管理層發言
Good day, and thank you for standing by. Welcome to the Diamondback Energy Second Quarter 2026 Earnings Conference Call. Please be advised that today's conference is being recorded. I would now like to hand the call over to your host today, Adam Lawlis, VP of Investor Relations. Adam, please go ahead.
Thank you, Grace. Good morning, and welcome to Diamondback Energy's Second Quarter 2026 Conference Call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback's website. Representing Diamondback today are Kaes Van't Hof, CEO; Danny Wesson, COO; Jere Thompson, CFO; and Al Barkmann, Chief Engineer. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Kaes.
Good morning, everyone, and I hope everybody read our shareholder letter last night. It continues to get good feedback from the investment community. And as we've done over the last couple of years, we're just going to move straight into Q&A. So operator, please open the line up for questions.
分析師問答
Our first question comes from the line of Neal Dingmann with William Blair.
Happy birthday Kaes, from me and the coach. Turning to my first question. I really want to talk about your macro view, specifically, your remarks last night. You seem to indicate your thoughts that worldwide inventory levels will remain low for the foreseeable future. So as such, am I correct in thinking that you all will continue to strategically grow production well into '27, given this low inventory backdrop and positive oil backdrop?
Yes, Neal, I think it's been pretty hard to predict what's going to happen globally over the last couple of months. Certainly, our opinion and the data shows that inventories are draining not only on the oil side, but on the product side. And absent permanent demand destruction, which we're hopeful is not the case, those inventories are going to have to be refilled. We can debate at what price those inventories need to be refilled, but I do think that helps us get some confidence that there's a bid for a longer-term price for oil to refill those inventories and meet global demand. In general, I think that does skew us towards the decision to grow production versus hold production flat. We were the first to respond to the price signals in March to increase our production for the year by 3% or 4% versus the original plan. The team executed on that very, very quickly to where we are today, up somewhere around 4% from where we started the year.
Going into next year, the question is do we hold production flat, which we're kind of doing from these higher elevated levels right now in Q3, or do we grow organically off of this number in a capital-efficient way. Right now, the model spits out some form of low single-digit organic growth while maintaining capital efficiency and running 5 frac crews consistently throughout the year. In today's environment, betting on the need to refill inventories is probably where our head is today. But as you've seen in the past, Diamondback can react quickly to the positive or the negative. In this environment, it's prudent to be able to do that. There's a lot of uncertainty out there, Neal. Our bet is that these global inventories, including SPRs, are going to need to be refilled. That should be a positive for Diamondback shareholders and Diamondback's growth trajectory.
Great points, Kaes. And then just secondly, turning to well productivity, definitely shown on your recent Slide 10. To me, what seems most intriguing there is not only the high productivity you have, but you're doing this by — I'm looking at the left side of the slide also why it sort of seems like maximizing value. You're targeting the most zones, wells per section and, I think, what you all would say are probably the most appropriate completion levels. So I'm just wondering, could you talk about how you're able to target these leading productivity metrics while maximizing value?
Yes. I think Slide 10 is the most important slide in our deck when it comes to the technical aspects of our business and how we're making capital allocation decisions in the field. It's been in there for a couple of quarters now, and we've put in some data on year-to-date performance. Clearly, we're having a good year in 2026 so far. I will borrow a comment from one of our competitors because it's smart: this is a stacked innovation play. We've done a lot of things in terms of well construction, well targeting, stimulation and that's leading to better results. We didn't get here overnight. We started by drilling wells in 30 days; now we're drilling them in 5. Our culture and organization is a continuous improvement culture that has led to these results today. High level, we try to blend the best mix of the most wells per section multiplied by the most production per well. Diamondback operates at the lowest cost per well, and that should generate the most NPV per section or acre in the basin. We're very proud of that, and we have to keep working on continuous improvement in the business. Al, do you want to add anything on what we've changed and done over the last couple of years?
Yes. I think it's really about maximizing the return on every DSU, every well that we put in the DSU, Neal. On well construction, we're using larger tubulars that allow us to flow the wells back more aggressively on the stimulation side, and we've optimized stage architecture and perforating. On the targeting side, the technical teams take a deep dive into how we target every well within the DSU, and I think that's leading to the outperformance you see on the slide.
Yes. It's a lot of little wins. We have to stack up those little wins and keep doing that to maintain our position.
Our next question comes from the line of Neil Mehta with Goldman Sachs.
I guess the first question is just on the gas side. Waha has firmed up a little bit. So just how are you thinking about egress out of the basin recognizing this is probably a problem that will percolate again. But does this create some near-term relief? And then as you think about your gas strategy in general, maybe you can — it's a good opportunity for you to update the market on where you stand around the data center side and the power side of your business.
Anything is relief compared to Q2. We're happy to see these new pipes start to flow, and we've seen some announcements from both Energy Transfer and WhiteWater that the two big pipes are moving forward. That's resulted in Waha being positive for the whole month of July and certainly a nice near-term tailwind for us and our shareholders. At a higher level, we believe in the gas mega theme. It's not core to Diamondback's value proposition, but it can be additive to the amount of oil we produce. In general, that means owning more space to the Gulf Coast. We can debate where that needs to go in the Gulf Coast, but the large demand centers will be along those pipelines for either power projects or data centers, and the rest of the gas that gets to the Gulf Coast is going to cross the dock in the LNG terminals. I'm not smart enough to figure out exactly how much incremental demand the world can handle from an LNG perspective, but we will have enough supply coming out of the U.S. to play a role.
The Permian will be important, and Diamondback can play a big role. Our gas production continues to outperform expectations and I expect that trend to continue over the next 10-plus years. Therefore, we need more contracted space to more markets so we can be in the conversation when LNG offtakers need supply. We're building relationships in that world because the wellhead-to-water gas strategy has to be part of the Diamondback proposition. On top of that, we believe in the power and data center mega theme, and we have a project we've been working on. Jere will give you some color on where we are.
Yes, Neil. Great question. For some background, we and our IPP partner have put together what we view as a unique bridge-to-grid solution on our 30,000-acre Bryant Ranch location to deliver scalable, reliable power near Midland, Texas. We have secured distributed power generation, remediated land and directed access to dedicated natural 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 reciprocating units. Beyond this initial phase of power generation, we are working to secure grid-connected power as soon as 2028 via Batch Zero. We believe we are well positioned within the Batch Zero queue and are awaiting ERCOT's final determination regarding project eligibility for the next interconnection study as soon as their meeting on August 20. We are closely monitoring communication out of Austin and remain confident in a project like ours with low water use and new generation, ultimately meeting Batch Zero standards. We'll give the market a larger update once we sign the definitive documentation with the hyperscaler, but are confident in the direction that this project is going.
Neil, I'll add one thing. I was in a room with a lot of the tech world about 1.5 years ago — a mix of energy and tech. The energy side of the equation got laughed out of the room when we suggested coming to West Texas and building behind the meter. Someone who 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." We offer a lot of opportunity out here. At the end of the day, Diamondback is going to stay in our lane: produce the molecules, provide the surface, provide the water and provide industry know-how. We're not a power company or a data center company, but we can play an important role in this ecosystem that's coming together.
That's a really helpful update, and we'll stay tuned for more. And then Kaes, just maybe give the market an update around how you're thinking about return of capital. I think you adopted a little bit more of a flexible strategy or way of updating the market. How do you approach it in 2Q? How are you thinking about the balance of the year? And talk about that in the context of your largest shareholder, too.
Let me frame the goal. The goal for us is to maximize and capitalize on the option value that is inherent in this business. We live in a very volatile business where things can change overnight. We felt that a formula or any sort of restriction on capital allocation does not allow for the maximization of that option value. Last quarter, as prices rose, we said we were not going to commit to returning a minimum percentage of free cash just because we had to; we removed that minimum commitment. There was a lot of discussion on the call and in the days afterwards with shareholders explaining our case, and they were very supportive. I have not heard a lot about it from long-only shareholders since; they've been supportive. Look at what we've done: we allocated a little to the buyback in Q2 as weakness stepped in at the end of the quarter and a little to the buyback in Q3. Those numbers we're willing to buy back at have gone up, but we also reduced net debt by $1.6 billion.
That translates to $5.60 a share of value that went from the debt side to the equity side because, in my mind, our NAV didn't go down much in Q2; in fact, it went up. It's more about what we've done versus what we're going to do. Investors know we'll lean into the buyback when it presents itself. In 2025, we bought back over 5% of our stock — I wished it was 10%. Now, we're positioning the balance sheet to be in a position where we can lean on it to buy back shares when the cycle turns in this volatile business. It's about making the right capital allocation decision every day. If we can stack up wins on return of capital, that's a long-term win for our shareholders.
Our next question comes from the line of Scott Hanold from RBC Capital Markets.
I was wondering if you could delve into some of the production performance a little bit. You are delivering more oil barrels than guided to, but natural gas is really outperforming. Can you give us a sense of why that is? Are you being conservative with gas expectations? Or is there any kind of zone targeting that's different that would cause that? And where do you see that going moving forward?
Scott, it's Danny. Great question. I think it's multiple things. The biggest driver has been improvement in our ability to market our gas locally. As the G&Ps have matured their systems and built redundancy, and we've worked with our gathering and processing partners to add split connects in strategic areas, we've improved our flaring metrics and increased gas processed and sold. It doesn't feel good to sell at a negative price, but we've gotten a lot better at marketing gas downstream. That's the biggest needle mover. I'll let Al cover any of the technical background on the gas number.
There wasn't much in terms of well selection this quarter associated with the gas production. We brought on a couple of pads in the southern end of the Midland Basin that were a little higher GOR, but that didn't drive the beat on gas. It's really related to what Danny mentioned. 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 gas number creep up a little bit.
And then my follow-up is if you can give some lens into what you're seeing on the oilfield service cost front, any inflation pressures? When you look at this higher production base you're running at, what's a reasonable steady-state maintenance pace exiting this year? What is the quarterly capital run rate you see right now?
Good question. We have seen some inflation mainly tied to consumables. Fuel costs remain present with higher commodity prices. Thankfully, our biggest fuel consumption is on the completion side with the frac fleets, but all our frac fleets are currently electric fleets, which has mitigated some inflation. What we're seeing in the future is casing prices in the back half of the year will come up; that's the big needle mover. We think it's a little over 1% of our total well cost in inflation, so not much, and we think we can offset it with efficiency gains. For '27, it's a little early to talk about specifics, but somewhere around $1 billion to a little over $1 billion a quarter run rate to hold production flat is reasonable with what we see today. If rig counts continue to be added nationally, we anticipate more pressure. As we get closer to '27, we'll talk more about anticipated inflation. For now, that's where we're at, and we'll fight the variable cost side and drive efficiencies to reclaim any inflation on the consumable side.
Our next question comes from the line of Arun Jayaram from JPMorgan.
I was wondering if you could provide an update on what's going on in the field with the Barnett. It looks like you're running three or four rigs targeting that play right now in the basin. I'm interested in your focus on reducing cost, call it from $1,000 a foot to $800, and how you plan to lean into that program in 2027?
Arun, stepping back to earlier this year, we did a big reveal on our Barnett position. Since then, that position has continued to grow and we've continued to block it up so that we can have longer lateral development as we start developing the position aggressively now. Our first four-well pad in Spanish Trail has been drilled and will be completed in the next couple of months. It will be interesting to see full section results end of the year into next year. With the Viper minerals, that's a very high-return project and will give a good idea on the cost side. Since the beginning, we've done a couple of wells here and there; we haven't done a full section with an e-fleet simul-frac crew to get completion costs down. We're seeing wins on the drilling side and I think we're more on our front foot than anybody else in the basin on Barnett exposure and drilling costs. Drilling costs are getting closer to $400 a foot. We have maybe 5% to 10% to go; a couple of wells have been below $400 a foot. We expect to consistently get to around that $400 or less per foot number to make returns competitive with the base plan.
Got it. And then my follow-up, could you give details on how the enhanced oil recovery program is progressing? I know you did a pilot of around 50 wells and are expanding. Maybe give an update on the kind of well productivity improvement you've seen from chemicals and surfactants? Do you plan to evolve that program into new completions?
On the oil side, enhanced recovery and improving recoveries in this basin is a mega theme as well. Given our size and scale and asset base, we need to be on our front foot. As we said in the letter, we need to spend dollars to understand what's happening. That project kicked off last year with our first surfactant program where we learned a lot. Al will update you on what we're seeing today and what we expect in the future. High level, you'll hear a lot about this from large operators over the coming years.
We executed a 12-well project this quarter and are in the process of flowing those wells back now. Initial results are very positive. We're taking the learnings from this batch in terms of rock type and reservoirs where the technology is most suitable, and we'll apply those to the next group of wells in Q3. We're just scratching the surface on the potential for this technology, and the team is really excited going forward.
There are two ways to think about it: it either reduces your base decline or it's a replacement of capital with something higher returning. To date, we've only done remedial work where we go back into existing wellbores to learn about this treatment process, but we are now also incorporating it into new pads where we have a control half of the section and a surfactant half of the section. We're moving with haste and learning quickly.
Our next question comes from the line of John Freeman with Raymond James.
You highlighted a number of impressive operational achievements in the letter. The one that really stood out for me is the first full quarter of continuous pumping over 21 hours of average pumping time per day. What's achievable there? Are we talking about something that in a couple of years gets close to 24 hours a day, or is that unrealistic? I'm trying to understand what's achievable.
John, great question. We're pushing a manufacturing-mode mindset on surface operations for completions. There are 24 hours in a day, and the team won't quit until they can reach a full 24 hours, but there is maintenance associated with equipment on location and every piece of redundancy costs money. There's a balance between adding more equipment for redundancy and how many hours a day you're pumping. The team continues to push efficiency, pumping hours and rate to get more done in a single day. We've seen some pads exceed 5,000-plus feet per day on average, and that's the next target: achieving 5,000 feet per day across all crews every day. I think that's achievable within the next year or so as they apply new surface technology.
One housekeeping item: it looks like there were bolt-on acquisitions during the quarter, net of divestitures, around $385 million. Is there any production associated with those transactions? Anything else we should be aware of?
Very little production. We're continuing the Barnett leasing play with our partners at Double Eagle. Outside of that, the team has been finding $20 million to $100 million deals to net up or extend laterals or block up our position. About one sizable deal a quarter — they add up and tie into our corporate NAV, higher working interest and longer laterals that should result in a higher stock price. We built the Barnett position at a very low cost of entry with cash, and that position is worth multiples of that today, which should accrue directly to shareholders.
Our next question comes from the line of Phillip Jungwirth at BMO.
When you look at the mid-cycle NAV, which you mentioned earlier you feel went up during the quarter, you conservatively use around $65. How much do you think operational improvements and resource expansion initiatives can contribute to a higher NAV plus more volumes or growth? How meaningful are these to intrinsic value and future capital returns?
They 100% contribute. We put our buyback program in place post-COVID in Q3 2021 and said we would buy back shares at a mid-cycle price at a rate of return above our cost of capital. That initial top was $90 a share. Over five years, we've done M&A and expanded the asset base from zones like the Barnett, Jo Mill, Middle Spraberry and Upper Spraberry that weren't big in 2021. Cost structure improvements, longer laterals and execution in the field have driven the top higher — more than doubling since that moment. People ask me what's the future value creation opportunity: look back five years and we doubled the value of the company at the same parameters. We stuck to our assumptions on mid-cycle price and rate of return, and the rest of the business drove improvements. I expect that to continue.
On the shovel-ready power project, where is the most value creation for Diamondback? Is it utilizing surface acreage, the gas supply, partnering on data center cooling, or something else? Any color on the distributed power piece you referenced earlier?
A great question. The biggest driver is having a new in-basin egress solution for natural gas. We're setting aside $200 million to $250 million for this project. Ideally, you get a contract structure akin to Waha plus with a floor, and based on recent quarters, this would provide material uplift. As you said, this could have a material benefit for Deep Blue, of which we own 30%. There are potential land proceeds that could come through as a one-time payment or structured royalty. Those are just a few of the revenue streams we're seeing, but natural gas is the key focus for us.
This is the first step in a long process: planting our flag and proving we can do this and make money for shareholders while partnering across the tech space. It can be repeatable; get one done and you have a blueprint for round two and round three. If you hear tech guys' numbers on power needs, this could be meaningful over time for Diamondback.
Our next question comes from the line of Kevin MacCurdy with Pickering Energy.
On the operations front, can you expand a little on what you saw on productivity and costs on the U-turn wells and how you might be integrating that into your plan moving forward?
We haven't completed the six wells we've drilled thus far on the U-turn pad; we're still developing the pad. On the drilling front, it was certainly a success. There are things we learned and some challenges, but we saw lower per-foot well cost than drilling standalone 7,500 footers. We've completed some U-turn wells we inherited from an acquisition — those were short 5,000-foot U-turns to 10,000-foot total lateral length and execution on those completions went great. This will be our first fully developed Diamondback pad; we haven't gotten it on production yet. The pad we inherited was in line with a regular straight 10,000-foot well in productivity and execution.
Great. As a follow-up, LOE fell below $6 a barrel and partially drove the EBITDA beat this quarter. You talked about some reasons for that. Is there anything structural for that to continue? How are you viewing LOE for the rest of the year?
If you look at the top-line OpEx dollars, they were actually flat quarter-over-quarter. The LOE beat was driven by the production beat. The team has done a remarkable job fighting cost pressures from power and water and doing the little things that save money that add up. I don't think LOE will trend down in the back half of the year; we like circling that $6 range or a little higher. If we continue to see volume outperformance, we could see upside to that number, but inflation on power, water and tubulars will likely flow through some on the top-line LOE number. The team feels confident in that $6 range, but the denominator matters — and the great quarter on productivity helped drive the OpEx beat.
I'd add that the KPIs we track that the team can control on LOE look as good as they've ever looked. We've integrated two large field organizations post-Endeavor and are starting to see benefits like moving to a pump-by-exception company and more automation. AI and automation are driving production-side improvements and lower costs to maintain the production base.
Our next question comes from the line of Doug Leggate with Wolfe.
Kaes, two things. First, on the trade-off between balance sheet and buybacks: you've been vocal about avoiding procyclical buybacks. But with the free cash flow you're generating, you could build cash and materially change your balance sheet. Where are you prepared to take that in terms of building cash as opposed to debt redemptions? Second, on capital efficiency: your latest type curves are significantly above 2025. Would you take capital efficiency and lower spending in '27, or would you take incremental production and keep CapEx flat? Curious on the trade-off between those two.
Both are good questions. On whether to take productivity and reduce CapEx or increase production, today we decided to spend more within our budget and let growth be the output. The debate will continue; some years it's obvious to grow organically and some years, like 2024 and 2025, it made sense to cut CapEx and return more cash. We'll maintain flexibility. On the balance sheet, there are near-term priorities: we want to put enough cash on the balance sheet to address our 2026s that are callable in a couple months and be prepared to address 2027s. That positions us to tackle the maturity tower in 2029 to 2032. I'm not afraid to put cash on the balance sheet; it's prudent because cycles turn. We're not building cash to do big cash deals that blow up the balance sheet. We still want to grow the business and look at opportunities, but our M&A history rarely involves significant cash in deals.
Our next question comes from the line of Geoff Jay with Daniel Energy Partners.
Following up on your comments about AI, predictive maintenance, and remote sensing: how far down the pike are you on that, and what's the timeline for deployment to improve uptime?
I'll let Chad or Danny give the details. We're in the first inning on this — there's so much potential. In five years we'll look back and say we were rookies at all this stuff; it will be a huge help to our production base. Chad?
We're really excited about the progress, but it is incredibly early. We're tackling it first on artificial lift and using AI and automation to help manage optimization day-to-day, which is going very well. The team is also using these tools to manage downtime, and that's been an incredible value add. Still very early, but lots of room to run.
It's a numerator/denominator thing: lower downtime, lower spend, lower decline rate means you don't have to spend as much capital to sustain production. Just a 1% move in decline rate can make a big difference.
Our next question comes from the line of Paul Sankey with Sankey Research.
Can you hear me okay?
Yes, Paul, we got you.
You mentioned the NAV was a bit coy but said it went up during the quarter. Can you talk more about how you think about the NAV now, particularly on upstream performance, and whether the other businesses remain key drivers of buyback attractiveness?
High level, we try to keep price assumptions constant; reducing NAV by changing price isn't the right way to look at it. In Q2 we generated significant free cash flow above our mid-cycle price, which helps NAV. Type curves and well performance improvements and Barnett development have expanded value: Barnett moved from a couple hundred million dollars of value in our NAV to now a couple billion. As we refine our analysis, NAV should continue to go up if we're doing our job. On other businesses, we don't have power value in NAV yet. We do have a good amount of midstream value with our Deep Blue investment. Multiples on the water side have expanded as more attention has been brought to that business in the basin, and we expect to be money ahead on that investment. All of that ties together: reduced share count and lower net debt pops out as a higher per-share value.
Our next question comes from the line of Gabe Daoud with Truist.
Kaes, can you get a little more color on the water side? Given some of the changes the RRC has made to injection, are you seeing any constraints now or concerned about constraints moving forward?
We haven't seen constraints on our system. You need significant capacity and a large interconnected system; the days of one or two SWDs hooked up to the system make no sense. We have a valuable partnership with Deep Blue, where they are investing capital to loop lines, connect areas and add SWD capacity to prevent issues. Water is getting more attention in the basin. The Delaware Basin, given the amount of water produced there, is working to solve these problems sooner than the Midland Basin, but there are learnings we can translate. Deep Blue used the asset base we gave them with Diamondback as the anchor customer and has done a great job adding third-party business and connecting and improving the system.
Helpful. A follow-up: you had non-D&C spend of $600 million across some science and midstream. How does that change into '27? Does Barnett require incremental midstream or facility spend we might not be thinking of?
Generally, that number will go up slightly next year and the mix will move. As we get to large-scale Barnett development in areas without existing infrastructure, we'll have to build new batteries, and we're designing those to be tailored to Barnett wells versus Wolfberry wells. Infrastructure capital is higher at the beginning and then reduces. So that number is close with a little upside next year.
Our next question comes from the line of Derrick Whitfield with Texas Capital.
Congrats on a solid update this quarter. On the operational front, can you speak to some of the design changes you incorporated this quarter to drive lower equipment cost per well?
High level, combining best practices from Endeavor and Diamondback and finding the best of both on equipment scope has helped. Dan or Al can share details.
A lot of it is driven by extending lateral lengths. That's the biggest lever. We are starting to lean into U-turn development because the efficient frontier for lateral lengths continues to increase. If our average lateral length creeps beyond 12,000 feet, that drives much more efficiency. That's what you're seeing: longer laterals mean the same flow line and tubing for more footage, driving down per-foot cost.
Some things have come out of scope as well. The equipment and infrastructure piece is nonproductive capital, and we want to minimize non-oil-producing capital in our CapEx budget.
As a follow-up on EOR, could you speak to lessons learned so far and how you're thinking about broadening the program beyond the first 50 wells?
We're figuring out which rock types and lithologies the specific surfactant technologies work best in. We're mapping our portfolio of thousands of wells to those rock types and thinking about chemical composition and which surfactants work best in each. That's an ongoing process. Initial results from the 12-well package are promising. We're early innings, learning a lot, and will apply those learnings to future groups of wells. Over time, this could lead to shallowing of the decline rate and decisions about taking capital out or leaning in.
Our next question comes from the line of Charles Meade with Johnson Rice.
I wanted to go back to your shareholder letter and your theme of volatility and get your view on the macro. We've been living with a lot of volatility. Do you think stopping specific geopolitical conflicts or opening a key maritime route is what's going to end volatility, or are there structural changes in the oil market so that even if those issues are resolved, we'll live with more volatility going forward?
It's probably not our place to opine on geopolitical events and instead focus on global inventories. The relationship between inventories and price has broken down a bit over the last couple of months because there's noise in the system. Someone smarter than me described the market as basically a sine wave because of everything disruptive. There will be periods of heightened upside and downside volatility; a steady state is far from likely today. Chasing headlines over the last three months has been exhausting. We've decided to put our head down and believe that crude oil removed from inventories must be replaced over time. Over a multiyear period, that should result in a bid for oil for a longer period.
Second question on the Wolfcamp D: you wrote about driving down costs there. Slide 11 shows Wolfcamp D as the biggest rate of change from 2025 to 2026 in lateral footage. Which direction does causality work? Are you getting cost down because you're drilling more and learning, or drilling more because you've gotten cost down? Also, what are you seeing in productivity trends in the Wolfcamp D?
From a cost perspective, the team had a budget around $350 to $360 a foot and a stretch goal of $300 a foot, and they're hitting that stretch goal. That improves Wolfcamp D returns. More Wolfcamp D came into our program because when we merged with Endeavor they had acreage in the sweet spot of Wolfcamp D in eastern Midland County compared to our prior base. When companies add secondary zones, productivity per foot can take a hit, but our productivity per foot has been consistent and is up this year even while adding these zones. Credit to the team and it's also a combination of a larger asset base with more places to allocate capital post-Endeavor.
Our next question comes from the line of Leo Mariani with ROTH.
There hasn't been much Delaware Basin activity over recent quarters. Can you give an update on that asset? Is it going to sit and slowly decline over time, or might you look to get back to it later?
No capital is allocated to the Delaware this year, but interesting things are happening there. We've done some farm-outs in the second Bone Spring in our ReWard position that produced good results and unlocked inventory that wasn't as competitive a couple of years ago. Through our Viper lens, leasing in the Delaware for Viper has been significant year-to-date. There's a Delaware Woodford trend getting attention: big wells that are expensive but large, and leasing activity. So there's stuff happening below the surface, but no major capital allocated this year or likely next.
On EOR, I know it's early, but at this point do you think you've had clear economic benefit on some wells? Are you convinced there's economic benefit in incremental capital on some of these existing wells?
Yes, 100%. We need to learn where it works best. Some wells saw zero uplift; some wells saw production triple or quadruple versus pre-treatment. The average was in the range of a 150 to 200-barrel-a-day well going up by 100 to 150 barrels a day, but dispersion is wide. I liken it to a Wolfcamp B frac in 2014 versus one today — we need to figure out what's happening beneath the surface. With the quality of data and our processing ability today, we can iterate quickly for continuous improvement.
This concludes the question-and-answer session. I would now like to turn the call back over to Kaes Van't Hof, CEO, for closing remarks.
Thanks, everyone, for the time and the questions. We again used up a full hour. I continue to be impressed with the analyst community. So thank you for the time.
Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.