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Diamondback Energy is an independent oil and natural gas company. Focused on the acquisition, development, exploration, and production of unconventional, onshore oil and natural gas reserves, the company primarily operates in the Permian Basin in West Texas, expanding into the top oil producer focused exclusively on the Permian. Diamondback has grown through strategic acquisitions, including the recent $26 billion merger with Endeavor Energy Resources, making it one of the largest producers in the country. Diamondback continues to play a significant role in meeting the nation’s energy needs.

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Diamondback Energy (FANG): Company Profile, Stock Price, News, Rankings

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Diamondback Energy

diamondback energy

Good day and thank you for standing by. Welcome to the Diamondback Energy's Second Quarter twenty twenty five Earnings Call. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer session. Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your first speaker today, Adam Lawless, VP of Investor Relations. Please go ahead.

Thank you, Brianna. Good morning, and welcome to Diamondback Energy's second quarter twenty twenty five conference call. During our call today, we will reference an updated investor presentation letter to stockholders, which can be found on our website. Representing Diamondback today are Case Vantolf, CEO Danny Wesson, COO and Jerry Thompson, CFO. 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 Case.

Thank you, Adam, and good morning, everyone, and thanks for taking the time to listen into our earnings call. We're in our conference room in Midland, Texas with no air conditioning and truly valuing the importance of American Energy this morning with no air conditioning in his office. So we'll get it started. I hope you read our letter investor presentation and release last night, and we're going to go straight into Q and A.

Thank you. At this time, we will conduct the question and answer session. Our first question comes from Arun Jayaram of JPMorgan Securities LLC. Your line is now open.

Good morning. Sorry about the AC situation. Hope you have a couple of fans because it can get hot in Midland in the middle of the summer.

Hopefully, this is not part of Case, the your thoughts on reducing costs at the company because they see it as being important. Yeah. But let me shift gears a little bit. Case, I want to hit this one kind of head on. There's been a lot of consolidation talk in the industry, particularly from some of your big cap peers who've highlighted some of the benefits they've received from synergy capture from previous deals.

So wondering if you could comment on how you think about the consolidation roadmap in the Permian and FANG's role within the industry and just overall M and A thoughts.

Yes. I mean, question Arun. I mean, I think first and foremost, we have to remind everybody that our job is to maximize shareholder value. And I think we've done that very successfully at Diamondback over the last fifteen years. And what I think and I think investors would agree is extremely has been an extremely tough tape.

So generating alpha and creating value in a tough tape is what we've done. And we've done that via an acquire and exploit strategy in the Permian where we've been able to cut costs and execute better than anybody else on the assets we acquired. And I think that ability to integrate acquisitions and not have any issues executing post doing it, the most recent example is Endeavor, almost doubled the size of the company and outside to investors, looked like we didn't skip a beat. So listen, we got a young team executing at the highest level in the prime of all of our careers and we're only getting better quarter in quarter out as proven with the results today. So I think the way we see it is we should naturally be the consolidator of choice as we execute at a lower cost and better overall development strategy, some slides we put in the deck today that are pretty interesting.

And until someone else can prove they can do it better than us and we lose our edge, then we should be the consolidator of choice. So that's what I spend my time thinking about. I think it's interesting to see larger peers get bigger in the basin and talk about M and A, but I think we're singularly focused on continuing to execute at the highest level, and we exhibited that today.

Great, Casey. My follow-up, you announced some noncore, non op Delaware Basin property sales in the quarter. I was wondering if you could maybe give us some thoughts on the broader asset sale target of 1,500,000,000 in particular, maybe an update on the Endeavor water drop.

Yes. So we announced a $1,500,000,000 non core asset sale target with the Double Eagle transaction that closed early in the second quarter. We're a small way through it with two small sales, non op sale and the BANGL sale getting us to about $250,000,002 60,000,000 of cash in the door coming in this quarter. The other two big pieces of non core assets that we see as on the block are our EPIC pipeline stake, which we've increased to 27.5% of that pipe. It's a pretty valuable pipe now with the last remaining expansion out of the basin.

And then the other piece being our Endeavor water assets that we feel make a ton of sense in our Deep Blue JV. So we're working on both of those projects imminently. It's hard for us to put too much detail when we don't have binding documents done, but we are working on binding documents for both of those. So expect to have a very fulsome update for our shareholders at some point in the next quarter or two on hitting that target and getting that cash in the door.

Thank you. Our next question comes from David Deckelbaum of TD Cowen. Your line is now open.

Thanks for taking my questions, guys. I'll keep it short in the interest of comfort. I'm wondering if you can contextualize a bit more case the opportunity to address some of the production downtime and focus on the production tail. Can you quantify the size of that opportunity that you think can be addressed over the next couple of years?

Yes, I'll give you the high level. Commentary is kind of new to us, right? I mean, you look back at the development of shale or Diamondback, used to be 80% of our spend was on capital and 20% was on op costs. And now here we are at the size that we are, capital is 65% or so of our spend, op costs are 35% we think it's going to fifty-fifty. And I think there's a lot of things to work on, on the tail of our production, some of which came over from ideas the Endeavor team had and we're seeing some interesting results on some of our, we call them HCL jobs.

But I think if we can get a lot of little wins on the production side of the business, reduce downtime by 1% here, 1% there, do some of these workover jobs that bring some of the old wells back to life, so to speak, that kind of adds up over a very large program. So I don't know, Danny or Chad, you want add anything that we've been doing on that and our focus on that, but that's the highlights.

Yes, I mean, we've really leaned in a little bit more to our workover program this year. The spend, non DC and E spend budget line item is a little larger this year than it has been years past and really to allocate some more capital to working over older wells and trying to optimize the tail and we've seen some some really encouraging stuff out of out of that program. You don't have anything we can really quantify today, but we're going to continue to work that and get some data around it so we can talk to it in the future. But I think some of these wells that are three, four or five years old that have been impacted by offset fracs and whatnot. When we go into them and clean them out and put some acid or some other you know chemical optimization into the reservoir simulation into the reservoir we're seeing you know almost 20 to 50 to 100% you know improvement in production on lower production volumes.

But it was very encouraging what we're seeing on some of the work we're doing on the tail end of the production curve.

Thanks for the color, Danny. Maybe, Keh, just following up on just Arun's comments with some of the non core sales targeted for perhaps the back half of this year. How do you think about managing that cash coming in the door versus some of your debt targets by the end of the year and some shareholder returns?

Yes. I mean, think getting the cash in the door will help pay down our two year term loan that we took out with the Double Eagle deal. That's really our big piece of debt that's due in 2027. We have another note due in 2026, but it's 3% interest. So we'll just build cash to be able to take that out and enjoy that 3% interest for the last year that we have it.

I think overall, we have some nice tailwinds here in Q3, a little lower CapEx, production strong, a pretty big cash tax tailwind with the one big beautiful bill flowing through. And so that should create more free cash or significantly more free cash in Q3, some of which can be used to pay down debt. But a combination of that plus non core asset sales probably gets us into a really good spot where we think we could lean in on repurchases should things weaken further from here.

Thank you. Our next call is from Neil Mehta of Goldman Sachs and Co. Your line is now open.

Yes, thanks, Kase and team. If you can provide an update to the stoplight analogy, it sounds like you still think we're at yellow here, but your perspective on the macro and how that informs your activity decisions as there's some bifurcation in the industry about how they want to how players want to approach the back half of the year and you guys have definitely taken a more guarded position here. So talk about the top down view that informs how you're approaching your activity.

Yes, Neal, good question. I think the stoplight unveiled itself last quarter and I don't think it's going anywhere anytime soon. Unfortunately, we still think we're in the yellow situation, but if you go back to kind of May 5, May 4 when we released Q1 earnings, there's probably still more uncertainty then than there is today. And basically, we said we're prepared to go red if needed back then. And I think we're still ready to do that.

But I think it seems that the double whammy of a demand shock and a supply shock had dissipated for now. There's still a lot of firms, yours included that see oil prices as much lower next year. I don't know if I believe that they're going to be that low, but it's certainly hard for me to get extremely bullish today. And that's why I think 2025 for us is a year of debt reduction and share count reduction, waiting for that spring to coil when commodity prices do rally at some point.

Guess that kind of ties into the M and A in relation to last quarter, I think your message was Double Eagle represent an opportunity for you guys to pause because at that point you had consolidated a lot of the higher quality positions in the Permian and you want to stay a pure play and then incremental M and A if it's done or would probably be done from a Viper Energy perspective where you view that as a roll up story. Is that still the framework or are you suggesting a different posture year to date?

No, that's still our base case. I mean, think at Diamondback, we're very fortunate to have the inventory quality and depth that we have today. There certainly is more consolidation to happen in the Permian. I think for Diamondback, we need to be a lot more selective than we've been in the past because there's not a lot of inventory out there that competes for capital in our top quartile that we have today. And that's why we were so aggressive on Double Eagle.

And unfortunately, the timing wasn't great as that it closed right before Liberation Day, but we still feel very happy about the assets we acquired there, the sub-forty percent breakeven inventory we acquired there. And we really don't see that much sub-forty breakeven inventory in hands of potential targets. So I think we have to be a lot more selective. Viper, on the other hand, we can talk about on the Viper call, has had a great year consolidating and building that business. But I think your analysis is correct that Diamondback is going to be more patient and Viper is going to keep growing its business.

Thank you. Our next question comes from Scott Hanold of RBC Capital Markets. Your line is now open.

Yes, good morning all. You all every quarter seem to find ways of squeezing out more efficiency, getting drill days down and etcetera. Look, how many more things can you do? I mean, drilling days can't go to zero, but like, do you have a line of sight on how you can continue to improve efficiencies? Are you getting to a point where you're more at the optimal level?

And maybe if we understand what the leading edge kind of metrics right now are versus averages that'd be helpful.

Hey, Yeah, thanks for the question. Love to talk about the ops guys and nice reprieve and some of the stuff we talked about on these calls. So I think the drilling guys in particular have done a phenomenal job of really chasing that leading edge well and getting to that leading edge well more consistently. I think we've hit these four or five day wells that we talk about kind of sporadically throughout quarters in the past, but they're getting to where they're hitting them more consistently. And I think that's the real efficiency driver is how do we become more consistent and chasing those really record wells.

You know we continue to push lateral lengths longer. We put in our letter a highlighted a well that you know we drilled 30 plus thousand feet. I think it was a record well in Texas and so you know we're really pushing the limits of what we've known to be capable to do on the drilling side and I really don't know where the threshold limits going to take us there. But you know the guys have done a really good job of just consistently eliminating you know the downtime out of the operation and chasing that leading edge well in every section of the drilling well. And on the completion side you know they continue to do the same thing.

Just chasing that final frac efficiency continuing to get better pad after pad and you see that in the results of the aggregate lateral footage per day pushing 4,000 foot per day on the final frac crews. Look, I think there's opportunities to do some different things in the final frac world where we can grow that efficiency 15% to 20% more on top of that. We're not done chasing those things. Think we'll continue to try and lead the pack in the Permian with regards to drilling completion efficiency and I think at some point in time we will reach a plateau but we don't see it here in the near future.

All right, that's good to hear. And my follow-up question is, you all had a bit stronger gas production this quarter. And it sounds like it came from more gas capture and processing improvements. Can you tell us how much more of that is yet to come? And is that something where your midstream partners are investing more capital to improve it?

Are you doing things differently with them? Or give us a little bit of color behind what really drove that and how much more can we see from that perspective?

Yes, Scott. Mean, the backstory there is a business that we invested in WTG, West Texas Gas sold to Energy Transfer a year ago. WTG has been spending a lot of capital adding plants and capacity to a very high growth area, Martin County, of which we were the largest producer on the system. With that growth, there was some growing pains and some power issues that took both WTG and Energy Transfer some time to work through. But now we've started to see that those plants operate a lot more efficiently.

And the big increase was to our liquids yields. We've added 33,000 barrels a day of NGLs to our production in Q2 over Q1 like the snap of a finger. And I think that's very positive for long term cash flow and as well as the production in that area makes it more economic. So big wins from the Energy Transfer team, that's why we put them in the letter. But we continue to do things on our side too.

I mean, flaring was down 75 bps or 100 bps in the second quarter versus the first quarter That ties to the gas capture side. So really trying to get all three molecules generating as much revenue as possible for Diamondback here.

Thank you. Our next question is from John Freeman of Raymond James. Your line is now open.

One of the majors is recently sort of highlighted some pretty ambitious targets for kind of dramatically improving kind of oil recovery rates in the Permian. Just sort of your thoughts on that side of the equation. Obviously, have done a fantastic on the cost side and just anything that you all are looking at on the recovery rate side of things.

Yes, mean, listen, we're always trying to drill better wells, right? We added an interesting slide this quarter, Slide nine, about our development strategy where we talk about how many zones per section, how many wells per section we're drilling. And I think it's well known that Diamondback is the cost leader in the basin, but I think it's less understood that we're also a technical leader in the basin, drilling, maximizing both returns and resource, right? With our cost structure, we're able to put another couple of wells in every section. And if we're getting the same production per well than peers that are spacing wider than ours, then we're naturally generating better returns and more recoveries for our shareholders.

And I think with respect to your comments on the ambitious goals, I think that's amazing. I'm not going to knock technology developments in the basin because Diamondback is naturally going to be a beneficiary of that. And I think it's positive all around. So I hope it all works. We're going to continue to look across the fence line and try to drill the best wells possible, which I think we've done over the last ten years.

And maybe some technology will help us combine with our low cost structure over the next ten years.

Great. And then just one housekeeping item for me. Was there a production associated with the Delaware Basin non op divestiture?

Yes, there was a little bit, John, a little bit over 1,000 barrels a day of net oil production and a little bit more on the BOEs. But we just added it to the guidance going to the back half of the year.

Thank you. Our next question comes from Philip Jungworth of BMO. Your line is now open.

Wondering how you're viewing the cost of capital advantage right now for Viper versus Spang and how this shapes capital allocation decisions at the parent level. Looks like based on the decks, both stocks are yielding around 10% free cash right now at 70%, but I know you guys look at it in a lot more detail.

Yes, I mean, listen, think there's some technical things going on at Viper right now. We're stuck trying to get a public merger closed and that limits some of the things we can do in terms of repurchases, but also I think brings in a different kind of investor for the period of time between sign and close. I think I look forward to the window opening at the Viper level and being able to repurchase some shares aggressively as I think it is a very unique investment in the space. Also, another thing I'll note from a debt cost capital perspective, Viper just did its first investment grade deal that priced basically at or inside some very large peers of ours showing that there is a lot of investor support for that business. But I think there's some things on the equity side that are temporary that need to work themselves out.

Okay, great. And then maybe more from a macro perspective, but can talk about typical cycle times right now in the Permian, just considering efficiency gains, larger pad sizes, longer laterals? We're really just trying to understand how long it takes to start to see the production impact from some of the reduced activity, rig and frac that we've seen in the basin.

Yeah, mean if you think about kind of you could look at slide nine in our deck actually and we highlight some of the average wells per section from ourselves and some peers. And if you look at kind of 15 to 25 ish wells a section, call it 20 on average, ten days a well, you're looking at two hundred days of drilling time to cycle off that pad. Somewhere in the neighborhood of six to nine months is a typical pad development or DSU development that may be broken down into multiple pads. So it's really the projects are not as short cycle as I think they're often referred to as because you know, to properly develop the whole DSU, it does take you know, a quite a bit of time and the completion coming in following you know that much lateral footage it can be a month or two of completion timing. So yeah I like to think of these things as kind of twelve month cycles on a full DSU timeframe.

Know, a lot of flexibility in there if you see volatility and bring in rigs at certain times or factories at certain times, but these are not a short cycle as I think we regard them in the public markets.

Yeah, but I think from a macro perspective, you can't take 60 rigs out of the Permian in three months and 20 to 30 frac spreads out of the Permian in three months and not see eventually see a production response. So I think we kind of doubled down on our commentary. I think we're going to see U. S. Production roll a bit here at these prices.

It is taking a little bit longer than we all expected, but maybe that was the price reprieve we had in June. But there's just too much activity being taken out of The U. S. Basins.

Thank you. Our next question comes from Scott Gruger of Citigroup. Your line is now open.

I had a question on your excess DUC balance. How big would that be at the end of the year? And what's the strategy kind of going into '26 with the excess DUCs? If oil is weak, would you pull it down because there's less incremental spend per well? Or would you like to maintain it for some quick to respond barrels in case oil moves higher?

Yes, good question, Scott. It seems the DUC balance has gotten a little more attention than we expected. Listen, we're completing 500 to five fifty wells a year. It's good to have two fifty to 300 in the hopper, especially with this large pad development waiting for completions. I think we'd be comfortable going as low as high 100s to 200 ducts, but would still like to maintain flexibility in that range.

I think what's happened this year is drilling efficiencies and well costs are very low. And what we decided was, given that we're still definitively in this yellow light analogy. We wanted to maintain that flexibility later through this year. And that, as you mentioned, gives us two options, right? If things are weak, we can slow down a bit.

If things are strong, we can accelerate pretty quickly. So we've built a lot of flexibility into our entire plan, which is why our results are always consistent and best in class. And that's why you expect us to do that. Our investors expect us to do that. So we're going maintain that flexibility later in the year.

There's certainly some drawdown coming in Q3 and Q4, but these drilling guys keep drilling wells in four days. We might not have any DUC drawdown by the end of the year.

I got it. And then on cash taxes, you guys realized a good bit of savings this year following the one big beautiful bill. I think some of that is kind of a makeup in the second half. How do you think about 'twenty six and beyond from a cash tax rate perspective?

Yes, Scott, this is Jerry. 2026, we expect cash tax rate to kind of level out at 18% to 20% of pretax income. When we look at 2025, we're expecting a 15% to 18% cash tax rate down from roughly 19% to 22%. So reduction of roughly 300,000,000 in total, about $200,000,000 of this is one time benefits. Two components of 200,000,000 here in 2025, the vast majority is related to the accelerated recovery of remaining unamortized R and E expenditures that were capitalized over the last three years.

And then the remaining is related to the full expensing of depreciable equipment, primarily related to LWE we acquired earlier this year in the Double Eagle transaction.

Got it. I appreciate the color. Thank you.

Thank you. Our next question is from Betty Jiang of Barclays. Your line is now open.

Hi. Good morning. Thank you for taking my question. I want to ask about the development mix. If I look at the development mix provided in the back of the slide, there's a there's an increase in other zones and also Wolfcamp B, but, yet at the same time, you're able to maintain performance, if not better performance, which is quite impressive.

So how do you see development mix evolving over time? And if you could just talk about what you're seeing in the other zone development performance wise versus the traditional zones? Thanks.

Yeah, Betty, that's a great question. We focused on delineating some of these upside zones over the past couple of years. And on the slide that you're talking about in the back of the deck there, can see sort of that mix changing over time. I would expect that to increase over time as we sort of delineate and rationalize where the highest returning areas are for those zones in the Upper Spraberry and in the Barnett and some of the deeper zones like the Wolfcamp D. So yeah, I would expect that to continue as we progress through the year and then going into 2026.

Yeah, think also on top of that, Endeavor Acreage probably had some better Wolfcamp D than our legacy acreage and probably better overall Wolfcamp B further south in the Midland Basin. So that's driving it a little bit. But as Al mentioned, being able to add these zones into the mix and not see productivity degradation as a company is a very impressive feat.

Yeah, thank you. Thank you for that color. My follow-up is on power. We started to see some gas power deals in the basin. Can you just give us an update on what you're seeing along that front?

Where do you see the value add opportunities for Diamondback?

Yeah, Betty. I mean, I think the two big value this is Jerry. The two big value drivers for Diamondback are one, finding an in basin egress solution for our natural gas molecules, and then two, lowering what we view is probably the most inflationary piece of our cash cost structure on a go forward basis, which is electricity costs that you find within LOE. So I think when you PV those two items, that's where you're seeing the greatest benefit to Diamondback. If we could lock in a behind the meter solution here for power gen, we're not going to go out and build anything on spec here.

We've continued to look at various opportunities on potentially advancing power gen within the basin. It's just taken a little longer and I think there's going to be opportunities over the next five to ten years. We're just being patient.

Yes, I think there's some other little things we can do on our existing asset base if we don't do a large power trade. I mean, just using the example today, right, our NGL yield and gas capture went up in Martin County because the gas plants had a better power solution in place.

So it just shows that there's power issues all throughout the basin with or without hyperscalers or data centers coming into the basin.

Thank you. Our next question is from Derek Whitfield of Texas Capital. Your line is now open.

Yes. There's been a lot of industry discussion, on your comments from the one key reporting cycle, both supportive and non supportive as you've highlighted. How would you characterize the support from your peers out of Basin and the pushback within the basin?

Diamondback Energy (FANG) Q2 2025 Earnings Call Transcript

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