side, the team has been working on implementing what they call continuous pumping across all of our simul-frac e-fleets. Really, what that means is we just don't shut down between swapping wells in the simul-frac pad. We've been averaging 4,500-ish feet a day on those continuous pumping fleets, but we've seen some results above 5,500 feet per day. We're encouraged by that. We think we still have the opportunity to reduce our cycle times this year. If that comes to reality, we're going to be able to get rid of some frac crews and be able to complete fewer wells in the year to achieve our production targets.

I think one thing I'd add, John, that we're kind of finding out is we're really starting to test different stage length, stage designs, frac designs. Continuous pumping removes the biggest piece of nonproductive time to swapping between your stages. So we're going to test shorter stages. We're able to do that with less cost. All these things are little wins that accrue to our shareholders. You think, hey, continuous pumping, it's one thing to do more lateral feet, but what are all the other tangential benefits that are now starting to show their face, and that's what's exciting there, too.

I guess for my first question, I'll just hit on OpEx. We saw lower OpEx as a partial driver of the EBITDA beat in 4Q, but guidance for 2026 is for a small increase for both LOE and GP&T. I wonder if you could address those. Is that just the water drop-down on LOE and gas transportation contracts on GP&T? Or is there anything else in there?

Yes, that's most of it, Kevin. We sold the EDS system to Deep Blue in the fourth quarter, which contributed to a slight increase in LOE. This year, we are facing a couple of headwinds on LOE; power prices in the basin have increased, and some of our power is now unhedged, leading to higher costs, potentially around $0.10 to $0.20. We are also investing more in workovers, plugging, and abandoning vertical wells to ensure our asset base remains in good condition. These are the primary headwinds. Regarding GPT, most of the changes come from traditional escalators tied to CPI and an increase in the volume of molecules taken in kind, which shifts dollars from realizations to GPT. It really just depends. There will be separate rig lines that we have dedicated to the Barnett. I think it probably makes sense that those rigs just focus on that type of development. But there are areas like Spanish Trail where we have 100% of the minerals and high working interest that we're going to be in the same area as our shallow development. Then there are areas where we don't have it. I think overall, though, we're going to continue to build the position and try to share facilities wherever we can because that's the most efficient form of capital use.

Yes. With the Barnett depth and with some of the mud properties and such that we'll be utilizing to drill those wells, it will probably be a different rig package that we're looking at. Those rigs can certainly drill the Midland Basin core, but we're probably looking at a little bit upgraded rig package for those wells. Ideally, we'll have them all on separate rig lines that we may mix in some of our Midland Basin core with. But if we can get days down on the Barnett drilling, we'll mix in more of our core development and probably have fewer Barnett-directed rigs in particular at the end of the year.

I wonder if I could follow up on the last question about the mix of Barnett versus the base business. It seems obviously an HBP requirement here given the relatively new acreage. And I guess the core of my question is the type curve you've shown for the Barnett is presumably a parent well versus a development type curve for the cube development elsewhere. So how do you expect that development type curve to evolve relative to the base business?

Yes. I mean I think we'll see, Doug. We're spacing these wells pretty wide. We have done a few 2-well pairs, and we'll still see what a full section development looks like. I think in general, the size of the job and the spacing that we're assuming should result in pretty consistent performance. Listen, I'm not going to tell you that every well has been the best well we've ever drilled, but there are a couple in that data set that are probably the highest 6-month cums we've ever had at Diamondback. I think we're putting a bet on ourselves to continue to improve results and get costs down, and that's a good bet.

It's still early, but I’d like to follow up on the inventory question. I understand there's some uncertainty, but I'm curious about your reference to 20 years. Does that relate to a consistent weighted average of well quality, maintaining production mix, or is it more about ensuring free cash flow? What should we take away from that 20-year comment?

I believe that not all inventory is the same. Ideally, if we're performing effectively, we focus on extracting the highest quality resources first. This trend is visible across the industry, where productivity per foot is starting to decline for some companies. Our objective is to sustain the highest productivity per foot for as long as possible. You can observe this in areas like the Upper Spraberry and Wolfcamp D, as well as from five years ago in the Middle Spraberry and Jo Mill, where we have not experienced major declines. In fact, our 2025 results exceeded those of 2024. In a landscape where productivity is generally decreasing, our capability to consistently maintain that productivity over a longer period is advantageous. As we move deeper into our inventory, lower productivity is expected, and I wouldn't mislead you about that. Our teams are constantly exploring ways to cut costs, enhance drilling quality, improve frac jobs, and achieve better performance from regions we previously considered lower-tier. The focus is on prioritizing the best resources and sustaining the free cash flow that is important to you. I believe we can maintain this advantage longer than anyone else.

Kaes, could you provide some insights on your perspective regarding Diamondback's position in the industry moving forward? Historically, your company has strengthened its position through successful mergers and acquisitions. However, it seems that this quarter has seen a shift towards more organic resource expansion. Can you share what you're observing in the industry that is influencing this change from Diamondback's traditional approach?

Yes. I mean, Scott, there's no doubt that there's been a ton of consolidation both in the Permian and elsewhere around the U.S. and it's been top of mind. Your website, the RBC website continues to shrink in terms of the number of tickers. Generally, there have been things that have moved towards basin champions. In the Permian, there are going to be independent basin champions like Diamondback. There are going to be mineral champions like Viper, and there are going to be surface champions like some of the other companies out there. That natural consolidation has led us to say, hey, we have a ton of acreage and a ton of resource. We should probably start to spend some more dollars improving that existing resource. We aren't out of the M&A game. As we said in the letter, the opportunities are fewer and further between. Therefore, we're going to be doing more things like the Barnett and more things like testing surfactants. But don't get it wrong; there's not a deal that happens in the basin without us knowing about it. It’s just that there aren't 10, 20, 30 deals left to do.

My follow-up is on your reserve report. You mentioned there were some revisions to some of the numbers in there. While I know some of it is price-related, you did mention some performance-related revisions. Can you just give us a little bit of context behind that?

Yes. The majority of the reserve revisions, and it's interesting that reserve reports are now becoming something people read again in detail. The majority of our revisions are due to price. The rest of the majority of our revisions are due to PUD downgrades, but it really just means we're bringing in wells that we acquired or PUDs that we acquired and bringing those to the front of the development program. In general, we try to keep a very low PUD balance. The SEC rule is five years of development. We're averaging three years of development in what we put in our PUDs. Right now, from a booking perspective, we're 70% PDP, 30% PUDs. As we do deals like Double Eagle last year or Endeavor the year before, some of our existing PUDs get taken out and new PUDs get put in. But from a performance perspective or PDP performance perspective, there have not been meaningful changes to the reserve report.

I wanted to just revisit the Barnett here quickly. Can you give us a rough sense of the number of wells that you guys are going to be drilling or completing here in 2026? And can you just talk a little bit about what you kind of need to do to hold that position, say, over the next five years? Is there going to be a meaningful step-up in activity in '27, '28?

Yes, Leo. We expect that to ramp up kind of through the end of the year. We expect to allocate some activity to the plan in the back half of the year. So roughly, we're looking at drilling about 30 wells this year, popping probably closer to 10, and then that ramps up significantly in 2027, where on a gross basis, we're probably looking at more like 100 wells for that program.

Got it. Okay. And I guess is that the type of pace that would kind of hold everything together over the next couple of years? Just any color you can provide around lease terms or anything like that on the asset?

Yes. That's a general pace, and we can do it in a capital-efficient manner.

Okay. Appreciate that. And then on continuous pumping, obviously, you talked about that. I think you're kind of increasing the amount of activity moving in that direction. You mentioned potentially being able to drop crews at some point down the road. Do you see that as a potential meaningful capital savings if you can get to the point where you are dropping crews at some point, say, later this year or next year?

I don't believe that it will result in significant cost savings from our service providers. There are extra equipment needs to achieve this. There is a slight reduction in costs for some of the basic rentals as we extend cycle times. The main advantage, as Kaes highlighted, is our ability to optimize completion without incurring extra costs from additional well swaps. The decreased cycle time affects the frequency of water extraction, allowing us to advance wells in the plan. While this may only be a one-time benefit, the reduction in water extraction duration and the time spent on watering out offset pads provides a substantial advantage for the overall annual cycle time.

I would like to ask a question about the terminology you have been using. In your presentation, you refer to the Barnett, but in your shareholder letter, you mention both the Barnett and the Woodford. Could you help me understand how this play has changed over time? If we look back to the late teens when you had the Limelight prospect, it seemed to clearly target the Barnett Mississippian. However, it appears that as you move toward the basin center, you are now targeting both the Woodford and Barnett. It sounds like you might be landing in the Woodford and attempting to frac up into the Barnett. Is that understanding correct? Additionally, could you provide more insight into how this play has evolved for your company?

Yes. I think that's good commentary. The Barnett and Woodford are distinct reservoirs and have their own distinct properties. The initial play, the Limelight play, when you think back to the 2017 time frame, was truly a Barnett play. There's some nuance across the basin with the zone that divides the two reservoirs. The Mississippian Lime sits between them. It changes in thickness pretty materially as you move across the basin sort of north to south. Up at the Limelight position, we had a pretty thick Miss Lime section. So those two reservoirs were separate and distinct. As you move into some of the areas where we've been delineating more recently, the Miss Lime is materially thinner, and we're able to frac through it. Generally, we're targeting the lower Barnett and able to drain the Woodford in some of these areas where you've got that thinner Miss Lime section.

Got it, that's helpful. Kaes, this question might be directed towards you. Referring back to your stoplight metaphor, I appreciate that you clarified your view on the red light scenario, indicating it has lessened somewhat. The unspoken implication of that is that the green light scenario might be closer. Could you provide more details on this? Does it suggest that the green light scenario is nearer than the red light, or is it simply closer than it was previously, although there's still a tendency to slow down? Please elaborate on that metaphor.

Yes, it's a metaphor we can't seem to shake. In general, I think it explains the situation pretty well. I would say that over the last six months, there were times when we were very close to a challenging situation regarding crude prices. Recently, many factors have influenced crude prices. Generally, when I speak with our investors, they are very supportive of our plan to maintain production levels and maximize free cash while waiting for a more favorable scenario. There's been talk of oversupply for some time, yet it hasn't materialized as quickly as expected. As we approach the summer and the driving season, and with the spring trading months for crude, people will start to find reasons to be less pessimistic. I could be mistaken, but overall, we feel more confident about the broader economic situation following some significant shocks to supply and demand last year.

Gentlemen, 2 questions. One, in your D&C or well cost now you're already down in your legacy operations, say, in Midland $550 or so. So where is the biggest opportunity to drive that down further? Is it coming from further improvement in drilling or completion? I mean you're already extremely efficient over there or that is going to allow you that to have better maybe reduce downtime? And so just give us some idea that where should we see from there? That's the first question.

Yes. Good question, Paul. I think on the drilling side, we've really been able to show quarter-over-quarter efficiency gains. I think it's just more getting consistent in those ultrafast wells, right? We talked about in the letter some wells that are sub-6 days, and we're still averaging over 8 days spud to TD. How do we get that average from 8.5, 9 days down to 7 days? That drives meaningful cost savings on the drilling side. On the completion side, we're continuing to go faster, and we talked earlier about continuous pumping and what that means for us. It's also working on the supply chain of the completion side. What can we do around fuel? What can we do around other supporting services to get more efficient and drive some of the debt cost out of that business? We're working on a lot of those things every day. These are not big chunks of dollars, but it's a lot of little things that add up to big chunks of dollars. We're still grinding away on the core business. Like Diamondback has always done, we're not going to let up on that grind, and I'd expect to see more dollars flow out of the core business as we go throughout this year.

Do you think over the next several years, you will be able to more than offset the inflation and drive that $550 number down, say, towards the $500 or $525 in the next few years?

The $550 is a mix of all of our Midland Basin zones. That includes Wolfcamp D and some of the deeper stuff that is in Barnett. Yes, I think certainly some of those deeper zones that are higher cost today, we're going to see some material cost reductions in them as we continue to deploy our best-in-class execution prowess to those zones and learn about them more and put the bid in them better. Yes, I do believe we'll see the $550 come down materially. In the older stuff that we're doing, the Spraberry, shallower Wolfcamp zones, I don't know what inflation will do. It will be largely driven on activity, but our goal every day is to continue to work to execute better, more efficiently, and drive cost out of our supply chain through what we consume. The variable cost, if we can execute better than everybody else, we'll have better variable costs than everybody else. That’s always been our focus and will continue to be our focus going forward.

The second question is a quick one. I understand that the impairment charge primarily relates to noncash prices. You have about 130 million barrels of reserve revisions due to price changes. Considering that $65 WTI last year is not particularly low, I'm a bit surprised to see a reserve write-down along with the impairment charge. Is this related to the legacy Diamondback asset, or does it involve Endeavor or Double Eagle as well?

Yes, Paul. Fair value accounting is what it is. Fortunately, the Endeavor deal was well received, and it was recorded in September 2024 at $80 oil and $4 Henry Hub. I don't think any investor would consider that a bad deal. When something is recorded at $80 and then averages $64 for a year, the market indicates that the accounting rules require a write-down. It's unfortunate. Ultimately, I believe all our investors share our excitement about the Endeavor deal, and the accounting rules will remain as they are.

Well, despite no prepared remarks and starting immediately, you guys all were able to ask 65 minutes worth of questions. We appreciate your interest, and thank you for the time today.