FANG

A month has gone by since the last earnings report for Diamondback Energy (FANG). Shares have added about 5.9% in that time frame, outperforming the S&P 500. Will the recent positive trend continue leading up to its next earnings release, or is Diamondback due for a pullback? Well, first let's take a quick look at the latest earnings report in order to get a better handle on the recent drivers for Diamondback Energy, Inc. before we dive into how investors and analysts have reacted as of late. Diamondback Energy reported second-quarter 2026 adjusted earnings per share (EPS) of $6.48, which beat the Zacks Consensus Estimate of $5.96 and more than doubled from the year-ago adjusted profit of $2.67. The outperformance was driven by production growth and a 53.1% improvement in the year-over-year realized oil prices. This Midland, TX-based oil and gas exploration and production company’s revenues of $5.6 billion increased more than 51% from the year-ago quarter and topped the Zacks Consensus Estimate by about 17%, fueled primarily by higher sales of oil, natural gas and natural gas liquids, increased sales of purchased oil and higher revenues from other operating income. In the second quarter of 2026, Diamondback Energy generated free cash flow and adjusted free cash flow of $2.3 billion. Over the same period, it bought back nearly 756,385 common shares for roughly $141 million at an average price of $186.63 per share, excluding excise taxes. In July, the board of directors increased the company's share repurchase authorization from $8 billion to $16 billion, effectively doubling the program's capacity. Following this increase, approximately $9.9 billion remains available for future share repurchases under the authorization. FANG’s board of directors approved a base quarterly dividend of $1.10 per common share for the second quarter of 2026, payable on Aug. 20 to its stockholders of record on Aug. 13. FANG’s production of oil and natural gas averaged 1,017,659 barrels of oil equivalent per day (BOE/d), comprising 51.6% oil. The figure was up 10.6% from the year-ago quarter and beat our model estimate of 969,519.9 BOE/d. While crude and natural gas output increased 5.9% and 16.5% year over year, respectively, natural gas liquids volumes climbed 15.7%. The average realized oil price during the quarter was $96.82 per barrel, 53.1% higher than the year-ago realization of $63.23. The figure also beat our estimate of $66.12 per barrel. Meanwhile, the average realized natural gas price decreased to a negative $2.15 per thousand cubic feet from 88 cents in the prior year. The figure was also below our model estimate of 60 cents. Overall, the upstream oil and gas company fetched $51.68 per barrel compared with $39.61 a year ago. Diamondback Energy’s second-quarter cash operating cost was $10.96 per BOE compared with $10.10 in the prior-year quarter and our estimate of $12.56. The increase in costs compared with the year-ago period reflected a rise in lease operating expenses to $5.96 per BOE from $5.26 in the second quarter of 2025 and an increase in Production and ad valorem taxes to $3.26 per BOE from $2.56 in the prior-year quarter. However, FANG’s gathering, processing and transportation expenses decreased 29.5% year over year to $1.22 per BOE. Cash G&A expenses also fell in the second quarter of 2026 to 52 cents per BOE from 55 cents in the corresponding period of 2025. Diamondback Energy logged $996 million in capital expenditure — spending $842 million on operated drilling and completion additions to oil and natural gas properties, and $154 million on non-operated additions. The company booked $2.3 billion in adjusted free cash flow in the second quarter. As of June 30, the Permian-focused operator had approximately $462 million in cash and cash equivalents and $11.1 billion in long-term debt, representing a debt-to-capitalization of 20.1%. Diamondback Energy updated its 2026 guidance by raising its full-year oil production outlook to more than 522 MBO/d, up from the previous guidance of more than 520 MBO/d, and increasing its total production forecast to over 1,000 MBOE/d from more than 972 MBOE/d. The company maintained its full-year cash capital expenditure guidance at approximately $3.9 billion. For the third quarter of 2026, the company expects oil production to range between 517 MBO/d and 527 MBO/d, with total combined production projected at 995-1,015 MBOE/d. Third-quarter cash capital expenditures are expected to be between $950 million and $1.05 billion. Since the earnings release, investors have witnessed a upward trend in fresh estimates. The consensus estimate has shifted 11.98% due to these changes. At this time, Diamondback has a great Growth Score of A, a grade with the same score on the momentum front. Charting a somewhat similar path, the stock was allocated a score of B on the value side, putting it in the top 40% for value investors. Overall, the stock has an aggregate VGM Score of A. If you aren't focused on one strategy, this score is the one you should be interested in. Estimates have been broadly trending upward for the stock, and the magnitude of these revisions looks promising. Interestingly, Diamondback has a Zacks Rank #3 (Hold). We expect an in-line return from the stock in the next few months. Diamondback is part of the Zacks Oil and Gas - Exploration and Production - United States industry. Over the past month, Comstock Resources (CRK), a stock from the same industry, has gained 20.5%. The company reported its results for the quarter ended June 2026 more than a month ago. Comstock reported revenues of $353.28 million in the last reported quarter, representing a year-over-year change of -24.9%. EPS of $0.03 for the same period compares with $0.13 a year ago. For the current quarter, Comstock is expected to post earnings of $0.06 per share, indicating a change of -33.3% from the year-ago quarter. The Zacks Consensus Estimate has changed -36.8% over the last 30 days. Comstock has a Zacks Rank #4 (Sell) based on the overall direction and magnitude of estimate revisions. Additionally, the stock has a VGM Score of D. Want the latest recommendations from Zacks Investment Research? Today, you can download 7 Best Stocks for the Next 30 Days. Click to get this free report Diamondback Energy, Inc. (FANG) : Free Stock Analysis Report Comstock Resources, Inc. (CRK) : Free Stock Analysis Report This article originally published on Zacks Investment Research (zacks.com). Zacks Investment Research

Diamondback Energy, Inc. FANG raised its 2026 production outlook after a second quarter that topped earnings expectations, while leaving its full-year capital budget unchanged. That combination puts capital efficiency at the center of the investment case. Higher volumes could extend earnings momentum if operating gains keep costs contained. The test is whether Diamondback can sustain the larger production base without requiring a proportional increase in spending. Diamondback increased 2026 oil production guidance to 522+ thousand barrels per day from 520+ thousand barrels per day. Total production guidance rose to 1,000+ thousand barrels of oil equivalent per day from 972+ thousand barrels of oil equivalent per day. Full-year cash capital expenditures remain about $3.9 billion. For the third quarter, FANG expects oil production of 517-527 thousand barrels per day, total production of 995-1,015 thousand barrels of oil equivalent per day and capital spending of $950 million to $1.05 billion. Image Source: Diamondback Energy Second-quarter production reached 1.018 million barrels of oil equivalent per day, including 525 thousand barrels of oil per day. Adjusted earnings were $6.48 per share, topping the Zacks Consensus Estimate of $5.96. Revenues of $5.6 billion increased more than 51% year over year and beat the consensus mark by about 17%. The earnings outperformance reflected production growth and a 53.1% year-over-year improvement in realized oil prices. Image Source: Diamondback Energy Diamondback has improved well construction, targeting, stimulation and completion techniques. Management noted that wells that once took about 30 days to drill can now be drilled in roughly five days, while longer laterals and lower costs per foot are supporting well economics. The focus is on combining more wells per section with higher production per well at a low cost per well. ConocoPhillips COP also continues to emphasize capital discipline, reaffirming its full-year 2026 guidance after the second quarter. Occidental Petroleum Corporation OXY reported second-quarter production above the high end of guidance while spending $1.6 billion on capital expenditures. Commodity sensitivity remains the biggest constraint. A sustained crude-price decline could pressure cash flow, drilling economics and the economics of carrying a higher production base. Service-cost inflation is another concern, particularly for casing, fuel and other consumables. Management estimates that maintaining the higher production base could require roughly $1 billion or slightly more of quarterly capital spending. Rising gas production adds another risk because Permian natural gas pricing can weaken when takeaway capacity is tight, limiting the benefit of stronger volumes. The higher guidance supports the case that Diamondback can preserve operating momentum without lifting its full-year capital budget. Still, the payoff depends on execution, commodity prices and the company’s ability to keep efficiency gains ahead of cost inflation. FANG currently carries a Zacks Rank #3 (Hold). It has a Growth Score of A, Momentum Score of A, Value Score of B and VGM Score of A. Those favorable Style Scores reflect attractive growth and momentum characteristics, while the Hold rank keeps the near-term view balanced as investors weigh commodity exposure, costs and execution risk. You can see the complete list of today’s Zacks #1 Rank (Strong Buy) stocks here. Want the latest recommendations from Zacks Investment Research? Today, you can download 7 Best Stocks for the Next 30 Days. Click to get this free report Diamondback Energy, Inc. (FANG) : Free Stock Analysis Report ConocoPhillips (COP) : Free Stock Analysis Report Occidental Petroleum Corporation (OXY) : Free Stock Analysis Report This article originally published on Zacks Investment Research (zacks.com). Zacks Investment Research

Image source: The Motley Fool. Monday, Aug. 3, 2026 at 8:00 a.m. ET Chief Executive Officer - Kaes Van't Hof Chief Operating Officer - Danny Wesson Chief Financial Officer - Jere Thompson Chief Engineer - Al Barkmann Vice President of Investor Relations - Adam Lawlis Operator: Good day, and thank you for standing by. Welcome to the Diamondback Energy Second Quarter 2026 Earnings Conference Call. [Operator Instructions] 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. Adam Lawlis: 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. Kaes Van't Hof: 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. Operator: [Operator Instructions] Our first question comes from the line of Neal Dingmann with William Blair. Neal Dingmann: 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? Kaes Van't Hof: Yes, Neal, I think it's been pretty hard to predict what's going to happen globally with -- 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. And 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 bid for oil to refill those inventories and meet global demand. So 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 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. And I think the goalposts are for us going into next year, 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. And 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. So I think in today's environment, betting on the need to refill inventories, that's probably where our head is today. But 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, Neal. I think our bet is that 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. Neal Dingmann: 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 probably the most appropriate completion levels. So I'm just wondering, could you talk about how you're able to sort of target these, the leading productivity, while maximizing value. Kaes Van't Hof: Yes. I mean, 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. So it's been in there for a couple of quarters now, and we've put in some data on year-to-date performance. And clearly, we're having a good year in 2026 so far. And I kind of kind of steal a comment from one of our competitors because I think his comment is smart in that this is kind of a stacked innovation 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 5. But our culture and our organization is a continuous improvement culture that has led to these results today. So high level, we try to blend the best mix of most wells per section, right on the bottom left of that slide, multiplied by the most production per well. And clearly, Diamondback operates at the lowest cost per well, and that should generate or does generate the most NPV per section or acre or asset in the basin. And we're very proud of that, and we 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? Albert Barkmann: Yes. I mean, like you said, I think it's really about maximizing the return on every DSU, every well that we put in the DSU, Neal. I mean the specifics when you think about well construction, doing larger tubulars that allows us to flow the wells back more aggressively on the stimulation side, stage architecture and perforating. And then on the targeting side, 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. Kaes Van't Hof: Yes. So it's a lot of little wins, Neal. We got to stack up those little wins and keep doing that to maintain our position. Operator: Our next question comes from the line of Neil Mehta with Goldman Sachs. Neil Mehta: 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. Kaes Van't Hof: Yes, Neil, anything is relief compared to Q2. So 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 2 big pipes are moving forward. 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 I'll take it a little higher level because I think 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. And in general, I think that means 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 power projects or data centers. And then the rest of the gas that gets to the Gulf Coast is going to cross the dock in the LNG terminals. And I think I'm not smart enough to figure this out today, but the question is going to be how much demand can the world 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, I think the Permian is going to play a big role. And I think Diamondback is going to play a big role. So our gas production continues to outperform expectations. I think that will continue over the next 10-plus years. And therefore, we need to have more contracted space to more markets to be in the conversation when the LNG offtakers need supply. So 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 Jere is going to give you some color on where we are. Jere Thompson: Yes, Neil. Great question. For some background, we and our IPP partner have 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 nat 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 recip 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. Kaes Van't Hof: Neil, I'll add one thing. I was in a room with a lot of the tech world about 1.5 years ago. It's kind of a mix of energy and tech. And the energy side of the equation kind of got laughed out of the room when we suggested to come to West Texas and build behind the meter. And someone who was in that meeting called me last week and was -- 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 is going to stay in our lane, which is produce the molecules, deal with the -- produce -- 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. Neil Mehta: Yes. 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. Kaes Van't Hof: Yes. 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 we felt that a formula or any sort of restriction on capital allocation does not allow for the maximization of that option value. So that's why we -- last quarter, as prices rose, we said, listen, 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 there's a lot of discussion on the call about it. There was a lot of discussion in the couple of days afterwards with shareholders, explaining our case, and they were very supportive. And -- 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've 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 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 wasn't -- 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. If 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. Operator: Our next question comes from the line of Scott Hanold from RBC Capital Markets. Scott Hanold: I was wondering if you could delve into some of the production performance a little bit. You all are delivering more than -- oil barrels than I guess guided to, but nat gas is really outperforming. And can you just give us a sense of why you think that is? Are you just being conservative with gas expectation? Or is there any kind of zone targeting that's different that would cause that? And where do you see that going moving forward? Daniel Wesson: Scott, it's Danny. Great question. I think it's multiple different things. I'll let Al talk on the technicals. But I think just the biggest driver has been really an improvement in our ability to market our gas locally. As the G&Ps 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 flaring metrics and thus, we've improved in our gas processing and selling gas. It doesn't feel good to sell it at a negative price, but 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 I'll let Al cover any other of the technical background on the gas number. Albert Barkmann: Yes, not really much in terms of well selection in 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 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. Scott Hanold: And then my follow-up is, if you can give us some -- a lens into what you're all seeing on the oilfield service cost front, any kind of inflation pressures? And when you look at this higher production base you're running at, when you think about like -- I don't know if it's good to think about like just kind of a steady-state maintenance pace exiting this year? Like what is the quarterly capital run rate you all see right now? Daniel Wesson: Yes, another good question. I think we have optics into some inflation mainly tied to some of our consumables. Obviously, we talked about fuel costs in the past with the rise in commodity prices, and that's still here. Thankfully, we -- our biggest fuel consumption would be on the completion side with the frac fleets, but all of our frac fleets are currently electric fleets. So we've kind of mitigated that inflation hurdle through utilizing the electric fleets. What we've seen -- what we're seeing in the future, casing prices in the back half of the year are going to come up. And that's really the big needle mover. We think it's about 1% -- a little over 1% of our total well cost and inflation. So not much, and we think we can offset it with efficiency gains. It's a little early to talk about '27, but I think 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. But if we continue to add rigs in the U.S., and 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, we anticipate we're going to see some more pressure. But time will tell and what happens in the gas basins, along with what happens in the oil basins, what activity does. And 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 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. Operator: Our next question comes from the line of Arun Jayaram from JPMorgan. Arun Jayaram: 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 3 or 4 rigs targeting that play right now in the basin. But I was just kind of interested on 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? Kaes Van't Hof: Yes, Arun. I mean stepping back to earlier this year, we did a big reveal on our Barnett position. Since then, that position has continued to grow, continue to block it up as well so that we can have longer lateral development as we start developing the position aggressively, basically now. Our first 4-well pad in Spanish Trail has been drilled and will be completed in the next couple of months. So it will be interesting to see full section results kind of end of the year into 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 of wells here, a couple of wells there. We haven't done a full section with an e-fleet simul-frac crew getting the cost down on the completion side. I will say, we're seeing wins on the drilling side. I think we're more on our front foot than anybody else in the basin on Barnett exposure and drilling costs. And they're getting closer to $400 a foot. I think we have 5% or 10% to go. There have been a couple of wells below $400 a foot, but I think we expect to consistently get to around that $400 or less per foot number to make returns competitive with the base plan. Arun Jayaram: Got it. Got it. Okay. And then my follow-up, I was wondering if you could give us some details on how the enhanced oil recovery program. I know you did a pilot of 50 wells, and I think you're expanding that pilot to another batch of wells. Maybe just give a little bit of an update on what kind of well productivity improvement you've seen from chemicals and surfactants? And do you plan to evolve that program into new completions? Kaes Van't Hof: Yes. So I mean, just like we think the gas, power, AI theme is a mega theme, I think on the oil side, enhanced recovery or improving recoveries out of this basin is going to be a mega theme as well on the oil front. I think generally, given our size and scale and asset base, we certainly need to be -- as we said in the letter, we need to be on 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 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're going to hear a lot about all this kind of stuff from large operators over the coming years. Albert Barkmann: Yes, Arun, we -- 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 I think we're going to take the learnings from this batch of wells 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 I think we're just scratching the surface on the potential for this technology, and we're really excited about it going forward. Kaes Van't Hof: Yes. I think there's 2 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 wellbores 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 moving with haste and learning a lot pretty quickly here. Operator: Our next question comes from the line of John Freeman with Raymond James. John Freeman: You highlighted a number of impressive operational achievements in the letter. And the one that really stood out for me is just that first full quarter of continuous pumping over 21 hours of average pumping time per day, which is kind of hard for me to even wrap my head around. But just sort of what's like achievable there? I mean like is it like in a couple of years? Or are we going to be talking about something that's boring on close to like 24 hours or something? Just trying to understand what's even -- what's achievable there. Daniel Wesson: John, yes, thanks. Great question. We continue to try and push the manufacturing mode kind of mindset with regards to the surface operations on the completion. And I think there's 24 hours in a day. So I don't think the team is 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 every piece of redundancy costs money. So there's a balance between adding more equipment out there to get redundancy and how many hours in a day you're pumping. And that's been the fight with the team on doing trimul-frac work versus simul-frac work and those things. But they continue to look at how do they push efficiency, push pumping hours and push rate to get more done in a single day. I think we've seen some pads that 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 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 they're working on it. They're applying new technology at the surface and it continues to get better. John Freeman: And then just one housekeeping item. It looks like there was some bolt-on sort of acquisitions during the quarter. It looks like kind of net of divestitures like $385 million. Is there any production that was associated with those transactions? Just anything else we should be aware of? Kaes Van't Hof: Yes. Very little, John. I mean, we're continuing this -- the Barnett leasing play with our partners at Double Eagle. So that's continuing onward. And I'd say outside of that, I've actually been very pleased that the team has been finding, call it, $20 million to $100 million deals to either net up or extend laterals or block up our position. And they've been finding them pretty consistently. I mean, about kind of one sizable deal a quarter. And I think looking into Q3, we got another couple of small ones. So those don't get headlines, but they add up, right? All of this ties into our corporate NAV, higher working interest, longer laterals should result in a higher stock price. I think we're done with cash, right? Done with cash, which is important, John. And the thing I'll say about the Barnett position we built, we built that at a very low cost of entry with cash. And that position is worth multiples of that today, and that should just accrue directly to shareholders. Operator: Our next question comes from the line of Phillip Jungwirth at BMO. Phillip Jungwirth: 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 conservatively use 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 in the business can contribute to the thought process around intrinsic value and future capital returns. Kaes Van't Hof: Yes, it's a great question. They 100% do, and I'll take you down a little bit down memory lane here. We put our buyback program in place post-COVID at, 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 here we are 5 years later, we've obviously done a lot in terms of M&A. The asset base has expanded from a zone perspective, things like the Barnett, things like Jo Mill, Middle Spraberry weren't big things in 2021, Upper Spraberry. 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, more than doubling since that moment. So people ask me what's the future value creation opportunities for Diamondback. And you look back 5 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. Phillip Jungwirth: That's great. And then on the shovel-ready power project, where is the most value creation for Diamondback on a project like this? Is it more utilizing the surface acreage, the gas supply deal or partnering on the data center cooling, which I assume would be deep blue, but let me know if you're thinking of it otherwise. And any color you could provide around the distributed power piece that you referenced earlier? Jere Thompson: Yes, Phillip, it's Jere. A great question. I think the biggest driver for us is just having a new in-basin egress solution for nat gas. 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 Waha plus with a floor. And for us, 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%. There's some land proceeds that likely could come through the door, either as a onetime payment or structured as a royalty. And these are just kind of scratching the surface of what we're seeing. So really excited about it. But I think nat gas is the one that we're focused on. Kaes Van't Hof: Yes. I think the one thing I'd say is we -- this is the first step in what I think will be a long process, right? This is us planting our flag, proving we can do this. We can make 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 2, round 3. 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. Operator: Our next question comes from the line of Kevin MacCurdy with Pickering Energy. Kevin MacCurdy: I guess for the first question, I'll stick on the operation front. Maybe you can expand a little bit on what you saw on productivity and costs on the U-turn wells and how you might be integrating that into your plan heading forward? Kaes Van't Hof: Yes. So great question. We haven't completed the 6 wells that we've drilled thus far. We're still in the middle of developing that pad. I think on the drilling front, it was certainly a success for us. There are some things that we learned and some challenges we saw, but we still saw lower per foot well cost than drilling stand-alone 7,500 footers. 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 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, it was in line with what we would see from a regular straight 10,000-foot well. Kevin MacCurdy: Great. And as a follow-up, maybe I'll hit on LOE. It looked like it fell below $6 a barrel and partially drove the EBITDA beat this quarter. You kind of talked about some of the reasons for that. Is there anything structural in there for that to continue? Or how are you viewing LOE for the rest of the year? Kaes Van't Hof: I think if you look at the top line OpEx number, the dollars were actually flat quarter-over-quarter. So the LOE beat was driven by the production beat. I think 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 -- they do the little things they do to save $1 here and there that adds up. And I think we're still going to see -- 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 I think if we continue to see volume outperformance, we could see some upside to that number. But I do believe that some of this inflation stuff we have on power and water and tubulars will flow through on the top line LOE number as well. So the team feels pretty confident in that $6 range. But again, that denominator is a pretty big number. So it was just a great quarter on the productivity front and helped drive the beat on OpEx. Jere Thompson: Yes. But I'd also say that 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, integrating 2 large field organizations takes a little longer than the office, but we're starting to see the benefits of that in terms of moving to a pump by exception company, a lot more automation. I think that AI is helping Diamondback in the office today, but I think AI is going to be an -- and automation are going to be very big drivers of the production base either shallowing or costing less to maintain. Operator: Our next question comes from the line of Doug Leggate with Wolfe. Douglas George Blyth Leggate: Kaes, I've got a couple of things. The first one, I want to take you back to your first comment about the trade-off between the balance sheet and your buybacks. I think you've been more vocal than most about avoiding procyclical share buybacks. But you could make -- you could do some serious damage to your balance sheet with the kind of free cash flow you're generating. So my question is, where are you prepared to take that to in terms of building cash on the balance sheet as opposed to going after debt redemptions, but actually just sitting cash to reduce net debt? That's my first question. And my follow-up very quickly is the capital efficiency is extraordinary. Your latest type curves are significantly above 2025. You've run through a number of reasons why that's happening. My question is, would you take the capital efficiency and lower your spending in '27? Or would you take the incremental production and keep the CapEx flat? And I know you talked a little bit about growth, but just curious on the trade-off between those 2 things as well. Kaes Van't Hof: Yes, 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 as the output. I think there's going to be a debate throughout the year. Some years, it's going to be obvious to grow organically and some years 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 I think that also then ties to your other question, which is where are we prepared to take the balance sheet. And 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 of months and also take out our -- 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 time frame. So 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 cycles turn. And the one thing I will say to give investors comfort is we're not building cash here to do big cash deals and blow up the balance sheet doing deals. That's not what we're here for. We're here to grow -- we 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. Operator: Our next question comes from the line of Geoff Jay with Daniel Energy Partners. Geoff Jay: Just wanted to follow up on what you said earlier, Kaes, about the deployment of AI and like predictive maintenance and remote sensing, et cetera. How far down the pike are you on that? And I guess, what's the time line look like to you kind of for the deployment of those technologies out there to try to even improve your uptime? Kaes Van't Hof: Yes. 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 we can spit ball and debate internally what could happen. I mean I think in 5 years, we're going to look back and say, 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? Chad McAllaster: Yes. We're really 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 is 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. Kaes Van't Hof: Yes, 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. Operator: Our next question comes from the line of Paul Sankey with Sankey Research. Paul Sankey: Can you hear me okay? Kaes Van't Hof: Yes, Paul, we got you. Paul Sankey: Kaes, you mentioned the NAV. You were kind of coy about it, but you said that the NAV went up more or less during the quarter. Can you just talk a little bit more about how you think about the NAV now, particularly, first of all, obviously, on the upstream performance side. I don't know if you want to throw the oil price in there, but also the other businesses and whether or not it's still a key driver of buyback attractiveness? Kaes Van't Hof: Yes. I mean, high level, we try to keep price constant, right? Reducing your NAV by changing price, I don't think is the right way to look at it. So I think generally, Q2, we obviously generated a significant amount of free cash flow above that mid-cycle price. So that helps NAV. But I also think as we're looking at type curves and well performance and the Barnett development, the Barnett moved from something that had like a couple of hundred million dollars of value in our NAV to now a couple of billion. And so I think as those things continue to develop and we refine our analysis, the NAV should continue to go up if we're doing our job. I think on the other businesses, I don't -- certainly don't have any power value in our NAV. We do have a good amount of midstream value with our Deep Blue investment. It's been interesting to watch multiples expand on the water side of the equation as I think more attention gets brought to that business line in this basin. So 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 net debt value pops out of a higher per share value. Operator: Our next question comes from the line of Gabe Daoud with Truist. Gabe Daoud: Kaes, I was hoping maybe you could get a little more color on just the last point that you hit on, on the water side. Is there anything that you're seeing just given some of the changes the RRC has made to injection. Are you seeing any constraints at this point or maybe concerned about constraints moving forward? Kaes Van't Hof: 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 have to have significant capacity. You have to have a large interconnected system. The days of 1 or 2 SWDs being hooked up to the system makes no sense. And 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. The water discussion is certainly getting a lot more attention in this basin. I think the Delaware Basin, obviously, given the amount of water produced there is 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. Gabe Daoud: That's helpful. And then just a follow-up. I think this year, you had non-D&C spend of $600 million across some science and midstream. Just curious how does that change into '27? Does the Barnett require any incremental midstream or facility spend that maybe we're not thinking of? Or is the answer there, no? Kaes Van't Hof: I think generally, the number will go up slightly. But within that number, the mix will move. As we get to large-scale Barnett 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 Barnett well looks like versus what Wolfberry wells look like. So 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. Operator: Our next question comes from the line of Derrick Whitfield with Texas Capital. Derrick Whitfield: Congrats on a solid update this quarter. I wanted to start on the operational front. Can you speak to some of the design changes you incorporated this quarter to drive lower equipment cost per well? Kaes Van't Hof: Yes. I mean, I think generally, 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, Dan or Al, you have any details. Daniel Wesson: I mean, a lot of it is driven by just extending lateral lengths, right? I mean, that's the biggest lever we have to pull. And it's one of the reasons why we're starting to lean into some of the U-turn development because we talk about a lot, like what is the efficient frontier for lateral lengths and can we get to a point where our average lateral length continues to creep up beyond 12,000 feet and it just drives so much more efficiency. And so that's really what you're seeing. The biggest change is just a little longer laterals, and you need the same flow line and same tubing and all that for that well, it just drives down your per foot cost. Kaes Van't Hof: And I think some things have come out of the scope as well. So we're always looking at each little line item. But Danny's point is 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. Derrick Whitfield: Great. Makes sense. And as my follow-up, maybe I wanted to touch back on the EOR question from earlier. Could you speak to the lessons you guys have learned so far and how you're thinking about broadening this program as you look out beyond the first 50 wells? Albert Barkmann: Yes, Derrick. Great question. Really, it's figuring out which rock types and lithologies, the technology, the specific surfactant technology, we're applying where it 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 in 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 is learning a lot and the initial results that we're seeing from this 12-well 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 I think this is something that like Kaes talked about earlier, where we could see some shallowing of the decline rate and then the decision on do we take capital out of the system or do we lean in. But yes, overall, that's sort of the details of where we are today. Operator: Our next question comes from the line of Charles Meade with Johnson Rice. Charles Meade: I wanted to go back to your shareholder letter and your theme of volatility and see if you maybe share your view on the macro. We've been living in the world with a lot of volatility. But I'm curious -- we see some this morning, but I'm curious, do you think that stopping the bombing and opening the Strait of Hormuz is what's going to kind of end the volatility? Or do you -- are you anticipating that there's been some structural changes in the oil market that even if we do get these agreements that we're going to be living with more volatility going forward? Kaes Van't Hof: Yes. I mean, listen, I think it's been -- it's probably not our place to comment on geopolitical events and instead focus on global inventories. And I think the relationship between inventories and price has broken down a little bit over the last couple of 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 that's been disruptive. And at times, there's going to be heightened volatility on the upside and heightened volatility on the downside with a steady state far from a possibility today. So I think generally, chasing headlines over the last 3 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 multiyear period, that should be -- that should result in a bid for oil for a longer period of time here. Charles Meade: Got it. And then Second question on the Wolfcamp D. You wrote about that in your shareholder letter that you've been driving down costs there. And if I look at Slide 11, it's actually interesting. That looks like the Wolfcamp D is actually the biggest rate of change from '25 to '26 as far as your lateral footage. So I'm curious, two things, which direction does the causality work there? Are you getting the cost down because you're just -- you're drilling more of them and learning more? Or is it the other way around that you're drilling more because you've gotten the cost down? And perhaps you could also talk about what -- the other side of the equation there, what you're seeing in productivity trends in the Wolfcamp D? Kaes Van't Hof: Yes. So from a cost perspective, the team had a budget of like $350, $360 a foot and their stretch goal is to drill wells at $300 a foot, and they're actually hitting their stretch goal. So that does improve the returns of the Wolfcamp D. What has brought more Wolfcamp D into our program is that when we merged with Endeavor, they had some acreage in kind of the sweet spot of the Wolfcamp D kind of Midland County, Eastern Midland County versus where our prior asset base didn't have as much upside. But in general, as these other zones get more airtime, 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, 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. Operator: Our next question comes from the line of Leo Mariani with ROTH. Leo Mariani: I think there really hasn't been much in the way of Delaware Basin activity over the last handful of quarters. Can you just give us an update kind of what's planned for that asset? Is that just going to kind of sit there and kind of slowly decline over time? Is it something you're going to look to get back after kind of later on down the road? Just any color would be great. Kaes Van't Hof: Yes. 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 Bone Spring in our ReWard position. Those produced some really good results that unlocked some inventory that we probably didn't think was as competitive a couple of 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. 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 there's stuff going on beneath the waves, but no major capital allocated there this year or likely next. Leo Mariani: Okay. And then just on EOR, I know it's kind of early days, and you guys are still analyzing results. But at this point, do you think that you've had clear economic benefit and leased some of the wells out there, maybe not all of them. I know it works better on some versus others. But are you convinced that there's economic benefit in terms of incremental capital that's gone into some of those existing wells? Kaes Van't Hof: Yes, 100%. We just got to figure out -- we got to learn about what's happening. Some wells saw zero uplift, some wells saw production 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 a Wolfcamp B frac in 2014 versus a Wolfcamp B frac today. These are Wolfcamp B fracs from 2014, and we 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. Operator: 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. Kaes Van't Hof: 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. Operator: Thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Before you buy stock in Diamondback Energy, consider this: The Motley Fool Stock Advisor analyst team just identified what they believe are the 10 best stocks for investors to buy now… and Diamondback Energy wasn’t one of them. The 10 stocks that made the cut are built for long-term growth and could produce monster returns in the coming years. 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As with all our articles, The Motley Fool does not assume any responsibility for your use of this content, and we strongly encourage you to do your own research, including listening to the call yourself and reading the company's SEC filings. Please see our Terms and Conditions for additional details, including our Obligatory Capitalized Disclaimers of Liability. The Motley Fool has no position in any of the stocks mentioned. The Motley Fool has a disclosure policy. Diamondback Energy (FANG) Q2 2026 Earnings Call Transcript was originally published by The Motley Fool

Diamondback Energy’s second quarter saw strong revenue growth and profitability compared to Wall Street expectations, but the market responded negatively. Management attributed the quarter’s performance to operational improvements, including enhanced well productivity and cost efficiencies in drilling and completions. CEO Kaes Van’t Hof highlighted the company’s “stacked innovation play,” citing ongoing enhancements in well construction, targeting, and stimulation methods. Additionally, outperformance in gas production resulted from improved local marketing and pipeline access, while investments in automation and AI-supported maintenance further contained operating expenses. Is now the time to buy FANG? Find out in our full research report (it’s free). Revenue: $5.68 billion vs analyst estimates of $4.90 billion (54.3% year-on-year growth, 15.8% beat) Adjusted EPS: $6.48 vs analyst estimates of $5.98 (8.3% beat) Adjusted EBITDA: $3.94 billion vs analyst estimates of $3.63 billion (69.4% margin, 8.6% beat) Operating Margin: 46.3%, up from 30% in the same quarter last year Oil production: up 5.9% year on year Market Capitalization: $52.66 billion While we enjoy listening to the management’s commentary, our favorite part of earnings calls is the analyst questions. Those are unscripted and can often highlight topics that management teams would rather avoid or topics where the answer is complicated. Here is what has caught our attention. Neal Dingmann (William Blair): Asked about Diamondback’s willingness to grow production given low global inventory. CEO Kaes Van’t Hof indicated a bias toward modest growth but stressed flexibility based on inventory trends. Scott Hanold (RBC Capital Markets): Inquired about outperformance in gas production. COO Daniel Wesson attributed the gains to improved local marketing and infrastructure, with Chief Engineer Albert Barkmann adding that technical targeting of some higher gas areas had a minor impact. Arun Jayaram (JPMorgan): Sought updates on Barnett development costs and EOR pilots. CEO Van’t Hof described ongoing cost reductions, while Barkmann detailed early positive EOR results and plans for expansion to more wells. Douglas Leggate (Wolfe): Questioned the trade-offs between building cash, reducing debt, and capital allocation. Van’t Hof emphasized the need for flexibility, balancing debt reduction with the potential for opportunistic buybacks and prudent cash build. Geoff Jay (Daniel Energy Partners): Asked about the deployment of AI and automation for operational efficiency. Management said AI is in early stages, mainly optimizing artificial lift and downtime management, with significant potential long-term. In the coming quarters, our analysts will monitor (1) the pace and results of Barnett and Wolfcamp D development, (2) continued improvements in operating efficiency and adoption of automation/AI in field operations, and (3) execution of the new power/data center project and its effect on gas strategy. Progress on enhanced recovery pilots and ability to offset service cost inflation will also be crucial. Diamondback Energy currently trades at $188.56, down from $198.75 just before the earnings. At this price, is it a buy or sell? The answer lies in our full research report (it’s free for active Edge members). ONE MORE THING: Top 6 Stocks for This Week. This market is separating quality stocks from expensive ones fast. AI is taking down whole sectors with no warning. In a rotation this fast, you need more than a list of good companies. Our AI system flagged Palantir before it ran 1,662% between October 2022 and February 2026. AppLovin before it ran 753% between February 2024 and February 2026. Nvidia before it ran 1,178% between January 2023 and February 2026. Each week it produces 6 new names that pass the same tests. Get Our Top 6 Stocks for Free HERE. Stocks that have made our list include now familiar names such as Nvidia (+1,460% between June 2020 and June 2025) as well as under-the-radar businesses like the once-small-cap company Exlservice (+271% between June 2020 and June 2025). Find your next big winner with StockStory today.

For the quarter ended June 2026, Diamondback Energy (FANG) reported revenue of $5.56 billion, up 51.2% over the same period last year. EPS came in at $6.48, compared to $2.67 in the year-ago quarter. The reported revenue compares to the Zacks Consensus Estimate of $4.76 billion, representing a surprise of +16.82%. The company delivered an EPS surprise of +8.73%, with the consensus EPS estimate being $5.96. While investors scrutinize revenue and earnings changes year-over-year and how they compare with Wall Street expectations to determine their next move, some key metrics always offer a more accurate picture of a company's financial health. As these metrics influence top- and bottom-line performance, comparing them to the year-ago numbers and what analysts estimated helps investors project a stock's price performance more accurately. Here is how Diamondback performed in the just reported quarter in terms of the metrics most widely monitored and projected by Wall Street analysts: Average daily production / Daily combined volumes: 1,017,659.00 BOE/D compared to the 976,804.50 BOE/D average estimate based on eight analysts. Average Prices - Natural gas liquids, hedged: $/18.56 compared to the $/20.01 average estimate based on five analysts. Average Prices - Oil -hedged: $/94.33 compared to the $/95.31 average estimate based on five analysts. Average Prices - Natural gas, hedged: $-0.34 per thousand cubic feet versus $0.18 per thousand cubic feet estimated by five analysts on average. Average Prices - Natural gas liquids: $/18.56 versus $/20.61 estimated by four analysts on average. Total Production Volume - Natural gas liquids: 23,436.00 MBBL versus 21,440.35 MBBL estimated by four analysts on average. Total Production Volume - Natural gas: 128,279.00 MMcf compared to the 118,874.10 MMcf average estimate based on four analysts. Total Production Volume - Oil: 47,791.00 MBBL compared to the 47,491.60 MBBL average estimate based on four analysts. Revenues- Oil, natural gas and natural gas liquid: $4.79 billion versus the five-analyst average estimate of $4.6 billion. The reported number represents a year-over-year change of +44.3%. Revenues- Oil sales: $4.63 billion compared to the $4.17 billion average estimate based on four analysts. The reported number represents a change of +62.2% year over year. Revenues- Natural gas liquid sales: $435 million versus $444.33 million estimated by four analysts on average. Compared to the year-ago quarter, this number represents a +18.5% change. Revenues- Natural gas sales: $-276 million versus $-71.41 million estimated by four analysts on average. Compared to the year-ago quarter, this number represents a -384.5% change. View all Key Company Metrics for Diamondback here>>> Shares of Diamondback have returned +4.2% over the past month versus the Zacks S&P 500 composite's +2.3% change. The stock currently has a Zacks Rank #3 (Hold), indicating that it could perform in line with the broader market in the near term. Want the latest recommendations from Zacks Investment Research? Today, you can download 7 Best Stocks for the Next 30 Days. Click to get this free report Diamondback Energy, Inc. (FANG) : Free Stock Analysis Report This article originally published on Zacks Investment Research (zacks.com). Zacks Investment Research

Diamondback Energy, Inc. FANG reported second-quarter 2026 adjusted earnings per share (EPS) of $6.48, which beat the Zacks Consensus Estimate of $5.96 and more than doubled from the year-ago adjusted profit of $2.67. The outperformance was driven by production growth and a 53.1% improvement in the year-over-year realized oil prices. This Midland, TX-based oil and gas exploration and production company’s revenues of $5.6 billion increased more than 51% from the year-ago quarter and topped the Zacks Consensus Estimate by about 17%, fueled primarily by higher sales of oil, natural gas and natural gas liquids, increased sales of purchased oil and higher revenues from other operating income. Diamondback Energy, Inc. price-consensus-eps-surprise-chart | Diamondback Energy, Inc. Quote In the second quarter of 2026, Diamondback Energy generated free cash flow and adjusted free cash flow of $2.3 billion. Over the same period, it bought back nearly 756,385 common shares for roughly $141 million at an average price of $186.63 per share, excluding excise taxes. In July, the board of directors increased the company's share repurchase authorization from $8 billion to $16 billion, effectively doubling the program's capacity. Following this increase, approximately $9.9 billion remains available for future share repurchases under the authorization. FANG’s board of directors approved a base quarterly dividend of $1.10 per common share for the second quarter of 2026, payable on Aug. 20 to its stockholders of record on Aug. 13. FANG’s production of oil and natural gas averaged 1,017,659 barrels of oil equivalent per day (BOE/d), comprising 51.6% oil. The figure was up 10.6% from the year-ago quarter and beat our model estimate of 969,519.9 BOE/d. While crude and natural gas output increased 5.9% and 16.5% year over year, respectively, natural gas liquids volumes climbed 15.7%. The average realized oil price during the quarter was $96.82 per barrel, 53.1% higher than the year-ago realization of $63.23. The figure also beat our estimate of $66.12 per barrel. Meanwhile, the average realized natural gas price decreased to a negative $2.15 per thousand cubic feet from 88 cents in the prior year. The figure was also below our model estimate of 60 cents. Overall, the upstream oil and gas company fetched $51.68 per barrel compared with $39.61 a year ago. Diamondback Energy’s second-quarter cash operating cost was $10.96 per BOE compared with $10.10 in the prior-year quarter and our estimate of $12.56. The increase in costs compared with the year-ago period reflected a rise in lease operating expenses to $5.96 per BOE from $5.26 in the second quarter of 2025 and an increase in Production and ad valorem taxes to $3.26 per BOE from $2.56 in the prior-year quarter. However, FANG’s gathering, processing and transportation expenses decreased 29.5% year over year to $1.22 per BOE. Cash G&A expenses also fell in the second quarter of 2026 to 52 cents per BOE from 55 cents in the corresponding period of 2025. Diamondback Energy logged $996 million in capital expenditure — spending $842 million on operated drilling and completion additions to oil and natural gas properties, and $154 million on non-operated additions. The company booked $2.3 billion in adjusted free cash flow in the second quarter. As of June 30, the Permian-focused operator had approximately $462 million in cash and cash equivalents and $11.1 billion in long-term debt, representing a debt-to-capitalization of 20.1%. Diamondback Energy updated its 2026 guidance by raising its full-year oil production outlook to more than 522 MBO/d, up from the previous guidance of more than 520 MBO/d, and increasing its total production forecast to over 1,000 MBOE/d from more than 972 MBOE/d. The company maintained its full-year cash capital expenditure guidance at approximately $3.9 billion. For the third quarter of 2026, this Zacks Rank #3 (Hold) company expects oil production to range between 517 MBO/d and 527 MBO/d, with total combined production projected at 995-1,015 MBOE/d. Third-quarter cash capital expenditures are expected to be between $950 million and $1.05 billion. You can see the complete list of today’s Zacks #1 Rank (Strong Buy) stocks here. While we have discussed FANG’s second-quarter results in detail, let us take a look at three other key reports in the energy space. Expand Energy Corporation EXE reported second-quarter 2026 adjusted earnings per share of $1.33, beating the Zacks Consensus Estimate of $1.22. The company’s bottom line increased from the year-ago adjusted profit of $1.10 per share, fueled by strong production and lower operating expenses. Expand Energy’s ‘natural gas, oil and NGL’ revenues of $1.8 billion missed the Zacks Consensus Estimate of $2 billion. The top line was also below the year-ago figure of $2 billion. As of June 30, 2026, the company had $663 million in cash and cash equivalents. Expand Energy had a long-term debt of $3.7 billion, reflecting a debt-to-capitalization of 16%. NOV Inc. NOV reported second-quarter 2026 adjusted earnings of 31 cents per share, which beat the Zacks Consensus Estimate of 16 cents. The bottom line also increased 6.9% from the year-ago quarter’s 29 cents, driven by outperformance of the Energy Equipment segment. The oil and gas equipment and services company’s total revenues of $2.1 billion beat the Zacks Consensus Estimate by $39 million. However, NOV’s revenues fell 2.5% from the year-ago quarter’s figure of $2.2 billion due to lower year-over-year revenues from the Energy Products and Services segment. As of June 30, the company had cash and cash equivalents of $1.2 billion and long-term debt of $1.7 billion with a debt-to-capitalization of 21.3%. Core Laboratories Inc. CLB reported second-quarter 2026 adjusted earnings of 11 cents per share, which beat the Zacks Consensus Estimate of 8 cents, driven by outperformance of the Production Enhancement segment. However, the bottom line decreased from the year-ago quarter’s reported figure of 19 cents due to the underperformance of the Reservoir Description segment and increased costs and expenses. This oilfield service provider reported second-quarter operating revenues of $124.6 million, missing the Zacks Consensus Estimate of $128 million and decreasing from the earlier-year quarter’s reported figure of $130.1 million. This can be attributed to military conflicts in the Middle East and the Russia-Ukraine region, which disrupted energy infrastructure, delaying projects, disrupting crude oil trade and reducing demand for the company's international laboratory services. As of June 30, 2026, the company had cash and cash equivalents of $22.7 million and long-term debt of $113.9 million. CLB’s debt-to-capitalization was about 29%. Want the latest recommendations from Zacks Investment Research? Today, you can download 7 Best Stocks for the Next 30 Days. Click to get this free report Diamondback Energy, Inc. (FANG) : Free Stock Analysis Report Core Laboratories Inc. (CLB) : Free Stock Analysis Report NOV Inc. (NOV) : Free Stock Analysis Report Expand Energy Corporation (EXE) : Free Stock Analysis Report This article originally published on Zacks Investment Research (zacks.com). Zacks Investment Research

Diamondback Energy, Inc. FANG used its second-quarter 2026 earnings call to outline a more growth-oriented operating stance while retaining flexibility around capital allocation. Management tied that posture to low global inventories, stronger well performance, debt reduction and new natural gas demand opportunities. Diamondback increased 2026 oil production guidance to at least 522,000 barrels per day from 520,000 barrels and total production guidance to at least 1 million barrels of oil equivalent per day from 972,000 barrels of oil. Second-quarter oil production averaged 525,000 barrels per day. Total production reached 1.018 million barrels of oil equivalent per day and cash capital spending was $996 million. Adjusted earnings of $6.48 per share beat the Zacks Consensus Estimate of $5.96. Revenue of $5.56 billion topped the $4.76 billion estimate. Diamondback Energy, Inc. price-consensus-eps-surprise-chart | Diamondback Energy, Inc. Quote A William Blair analyst asked whether depleted global inventories support continued growth, and CEO Kaes Van’t Hof said those inventories must be replenished absent permanent demand destruction. CEO Van’t Hof added that the current model points to low-single-digit organic growth in 2027 while maintaining capital efficiency and operating five completion crews. Executive vice president and COO Daniel Wesson said that roughly $1 billion to slightly more than $1 billion of quarterly capital could hold production flat, while efficiency gains could offset casing inflation equal to a little more than 1% of well costs. A Goldman Sachs analyst asked about the flexible shareholder-return framework. CEO Van’t Hof stated that removing a minimum free-cash-flow return commitment lets Diamondback respond to changing market conditions. Diamondback reduced net debt by about $1.6 billion, repurchased approximately $141 million of stock in the quarter and bought another $100 million early in the third quarter. CEO Van’t Hof told a Wolfe Research analyst that cash could be built for 2026 and 2027 debt maturities, adding that the balance-sheet buildup is not intended to finance large cash acquisitions. CEO Van’t Hof informed that new Permian pipelines provided Waha relief, but Diamondback still needs more contracted access to Gulf Coast markets as gas production grows. Executive vice president and CFO Jere Thompson said Diamondback and an independent power producer are developing a bridge-to-grid project on the 30,000-acre Bryant Ranch, with behind-the-meter generation targeted for the second half of 2027. CFO Thompson said the project could support 200 million to 250 million cubic feet per day of gas demand under a pricing structure tied to Waha with a floor, while land and water-related revenues could add value. CEO Van’t Hof said productivity gains reflect stacked improvements in well construction, targeting and stimulation, while Executive vice president and chief engineer Albert Barkmann cited larger tubulars and revised stage architecture. The Barnett program is moving toward broader development, with CEO Van’t Hof saying drilling costs are approaching $400 per foot as Diamondback works to make the play competitive with its base plan. Chief engineer Barkmann described initial results from a 12-well enhanced-recovery project as positive but varied, and CEO Van’t Hof said outcomes ranged from no uplift to production tripling or quadrupling. Management’s tone centered on preserving choices rather than committing to a fixed growth or shareholder-return formula. Diamondback enters the second half with higher production guidance, unchanged full-year capital spending and lower net debt, while Barnett development, enhanced recovery and gas commercialization remain execution priorities. FANG carries a Zacks Rank #3 (Hold). Its Value Score and Growth Score of B are favorable grades. While the Momentum Score of F is the weakest grade, VGM Score of B reflects a middle-tier combined profile. Style Scores complement the Zacks Rank, with the strongest combinations centered on Zacks Rank #1 (Strong Buy) or 2 (Buy) stocks carrying A or B scores. FANG’s Zacks Rank can change as analysts revise estimates after the latest results. You can see the complete list of today’s Zacks #1 Rank stocks here. Want the latest recommendations from Zacks Investment Research? Today, you can download 7 Best Stocks for the Next 30 Days. Click to get this free report Diamondback Energy, Inc. (FANG) : Free Stock Analysis Report This article originally published on Zacks Investment Research (zacks.com). Zacks Investment Research

Interested in Diamondback Energy, Inc.? Here are five stocks we like better. Diamondback raised its production outlook by roughly 3% to 4% versus its original 2026 plan and sees a potential path toward low-single-digit organic growth in 2027, while retaining flexibility amid oil-price volatility. Operational improvements are boosting well productivity and completion efficiency, though rising consumable costs—particularly casing—could add slightly more than 1% to total well costs. Management estimates roughly $1 billion to slightly more than $1 billion in quarterly capital spending could maintain production at current conditions. Diamondback reduced net debt by $1.6 billion in the second quarter and is pursuing opportunistic share buybacks while building cash for upcoming maturities. It is also developing a potential behind-the-meter power project near Midland that could serve future LNG, power-generation and data-center demand. 3 Stocks to Own If Gas Prices Keep Rising Diamondback Energy (NASDAQ:FANG) said its second-quarter operational performance and view of global oil inventories support a potential path toward low-single-digit organic production growth in 2027, while management emphasized it intends to retain flexibility amid commodity-market volatility. Chief Executive Officer Kaes Van’t Hof said the company increased its production outlook by roughly 3% to 4% versus its original 2026 plan after responding to oil-price signals in March. Production is now approximately 4% above its level at the start of the year, he said. → SpaceX’s First Earnings Report Could Decide Whether Shorts or Bulls Have Control Insider Selling: CRWV, DELL & FANG See +$100M in 2026 Sales Looking ahead, Van’t Hof said Diamondback is weighing whether to maintain production at elevated third-quarter levels or grow from that base. At present, the company’s model supports low-single-digit organic growth while maintaining capital efficiency and operating five frac crews consistently through the year. “Our bet is that these global inventories, including SPRs, are going to need to be refilled,” Van’t Hof said, referring to strategic petroleum reserves. He said oil and product inventories have been drawing down and that, absent permanent demand destruction, the market will need additional supply to meet global demand and replenish inventories. → Financials Hit Record Highs as the AI Trade Unravels—Can They Keep Leading? Diamondback Sees Resilient Demand Despite Cautious Guidance Management highlighted continued operational improvements across well construction, targeting and completions. Van’t Hof described the company’s progress as a “stacked innovation” effort, citing incremental advances that have improved drilling and completion performance over time. Chief Engineer Al Barkmann said Diamondback has used larger tubulars that allow more aggressive flowback, while changes in stimulation design, stage architecture, perforating and well targeting have contributed to recent well outperformance. Management said its objective is to maximize the combination of wells per section, production per well and low well costs to generate the highest net present value per section and acre. → Why Rare Earth Processing Could Be the Real 2027 Opportunity The company also discussed completion efficiency. Chief Operating Officer Danny Wesson said Diamondback averaged more than 21 hours of pumping per day during the first full quarter of continuous pumping. While the company sees potential to continue improving, Wesson said maintenance requirements and the cost of equipment redundancy create practical tradeoffs. Diamondback is targeting average completion performance of 5,000 feet per day across its crews, after some pads surpassed that level, according to Wesson. The company is also using electric frac fleets, which management said have helped mitigate fuel-cost inflation. On oilfield service costs, Wesson said Diamondback is seeing some inflation in consumables, particularly casing in the second half of 2026. He estimated the impact at slightly more than 1% of total well costs, adding that the company expects to offset much of that pressure through efficiency gains. Management said a quarterly capital run rate of roughly $1 billion to slightly more than $1 billion could be reasonable to hold production flat based on current conditions. Van’t Hof said improved gas pricing at Waha during July, following the start-up of new pipelines, provided near-term relief after weak second-quarter conditions. He said Diamondback views natural gas as an additive component of its oil-focused strategy and intends to secure more contracted transportation capacity to Gulf Coast markets, where gas demand could come from LNG exports, power generation and data centers. The company said gas production has exceeded expectations. Wesson attributed much of that outperformance to improved local gas marketing, including maturing gathering and processing systems, additional redundancy and strategic split connections. Barkmann said a growing role for Barnett development could cause gas volumes to increase further over time. Chief Financial Officer Jere Thompson provided an update on a proposed power project at Diamondback’s approximately 30,000-acre Bryant Ranch site near Midland, Texas. The project is being developed with an independent power producer and is intended to provide a bridge-to-grid power solution using behind-the-meter reciprocating units. Management said the site has distributed generation, remediated land, and dedicated natural gas and water access. The initial phase could deliver first gas as soon as the second half of 2027, according to Thompson. Diamondback is also pursuing grid-connected power as early as 2028 through ERCOT’s Batch Zero process. The company was awaiting ERCOT’s determination on project eligibility following an August 20 meeting. Thompson said Diamondback has set aside 200 million to 250 million cubic feet per day of natural gas for the project. He described a potential in-basin feed-gas solution as the project’s largest value driver, with additional possible benefits from Diamondback’s 30% interest in water infrastructure company Deep Blue and potential land-related proceeds. Management said it would provide a broader update after signing definitive documentation with a hyperscale customer. Van’t Hof stressed that Diamondback does not plan to become a power or data center operator, but intends to provide molecules, surface acreage, water and industry knowledge. Van’t Hof said Diamondback has moved away from a formulaic minimum free-cash-flow return commitment in favor of a more flexible capital-allocation approach. The company repurchased some shares in the second quarter and continued buying stock in the third quarter, he said, while also reducing net debt by $1.6 billion during the second quarter. Van’t Hof estimated that the debt reduction represented $5.60 per share of value moving from the debt side of the capital structure to equity. He said Diamondback intends to use buybacks opportunistically rather than pursue procyclical repurchases. The company also plans to build enough cash to address debt callable in 2026 and prepare for 2027 maturities, while potentially accumulating cash for maturities due between 2029 and 2032. Van’t Hof said cash accumulation is not intended to fund large cash acquisitions. Diamondback said it continues to expand and consolidate its Barnett position, including through leasing activity with Double Eagle. The company’s first four-well Spanish Trail pad has been drilled and is expected to be completed in coming months. Management said it expects full-section results around year-end or early 2027. Van’t Hof said Barnett drilling costs are approaching $400 per foot, with some wells already below that level. The company expects to achieve costs around $400 per foot or less consistently as it builds scale in the play. The company is also testing surfactant-based enhanced oil recovery techniques. Barkmann said Diamondback completed a 12-well project during the quarter and was flowing back the wells, with initial results described as positive. Management said results have varied widely across earlier work, with some wells showing no uplift and others producing three to four times more than before treatment. Van’t Hof said the average earlier result involved wells producing roughly 150 to 200 barrels per day gaining an additional 100 to 150 barrels per day, though the company is still determining which rock types and reservoir conditions respond best. Diamondback is also incorporating the approach into new-well pads, with control and surfactant-treated portions of certain sections. Management said it sees artificial intelligence and automation as early-stage tools for improving artificial lift optimization, reducing downtime and lowering operating costs. The company’s lease operating expense fell below $6 per barrel during the quarter, primarily because of higher production volumes, though management said it expects costs to remain around that level or somewhat higher in the second half. Diamondback Energy, Inc (NASDAQ: FANG) is an independent oil and natural gas company focused on the development, exploration and production of unconventional resources in the Permian Basin. Headquartered in Midland, Texas, the company concentrates its operations in the core Midland and Delaware sub‑basins of West Texas and southeastern New Mexico, where it pursues contiguous acreage positions to support repeatable drilling programs. Diamondback's activities span the upstream value chain, including leasehold acquisition, well planning, drilling, completion and production optimization. This instant news alert was generated by narrative science technology and financial data from MarketBeat in order to provide readers with the fastest reporting and unbiased coverage. Please send any questions or comments about this story to [email protected]. The article "Diamondback Energy Q2 Earnings Call Highlights" was originally published by MarketBeat. View MarketBeat's top stocks for August 2026.

This article first appeared on GuruFocus. Release Date: August 04, 2026 For the complete transcript of the earnings call, please refer to the full earnings call transcript. Diamondback Energy Inc (NASDAQ:FANG) is strategically positioned to grow production into 2027, leveraging low global inventory levels and a positive oil price backdrop. The company's well productivity is outperforming expectations, driven by stacked innovations in well construction, targeting, and stimulation, leading to higher NPV per acre. Improved gas marketing and processing, including new pipeline egress, have turned Waha prices positive, providing a near-term tailwind for the company. The company is advancing a shovel-ready power project with a hyperscaler, which could provide a new in-basin gas egress solution and material uplift to cash flows. Enhanced oil recovery (EOR) pilots are showing promising initial results, with some wells seeing production triple or quadruple, potentially reducing base declines. The company reduced net debt by $1.6 billion in Q2, translating to $5.60 per share of value transferred from debt to equity. Operational efficiency continues to improve, with a record 21+ hours of average pumping time per day and a goal of reaching 5,000 feet per day across all crews. The Barnett position has grown and is being developed at a low cost, with drilling costs approaching $400 per foot, making returns competitive with the base plan. The company is leveraging AI and automation to optimize artificial lift and reduce downtime, which could lower sustaining capital requirements. Management maintains flexibility in capital allocation, choosing to buy back shares opportunistically while also building cash to handle near-term debt maturities. The company faces potential oilfield service cost inflation, particularly in casing prices, which could increase well costs by over 1% in the back half of the year. Global oil market volatility remains high, with geopolitical noise and a breakdown in the inventory-price relationship, making it difficult to predict future prices. The company is not allocating capital to the Delaware Basin this year, allowing that asset to decline, though it may unlock inventory through farm-outs. EOR results show wide dispersion, with some wells seeing zero uplift, indicating the technology is not yet universally applicable and requires further learning. The company is building cash on the balance sheet, which could be seen as a drag on returns if not deployed effectively, though management says it's for debt maturities. Gas production outperformance is partly due to better marketing, but the company still faces the risk of negative prices if egress issues reoccur. The power project is still in early stages, with no definitive hyperscaler agreement signed, and faces regulatory uncertainty from ERCOT's Batch 0 determination. The company's decision to remove its minimum return of capital commitment may create uncertainty for income-focused investors, despite management's explanation. Inflation in power and water costs is expected to flow through to LOE, potentially keeping it around $6 per barrel or higher in the back half of the year. The company's growth strategy relies on continued low global inventories, which could be disrupted by demand destruction or unexpected supply increases. Warning! GuruFocus has detected 11 Warning Signs with FANG. Is FANG fairly valued? Test your thesis with our free DCF calculator. Q: Given your view that worldwide inventory levels will remain low, will Diamondback continue to strategically grow production into 2027? A: CEO Case Vanthaus confirmed that the company is leaning toward growth, citing global inventory draws on both oil and products. He noted that Diamondback was the first to respond to price signals in March by increasing production 3%-4%, and is now up ~4% from the start of the year. The current model suggests low single-digit organic growth while maintaining capital efficiency and running five frac crews consistently. He emphasized the company's ability to react quickly to either positive or negative signals. Q: Can you provide an update on the power and data center project, and the gas egress strategy? A: COO Jerry Thompson detailed a "shovel-ready" bridge-to-grid project on 30,000 acres at Bryant Ranch near Midland, Texas. The project, developed with an IPPP partner, will deliver first gas in the back half of 2027 using behind-the-meter RSIP units. They are also pursuing grid-connected power via ERCOT's Batch 0, with a determination expected August 20th. CEO Case Vanthaus added that the company is focused on securing more contracted gas space to the Gulf Coast to capitalize on the LNG and data center mega themes, noting the project provides a new in-basin egress solution for natural gas. Q: How are you thinking about return of capital given the removal of the minimum commitment, and how did you approach it in Q2? A: CEO Case Vanthaus explained the goal is to maximize option value in a volatile business. In Q2, the company allocated a bit to buybacks during weakness but also reduced net debt by $1.6 billion, translating to $5.60 per share of value moving from debt to equity. He stated that investors have been supportive of the flexible strategy, and the company will lean into buybacks when the cycle turns, positioning the balance sheet to do so. He highlighted that in 2025, the company bought back over 5% of its stock. Q: Why is natural gas production outperforming expectations, and where do you see that going? A: COO Danny Wesson attributed the outperformance to improved marketing of gas locally, maturation of GMP systems, and better flaring metrics. Chief Engineer Al Bartman added that while well selection wasn't a major driver this quarter, the increasing role of the Barnett in the development plan will cause gas production to creep up over time. Q: What are you seeing on the oilfield service cost front, and what is the steady-state capital run rate? A: COO Danny Wesson noted some inflation in consumables, particularly casing prices in the back half of the year, which represents a little over 1% of total well cost. He expects to offset this with efficiency gains. For 2027, he estimated a run rate of around $1 billion to a little over $1 billion per quarter to hold production flat, though continued rig additions in the US could create more pressure. Q: Can you provide an update on the Barnett development and the progress on reducing drilling costs? A: CEO Case Vanthaus stated the Barnett position has continued to grow and block up. The first four-well pad at Spanish Trail has been drilled and will be completed in the next couple of months. Drilling costs are approaching $400 per foot, with a few wells already below that mark. He expects to consistently hit around $400 or less per foot to make returns competitive with the base plan. Q: What are the initial results from the enhanced oil recovery (EOR) surfactant program, and how will you expand it? A: Chief Engineer Al Bartman reported that a 12-well project was executed this quarter with very positive initial flowback results. The team is learning which rock types and reservoirs the technology is best suited for and will apply those learnings to the next group of wells in Q3. CEO Case Vanthaus added that the program is expanding to new completions, with pads featuring a control half and a surfactant half to measure the impact. Q: With the impressive operational achievements, including 21 hours of average pumping time per day, what is achievable in the future? A: COO Danny Wesson said the team is pushing toward a full 24 hours of pumping, but there is a balance between adding redundant equipment and cost. He noted some pads have broached 5,000 feet per day on average, and the next goal is to achieve that across all crews consistently. He believes this is achievable within the next year. Q: How much do operational improvements and resource expansion contribute to a higher NAV, and how does that factor into capital returns? A: CEO Case Vanthaus explained that operational improvements and accretive asset additions have more than doubled the company's mid-cycle NAV buyback top since 2021. He cited the Barnett, Jo Mill, and Upper Spraberry as examples of zones that weren't significant then but are now. He expects this trend to continue, driving higher per-share value through a reduced share count and lower debt. Q: What did you see on productivity and costs for the U-turn wells, and how are you integrating them into the plan? A: COO Danny Wesson said the six wells drilled so far haven't been completed yet, but the drilling phase was a success with lower per-foot costs than standalone 7,500-foot wells. Completed U-turn wells inherited from an acquisition performed in line with regular 10,000-foot wells on productivity and execution. The first fully developed Diamondback pad is still in progress. Q: Where are you prepared to take the balance sheet in terms of building cash versus debt redemptions, and would you use capital efficiency to lower spending or increase production? A: CEO Case Vanthaus stated the company wants to build enough cash to take care of 2026 maturities and be prepared for 2027s, and potentially tackle maturities in the 2029-2032 timeframe. He is not afraid to put cash on the balance sheet, noting it's prudent at this point in the cycle. On capital efficiency, he said the decision varies by yearsome years it makes sense to grow, while others (like 2024 and 2025) it made sense to cut CapEx and return cash. The company will maintain flexibility. Q: How far For the complete transcript of the earnings call, please refer to the full earnings call transcript.

Our analysts just identified a stock with the potential to be the next Nvidia. Tell us how you invest and we'll show you why it's our #1 pick. Tap here. Management attributes the decision to skew toward organic production growth to a macro view that global oil and product inventories, including Strategic Petroleum Reserves, must be refilled. Performance outperformance is driven by a 'stacked innovation' framework, combining faster well construction, optimized targeting, and aggressive stimulation techniques to maximize NPV per acre. The company has successfully transitioned from drilling wells in 30 days to just 5 days, reflecting a continuous improvement culture that offsets inflationary pressures. Operational efficiency gains, specifically reaching over 21 hours of average pumping time per day, are being utilized to maintain a capital-efficient run rate of approximately $1 billion per quarter. Strategic positioning in the Barnett and Wolfcamp D zones has expanded the inventory depth without sacrificing productivity per foot, despite the historical industry trend of secondary zones diluting performance. Management emphasizes that capital allocation remains flexible, prioritizing the maximization of corporate option value over rigid return-of-capital formulas. Guidance for 2027 assumes low single-digit organic growth while maintaining a consistent 5-frac crew program and capital efficiency. The company is developing a 'bridge-to-grid' power solution at Bryant Ranch, targeting first gas delivery by late 2027 and grid connection via ERCOT's Batch Zero as early as 2028. Enhanced Oil Recovery (EOR) initiatives, specifically surfactant programs, are expected to become a 'mega theme' for the company to either shallow base declines or replace higher-cost capital. Management plans to build cash on the balance sheet to address 2026 and 2027 debt maturities, positioning the company to lean into share buybacks when market volatility presents opportunities. Gas strategy is evolving toward a 'wellhead to water' approach, seeking more contracted space to Gulf Coast LNG terminals to capture global demand. Anticipated inflation in casing prices during the back half of the year is expected to impact total well costs by slightly over 1%, though management aims to offset this through efficiency. The Waha gas basis remains a volatility risk, though recent pipeline additions provided relief compared to the negative pricing experienced in Q2. Regulatory uncertainty regarding ERCOT's Batch Zero standards for the power project is being closely monitored, with a key eligibility meeting scheduled for August 20. Management explicitly stated that cash accumulation is intended for debt reduction and buybacks, not for large-scale cash-based M&A that would stress the balance sheet. Kaes Van't Hof noted that low global inventories provide confidence in a long-term bid for oil, justifying low single-digit organic growth. The company maintains the ability to react quickly to price signals, as demonstrated by the 4% production increase earlier in the year. One stock. Nvidia-level potential. 30M+ investors trust Moby to find it first. Get the pick. Tap here. Drilling costs in the Barnett are trending toward $400 per foot, with a goal to reach sub-$400 levels to ensure returns are competitive with the core program. The Wolfcamp D program has achieved a stretch goal of $300 per foot, significantly improving the zone's economic standing within the portfolio. The project aims to dedicate 200 to 250 million cubic feet per day of natural gas, providing a new in-basin egress solution and potential 'Waha plus' pricing. Diamondback will provide the molecules, surface, and water, while partnering with specialists for the power and data center operations. Initial results from a 12-well surfactant package showed wide dispersion, with some wells seeing production triple or quadruple. Management is treating current EOR efforts as a learning phase to identify which rock types and lithologies respond best to specific chemical compositions. The company removed its minimum free cash flow return commitment to avoid procyclical buybacks and maximize flexibility. Net debt was reduced by $1.6 billion in Q2, which management views as transferring $5.60 per share of value from debt to equity.

Interested in Viper Energy Inc.? Here are five stocks we like better. Viper Energy raised its annual base dividend 32% to $2 per Class A share while ending its requirement to return at least 75% of quarterly distributable cash, giving management more flexibility for buybacks, acquisitions and debt reduction. Steady Permian development supported a third-quarter production outlook implying roughly 4.5% sequential growth and high-single-digit organic growth for 2026, with 691 gross horizontal wells brought online during the second quarter. Viper completed about $103 million of acquisitions and announced a roughly $160 million dropdown from Diamondback Energy; management also highlighted continued share repurchases and potential growth from Barnett and Woodford acreage. 3 Dividend Stocks Defying the Market Downturn Amid the Iran Conflict Viper Energy (NASDAQ:VNOM) said steady development activity across its mineral and royalty acreage supported second-quarter execution and prompted the company to initiate third-quarter average production guidance implying roughly 4.5% growth from the second quarter. Chief Executive Officer Kaes Van’t Hof said operators brought 691 gross horizontal wells online during the quarter on Viper’s acreage, where the company held an average 3% net revenue interest. The midpoint of third-quarter guidance implies an approximately 15% annualized increase in oil production per share compared with the fourth quarter of 2025, he said. → SpaceX’s First Earnings Report Could Decide Whether Shorts or Bulls Have Control MarketBeat ‘Stock of the Week’: Viper winds up as oil prices sink The company also announced a revised capital-return framework centered on a higher fixed dividend and more discretion over the use of remaining cash flow. Viper raised its annual base dividend by 32% to $2 per Class A share, effective in the third quarter, while ending its prior commitment to return at least 75% of quarterly cash available for distribution. For the second quarter, Viper returned 75% of cash available for distribution to stockholders, including $132 million of share repurchases and a combined base and variable dividend of $0.67 per share. → Financials Hit Record Highs as the AI Trade Unravels—Can They Keep Leading? Under the new framework, the company intends to prioritize a larger and more durable base dividend rather than a variable distribution tied to commodity prices. At the company’s current share price, Van’t Hof said the new annualized base dividend represents an approximately 4.5% yield. “The base dividend is sacrosanct,” Van’t Hof said, adding that management is committed to steadily growing it over time. He said the increased dividend represents about 50% of free cash flow at $70 per barrel West Texas Intermediate crude. → Why Rare Earth Processing Could Be the Real 2027 Opportunity Viper said it will retain flexibility to use cash beyond the dividend for share repurchases, debt reduction and acquisitions. Van’t Hof told analysts the company had concluded that the market was not adequately valuing its former variable-dividend approach. “We do not believe the market is currently valuing the variable dividend framework,” Van’t Hof said. “In its place, we believe our new capital allocation framework will better highlight the attractiveness of Viper’s dividend and enable a more compelling growth outlook to be paired with the existing yield.” Management emphasized buybacks as a key use of capital while Viper believes its shares are undervalued. Van’t Hof said Viper repurchased slightly less than $150 million of stock during the second quarter and had continued buying shares at a similar daily pace before its blackout period. He said there could be quarters in which the company returns all of its free cash flow through a combination of the base dividend and stock repurchases. If the market does not recognize Viper’s growth prospects, “we’re going to keep buying back and shrink the share count,” he said. The updated framework also gives Viper more capacity to self-fund acquisitions rather than relying on equity markets for every transaction, Van’t Hof said. He described the larger asset-and-development market as unusually active, noting that Viper recently completed the Riverbend transaction and sees a broad set of potential opportunities. President Austen Gilfillian said the company completed about $103 million of acquisitions during the quarter and announced an approximately $160 million dropdown from Diamondback Energy. He said Viper has gained traction in smaller “ground game” transactions while also evaluating larger packages. Viper sees a constructive acquisitions-and-divestitures market despite commodity-price volatility. Management said buying back Viper shares currently appears attractive relative to some acquisition opportunities. The company intends to allocate capital among deals, repurchases and balance-sheet management based on relative value. Gilfillian said the third-quarter production outlook incorporates approximately 2,000 barrels per day from Riverbend assets but still implies about 1,000 barrels per day of quarter-over-quarter organic growth. He characterized Viper’s overall 2026 organic growth outlook as high single digits after excluding effects from a non-Permian divestiture. While he did not project a specific growth rate for 2027, Gilfillian said the company’s visible activity supports “some modest growth” from this year’s exit rate. Van’t Hof said Viper sees organic growth potential beyond 2027, particularly from Diamondback’s development of the Barnett formation. Viper has historically captured roughly 75% to 80% of Diamondback’s gross activity, with an average net revenue interest of about 6%, Gilfillian said. Certain areas can carry substantially higher interests; he noted that some wells can have a 25% net revenue interest where Viper owns the full royalty. Management highlighted Diamondback’s planned full-well-pad development targeting the Barnett formation in the Spanish Trail area. Van’t Hof said that if well performance and costs meet expectations, full-section Barnett development at Spanish Trail could rank in the top decile of Diamondback’s combined inventory based on returns and net present value. Gilfillian said third-party operator activity has remained generally consistent on a gross basis, though quarterly net results can vary. The company is focused on acquiring exposure to high-returning undeveloped Permian acreage regardless of operator, he said. He added that rising Permian rig activity can accelerate the conversion of permits and drilled-but-uncompleted wells into production, bringing volumes forward for Viper. Management said the company benefits both from Diamondback’s development of Viper’s concentrated mineral interests and from broad exposure to other operators across the basin. Viper has also seen increased leasing activity for deep rights in the Woodford formation in the Delaware Basin. Gilfillian said the company had spent approximately $25 million to $30 million on lease bonuses for deep rights, representing about one-third of its total leasing effort since early 2025. Such leases typically provide operators with a three-year development window, which management said could support future production growth. Viper Energy Partners LP is a publicly traded master limited partnership that owns and intends to acquire mineral and royalty interests in oil and natural gas properties. As a pass-through entity, Viper Energy Partners does not engage in drilling or production operations directly; instead, it generates revenues by holding overriding royalty interests, mineral fee interests and royalty fee interests. These interests entitle the partnership to receive a percentage of the proceeds from hydrocarbons produced and sold by third-party operators. The partnership's assets are concentrated in the Permian Basin, with a primary focus on the Delaware Basin region of West Texas and southeastern New Mexico. This instant news alert was generated by narrative science technology and financial data from MarketBeat in order to provide readers with the fastest reporting and unbiased coverage. Please send any questions or comments about this story to [email protected]. The article "Viper Energy Q2 Earnings Call Highlights" was originally published by MarketBeat. View MarketBeat's top stocks for August 2026.