Q1 2025 Earnings Call Transcript

Good day. And thank you for standing by. Welcome to Diamondback Energy First Quarter 2025Earnings Call. [Operator Instructions] Please be advised that today’s conference is being recorded. I would now like to hand the conference over to first speaker today, Adam Lawlis, VP of Investor Relations. Please go ahead.

Thank you, Lawren. Good morning, and welcome to Diamondback Energy's first quarter 2024 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 Travis Stice, Chairman and CEO; Kaes Van't Hof, President; Danny Wesson, COO; and Jere 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 Travis Stice.

Thank you, Adam. I hope everyone has had a chance to review our stockholder letter that was released last night. Most of our commentary today will be found inside that letter. Operator, would you please open the line for questions?

[Operator Instructions] Our first question comes from the line of Neil Mehta with Goldman Sachs and Co

Yes, good morning, Travis, Kaes. And, Travis, congratulations as you position for retirement. And Kaes, congratulations again on taking on the new role. I think some important news this morning around changes in the activity plans and in response to obviously what is a tougher oil macro.

So, Travis, can you spend some time talking about the thought process that went into the decision and how you're thinking about the approach from here?

Sure. Neil, our job is to allocate capital and allocate capital for the most profit we can for the shareholders who own the company. Part of our role is we have to have a view of the macro as we allocate capital. And the current view of the macro is certainly challenging at best.

Over the weekend, OPEC made the decision to put an extra million barrels a day on the market in what's already an oversupplied world. And we still are looking at headwinds with what we're seeing as slowing economies around the world, which obviously has a re-through to demand. So, what we tried to put together was a response to those kind of macro conditions, which by taking $400 million out of our capital budget and three drilling rigs and one frac spread allowed us to maximize the CapEx reduction while minimizing volume impact. And at the same token, provide us a runway for maximum flexibilities to respond in either direction in the future quarters as this evolving supply demand imbalance works its way through the system.

So that's sort of the background of what we talked to the board about well before Saturday's decision by OPEC. And again, it stems to how can we create the most value when we allocate capital? And when you look at what we've done with this announcement, we've actually made our program more capital efficient by spending less dollars this year.

Yes, Travis, the follow-up on that is we've certainly reduced your cash capex by $400 million. The impact on production is not that significant, at least for 2025. And so, is that a function of the delay between changes in activity and in production, or is that you guys were just really tracking well in terms of your productivity to start the year?

Yes, Neil, let me give you some color on that because I think it's important, right? On the outside, it looks like a 1% hit to production, but if you just look at Q2, peak to trough, we're going to probably be down 20,000 net barrels of oil a day, which on a gross basis is close to 30. So, we had a great April. Things were humming along. We were well over 500,000 net barrels of oil a day.

Obviously, now hitting the brakes a little bit with the reduction in the frac crews. And so, if you think about it, we're about 475,000 barrels a day net Q1. Q2 guide around numbers is about 495. And then we're going to decline off a bit into Q3 down to about 485. And at that point, in today's market, hold that flat. So, on the outside, it looks like a flattish program, but this is why we've kind of been saying that we think gross oil production is coming down in the Permian in the U.S. You just look at ours, for example, going from five frac crews down to four is going to be a 30,000 barrel a day impact in just a quarter.

Our next question comes from the line of Scott Hanold with RBC Capital Markets.

Yes, thanks. And Travis, again, congrats too on your next stage. And look, I would say it's unfortunate it has to be on a bad macro note, but I think it’s a testament to what you've created that Diamondback able to kind of manage this pretty well.

Thanks.

My first question is, you're welcome. My first question is just your broad view of the oil macro. I thought it was pretty interesting in your investor letter how you thought the U.S. oil production was ready to roll over. And obviously you all have some pretty good eyes and feelers out on the ground.

Can you give us a sense of what you're seeing real time in the Permian Basin and other places and your view on maybe where oil production goes from here. And it's more of a U.S. perspective versus Diamondback one.

Sure. Well, certainly as the Permian Basin goes, U.S. production is going to follow that. And at roughly 6 million barrels of oil a day, we've got a base decline that we have to offset every year of about 2.5 million barrels a day. And it doesn't take much capital to come out of the equation for that base decline to really be seen in production.

And so you can apply that also to the 13 million barrels a day that the U.S. is producing. That's roughly 4.5 or 5 million barrels a day of production that has to be replaced. So I think as capital continues to come out of the investment equation, this decline that we're on is really going to be magnified. And because we are in the more mature stage of the development, this is not one of the types of declines that can be offset by improved efficiencies, although we highlighted continued efficiency gains at the Diamondback level in the quarterly results, but we're picking pennies up now.

And when we were going through this earlier in our history, probably most recently, 2014 and early 2015, we were able to pick up dimes and quarters back then. And it's just where we are in the maturation cycle of depleting these resources that I think you're going to see a really remarkable response on this base decline that's part of the equation.

Yes, and Scott, we've been kind of well-trained in shale, right? This is the fourth time we've had to do this in 10 years, the worst being five years ago and you saw how quickly shale responded. I think the only thing I would add to Travis' comments is the operators that we talk to in the field that work in Midland are right now pushing everything to the right, right? Every little five to eight well program that was going to get drilled is now going to get drilled and probably not completed or drilled later.

And so all those little anecdotes start to add up and you add that into what the companies like Diamondback are doing and that starts to add up pretty quickly. So I think for us, let's get this over with and move forward. Because the other side of this is going to be great for those that are left and it's going to be a great day for Diamondback shareholders.

And you know the comment I made, Scott, on a tipping point in U.S. production, it just depends on how low the oil price goes and how long it lasts. But the scenario is with this base decline that's so extreme is that the amount of capital required to get back to 13 million barrels a day or 6 million barrels a day in the Permian might be an untenable list for the business model that we've put in place where we're returning so much back to our investors that own the company. So that's sort of the final analysis is how low do we get and then what is the reinvestment rate going to be required to get production back up or to get it to start growing again?

Yes, I appreciate the commentary. It definitely feels like it's a have and have not situation. Kaes, Look, you gave a little bit of color on 2H this year and you kind of mentioned in your brief comments just a while ago, it's time to get over this and move forward. As Diamondback thinks about moving forward in 2026, what is it going to take for you guys to move into maintenance mode?

And could you just give a little color on the setup for 2026, considering obviously we're declining and flattening out in the back half of the year?

Yes, that's a good question, Scott. I think the key point for us is that we're not sacrificing anything in 2026 today. We expect to run four crews here for probably the next three months, depending on where prices go. If things get worse, we could go lower.

But basically, the plan points to us bringing back a fifth crew and leveling off at 485,000 barrels of oil a day in Q4. We'll still end the year with more DUCs than we've ever had and more flexibility than we've ever had to increase production in 2026, should prices respond. In my mind, that's a $65, $70 plus world where OPEC's capacity is lower and we have a healthier macro. So I'm open for that day. We'd like to get back to that 500,000 barrels of oil a day net plus plan, but it seems like it's a long way away today with the next couple quarters we have.

I think, Scott, just to finish this commentary, I think our shareholders are lucky that Diamondback has such a long inventory. Because while this base decline that I talked about at the macro will present itself for Diamondback as well, and Kaes gave you some very specific numbers for that, the breadth and depth of our inventory allows us to be more insulated from that than other investment opportunities where the inventory is a lot shorter or shorter and of less quality. So I hope that makes sense, but that's kind of how we think about 2026 and 2027.

Our next question comes from the line of David Deckelbaum with TD Security.

Thanks for the time, guys, and Travis, thanks for your candid thoughts in the letter. Good luck to everyone in the roles ahead. Maybe, Kaes, you could follow up a bit, or anyone, perhaps Danny, just talking about sort of the optimal DUC load. Obviously, you elected to drop the rigs and not build further DUCs ducks with the one-frac crew coming down.

Sounds like net-net this plan you're drawing down, perhaps, for building 20 fewer DUCs this year going into next year. How do we think about the variables for maybe keeping those rigs and building a DUC backlog in the context of what the right amount of DUC inventory level is for you going into the next couple of years, or is it more of a function of where you expect drilling rig rates to be coming down in the ensuing quarters?

Yes, I mean, look, we're carrying probably the largest DUC backlog in North America right now, and so there's not a world where we're looking at building DUCs, gross DUCs, the top line level. So in the new plan, we're drawing down less DUCs than we were in the original plan. I think probably a rule of thumb is for every frac crew you have running, you need 1.5 to 2 pads of DUC inventory behind, ahead of those pads, or ahead of those crews. If we're going to run five crews, you got to have 10 pad-ish worth of DUC backlog, and call it 8 to 12 wells of pad.

So that kind of gets you to a comfortable DUC backlog inventory for a run rate. We're probably sitting at the end of this year another 100 wells above that number, depending on what prices do in the back half of this year.

Yes, David, we put the comment in our letter that traditionally we would build more DUCs in this environment, but our largest input cost on drilling wells, so let's just say that drilling a well costs $200 a foot, about $2 million. The cost of casing is $650,000 a well now, and that is up 12% quarter-over-quarter due to tariff impacts. So we think that the demand side, as the rate count reduces, steel prices come back down, and we can look at logically bringing some rates back to build DUCs if costs are cheap, but that capital allocation decision today tells us drop the rigs, buy back stock.

Appreciate the color. Then maybe just as a follow-up, just given the environment we're in now, have your expectations changed with the ability to execute on some of the non-operated or non-core sales or the anticipated water infrastructure sale to Deep Blue?

Yes, Deep Blue obviously is essentially a subsidiary of ours. We own 30% of it. We think the EDS, which is the Endeavor water system, logically belongs in Deep Blue. It makes that business the largest water handler in the Midland Basin, and it seems that water has started to get a lot more attention in the public market, so I don't see that sale or deal being pushed too far to the right just because we want to get those two businesses integrated and ready for what's next.

Outside of that, we obviously participated a little bit in the sale of Bangle, the NGL pipeline, to MPLX. That should close in July, and the last big piece of our equity method investments is the EPIC pipeline, which we own 27.5% of, I think that probably is a slower process today than it was three months ago, but I think lessons learned from past down cycles is that we don't have to force asset sales. We can be patient. I think we're going to get a couple wins on the board, but we don't have to hit a specific number by a specific period of time because we think the market is going to recover, and the balance sheet is strong, and we can be patient.

Our next question comes from the line of John Freeman with Raymond James.

Good morning, and congratulations again, Travis, on a fantastic career. I want to follow up on some of the prior commentary, and again, really appreciate the leadership that you all are showing with this meaningful reduction in activity, both in the shareholder letter and then in those comments here earlier in the call, you talked about that $65, $70 kind of oil price world where you'd look to maybe put your foot back on the accelerator. And I just want to kind of dig it out a little bit more. So should we think of it as even if your cost structure was to continue to move lower due to service costs, efficiencies, whatever, and returns continue to improve, you all would still probably wait until you're in a $65, $70 world before you'd want to put your foot on the accelerator.

Am I thinking about that right?

Yes, that's right, John. I just think we want to be patient. I think there's a lot of uncertainty on both the demand and the supply side. In our mind, the supply side is going to figure itself out pretty quickly here, but demand obviously is something I'm not an expert in.

We're experts in US shale and US supply and what we're seeing in the field. And in my mind, a $70 plus crude environment is a relatively healthy environment, and that would be an appropriate time to bring some capital back into the equation.

Got it, and then y'all did highlight what you've seen in terms of the impact on kind of your steel-related products with the tariffs on casing being up 12% since last quarter, but we're able to lower your Midland basin cost per foot guidance yet again, and just hoping you could maybe speak to kind of the puts and takes that are allowing you to kind of offset what you're seeing on the casing side.

Yes, I mean, first of all, the team's had an incredible first quarter. I mean, we put some highlights in the deck. Under eight days average per well on 120 plus wells is a pretty impressive feat. So, I mean, I think we're on the lower end of our efficiencies, which is good.

And I think, unfortunately, the rest of that reduction is likely to come from the service environment here with rigs coming down and fractures coming down, but I'll let Danny apply it on what he's seeing real time.

Yes, I think we put some details out there around casing and the 10% increase is about $6 a foot or so on the drilling portion of the well. So it's really not a huge number. And like Kaes said, the execution from the drilling and completion teams is really driving the cost beat. And I think we anticipate that there's going to be lower activity in the basin, which usually leads to a lower service pricing.

There's a lot of volatility out there right now with input costs and tariffs, but we do expect that activity's going to come out of this basin in a meaningful way and that should have a triple down effect to pricing.

Our next question comes from the line of Arun Jayaram with JPMorgan Securities, LLC.

Yes, good morning, gentlemen. Travis, Kaes, you highlighted how the trajectory of oil volumes could trend, call it to 485 in the second half of ‘25. Danny mentioned you'll have kind of a really high DUC backlog kind of going into this period. I was just wondering if you could help us think about 2026 CapEx to keep that 485 flat, all else being equal, would a 900 million per quarter run rate seem reasonable based on what we know today?

Yes, Arun, I mean, I think that's reasonable. I hope that doesn't end up being the plan, but clearly with service costs coming down, efficiency's high, a little lower production base, I think that's logical. We also had a few more one-time items in the budget this year that will be reduced next year. So I think that's a logical baseline.

Again, I'm kind of hoping that the market recovers quickly here and we can be talking about 500 plus thousand barrels of oil a day next year. But I think we got to wait a few months here to see where things settle out.

Understood, that's helpful. Maybe my follow-up is in the shareholder letter, Travis, you mentioned how Diamondback will allocate a higher mix of free cash flow to repurchases if the volatility continues. I was wondering how you and Kaes think about kind of balancing leverage, reducing leverage versus buybacks and perhaps tell us how you think about, give us a sense of what type of mix could we see towards the return of free cash flow to shareholders versus the 50-50 kind of overall guidance?

Yes, listen, I think obviously improving the balance sheet is important, but I think that the best, the smartest capital allocation decision today is to repurchase shares. I think generally around round numbers probably allocate 25% to 30% of free cash flow to paying down debt. You saw that we repurchased some of our longer-dated notes at well below par. Those notes had come down in price due to the 30-year Treasury blowing out, so we took advantage of that.

I think you can expect to see more things like that on the debt side. I think some of our non-core asset sales coming in should reduce our term loan we put in place for a two-year term loan that we put in place for the Double Eagle closing. And then you get to the other 75% of free cash flow or 70% of free cash flow, and in our minds that needs to be allocated to 100% repurchases and the base dividend. I think obviously the variable dividend is out the window at these prices, and repurchasing shares grows per share well volumes and per share cash flow and free cash flow when the market recovers.

Great. Travis, best of wishes to you. If you do write the book, I look forward to the chapter on how you got the Endeavor deal with Kaes to the finish line.

Our next question comes from the Bob Brackett with Bernstein Research.

Hi. Good morning. If I think about the capital reductions, you guys get to choose which crews you keep and you guys get to choose which locations you drill. To what degree are those real levers where you're making choices, or are those most of the crews are about the same and most of the locations are about the same?

Yes. I mean, I think from an execution standpoint, most of our resources on the service side are pretty well in line with each other and so there's not a lot of high grading to occur and slowing down the activity. It really becomes a commercial decision and discussions with our business partners on who's going to work with us as activity comes down. And on the project side of things, our job is to always try to allocate capital to the best projects.

And I think if you look at the consistency of our program over the past few years, it kind of speaks to the consistency of the projects we're doing. So, again, there's not a whole lot of high grading to be done in the projects themselves. I think you will see us probably prioritize the projects where Viper has interest so we can continue to support Viper in that regard. But I don't think there's material high grading to be done in the pads or resource allocation.

And that's, Bob, that's a blessing of having an outstanding inventory as well, too. We're still allocating wells with very, very small range of outcomes because they're at the -- they're the top quartile of our inventory. And as Danny pointed out, we've been doing that for several years now. So, again, durability of inventory matters when you go into one of these cycles.

And that's what our shareholders are lucky to have with Diamondback.

Yes, that's very clear. Quick follow-up. At your run rate, you're going to get through the remainder of your share buyback authorization. That's a trivial exercise to top that up when you need to.

Yes, we thought about looking at it this quarter, but felt that we want to get through another quarter. There's probably enough noise with all the changes in the capital plan this quarter. And we'll discuss it with the board. But I think the board is certainly behind management in believing that buybacks are the right thing at these levels.

And we expect to increase it when we get closer to the authorization.

Our next question comes from the line of Scott Gruber with Citigroup.

Yes, good morning. I found the comment in the shareholder letter about geologic headwinds outpacing technology and process efficiency gains interesting. I assume that's a broader industry comment. So, curious do you see the technology and process efficiency gains slowing from here or are the geologic headwinds becoming more severe?

Just some more color behind that comment and kind of what's changing on the margins.

Yes, I think that's a natural evolution of a maturing basin. I mean, we've been now exploiting this shale resource in the Permian Basin for 15 years. And we still expect some R&D and some really innovative breakthroughs coming. But in a general sense, as dollars get allocated to lower and lower quality inventory and the longer, you're in the game, if you're focused on excellence and execution, your natural decline will be impacted where you're making less improvements than you did early on in the development of that asset.

So, it's more of a general comment that from my experience, we've seen play out in the Eagle Ford to Bakken, and some of these other in the Barnett Shale in the early days as you continue to deplete these reservoirs.

Yes, I got it. And then coming back to the cost saving side of things as you selected which rigs and frac crews were retained, were you able to capture some immediate savings from those that -- the crews that you retained? Or are you seeing service companies more willing to do blends and extends with any contracts in place? I'm just curious about kind of how quickly you're able to secure some savings from your service providers.

Well, I'll give a high level comment. I think for us we've always tried to have very short-term contracts so that we can have these conversations quickly both on the completion side and the drilling side. I think it's kind of a different story on both sides. On the drilling side, we use a multitude of contractors and those conversations are probably more fluid.

On the completion side, we've always been big fans of the Halliburton, Zeus E-fleets. We run four of those today. And so I think -- I truly think that relationship is more of a business partner-type relationship where we're going to get through it together. But I'll let Danny give some details.

Yes, I think Kaes's kind of hit the nail on the head. We are constantly in commercial negotiations with our service providers based on market conditions and what we're seeing in the pricing market and what kind of service quality we're receiving from them. And so when we lower activity internally, it's a discussion with all of them on who's going to be willing to work with us. And as the market softens more broadly, we'll continue to have those conversations.

I think Kaes said before, every day is RFQ day at Diamondback. We continue to just keep our ear to the ground on where the service market is and want to recognize the best commercial value for our shareholders and the discussion around our procurement process.

Our next question comes from the line of Phillip J Jungwirth with BMO.

Thanks. Good morning, guys. On the macro commentary around U.S. oil production, one of the things that analysts often underappreciate in a downturn is just the industry's ability to high-grade capital. And this can include coring up to more tier one or two acreage, private activity getting cut at a faster rate, or just targeting more primary zones or up spacing.

So wondering how you see that high-grading ability today for the Permian more broadly, and is there any reason, as shale more mature, to think that this could be less upside to capital efficiency for the industry than we've seen in prior downturns?

Yes. Kind of relative to my prior comment about we're in the later stage of development of these resources. I would argue that most of the high-grading has been occurring over the last three to four years, as all of these zones, particularly the Permian, have been well-defined, and the focus has been on efficient execution. So if someone hasn't been allocating capital to their very, very best projects, well, then I guess they can take this opportunity to do that.

But our reconnaissance and monitoring of the industry says that everyone's trying to drill their best stuff first, and that's the way we think it's going to play out in the future.

Yes, I think if you look at this, the market today just generally balance sheets are healthier, free cash flow is being generated, and so what we're trying to say is I think in the past, the decision to cut capital was to protect the balance sheet for a lot of, particularly when there's a multitude of smit caps and mid-caps that are no longer here, and now, today, I think decisions are being made to preserve precious inventory, because inventory is scarce, I think the plays are well-defined, there hasn't been -- there's little things going on around the basin, like the Dean play in Dawson County, Middle Spraberry down in Ector County, things that are adding resource, but not nearly to the level of what we saw in the past down cycles, so I think decisions to cut capital and defer churn lines or defer inventory is being made to preserve inventory life, rather than protect balance sheets.

Great, thanks, and there's been a number of gas pipeline projects that have reached FID to move gas out of the Permian and even further along the Gulf Coast, what's your appetite currently for incremental FT on gas? It looks like Waha tightens materially in 2027, you also have power opportunities, and how is that influenced by any expectations around future Permian oil growth?

Yes, sadly, the gas growth is going to continue out of the basin in our models, so we're going to keep putting more FT on the balance sheet. I think we have a lot of confidence in what we've committed to, and we have about 750 million a day total commitments that will be in place by the end of ‘26. We are reserving some space for power generation should that come to fruition in the basin, but in general, I think you can expect us to continue to support new pipelines out of the basin. Even -- there's even some talk of pipelines going west, we'll see if that happens, but we want to have a diverse set of marketing arrangements on the gas side, and I think we generally believe in the long-term gas thesis, and so therefore should make some more money off of our gas.

Our next question comes from the line of Derrick Whitfield with Texas Capital.

Good morning, all. I echo everyone's congrats and also appreciate your capital discipline leadership as well. With my first question, I'd like to use your driving analogy from the investor letter and ask, what price do you see as the next natural tipping point in activity or the point where you firmly press on the brakes, assuming current service costs?

Yes, we like that analogy too, but I think red is probably something with a four in front of it, and I would say yellow is something with a five in front of it, and green needs to be somewhere in the mid to high 60s with a path to 70 to accelerate through that green light.

And then thinking about your D&C activity or non-D&C activity, could you offer some perspective on the amount of non-D&C capital you could take out of the business if we were to assume a more protracted period of lower prices?

We lowered our non-D&C budget by about $50 million at the midpoint. We do think if we ever get our Midstream business merge into Deep Blue, that would take another $50 million to $60 million out of our non-D&C budget. Yes, but there's some pretty interesting things we're doing on the non-D&C side. Some of these capital workovers that we've put in the budget are starting to pay dividend and help improve the base decline.

So I think those projects stay in there, but as the total amount of wells turned in line goes down, the associated infrastructure also goes down or gets pushed to the right. So, I think we had a good cut for what we said today, but I mentioned earlier in the call that there are some one-time things in the budget this year that are probably coming out next year as well. So we always try to get that non-D&C budget number down, and I think it's headed that way, even in a flat environment next year.

Our next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.

Hi. Good morning, Travis and Kaes. In past cycles, Diamondback has been a consolidator and has taken advantage of M&A opportunities taking back to the COVID years. Is that different this time?

I know that Double Eagle was the last coveted undeveloped position in the Midland Basin, but are there other ways that you guys are kind of thinking about taking advantage of industry distress on the M&A front?

Yes, Kevin, I mean, that's a good question. We've obviously been very busy over the last year and a half with Endeavor and Double Eagle. Those are two premier assets that in our mind wouldn't be available in a more volatile environment. So, we're fortunate that we took advantage and consolidated those two when we could.

I think we're in the period right now where there's so much noise and volatility that not a lot gets done. I think we have to be very patient on our side. I think we're very focused on reducing our share count and getting our debt paid down a little bit. So, anything that we would look at would have to be extremely, extremely cheap.

And I just don't think we're there yet today.

Our next question comes from the line of Charles Meade with Johnson Rice.

Good morning, Travis, Kaes and Danny. Travis, you made up, I'm not sure how much you intended to, but I think you made a big splash with your shareholder letter. And I'm curious it's titled Letter to Shareholders, but are there other audiences you had in mind as you penned that letter? And I'm thinking it could be the Midland community more broadly or the Permian-based community, Washington policymakers, or even OPEC, perhaps.

Yes, Charles, the intent of that letter is for our stockholders, and they're the ones that own the company and are making future investment decisions based on the way management allocates capital. So we always focus that letter on as if they are our only audience. But we also recognize that this is a public document, and based on some of the feedback we've seen overnight, it's reasonable to expect others have read that letter besides just our stockholders. So I wouldn't necessarily intimate that there was any other effort out there besides communicating to our stockholders, but we weren't -- we're at least aware that this was a message that was going to be read by more than just our stockholders.

Got it. It sounds like you've seen a lot of messages already this morning. Travis, I want to go back to Scott Gruber's question, just push a little bit further on the rate of change. You talked about the headwinds, the geological headwinds, and the tailwinds of more efficiencies.

You talked about the rate of change on the efficiencies. You said we were picking up quarters, dimes, and nickels, and now we're picking up pennies on the efficiency side. What does the rate of change feel like on the geologic headwind side? Is it kind of a persistent headwind that's just now kind of balanced out versus the pennies, or is it picking up?

Yes, I mean, I think we think it's picking up. These plays are very well defined now, right? I mean, I think if you look at past down cycles, we've always learned something in the down cycle, whether it's a new completion design, co-development, spacing studies. So, we're certainly not going to let this slowdown go to waste, and we're going to learn something coming out of it.

I don't know what it is today, but the basin has been well tested by 300 plus rigs, used to be 600 plus rigs over the last 10 years. So, I think what we're trying to say is we're drilling average wells, average 10,000 foot wells in eight days. There's not three, four more days to come out of those on average, and therefore, the cost side of the equation is going to be harder to get down by 10% or 20%, and this is why we've been so aggressive on building our resource base and our inventory, because we feel like from a scale perspective, the vast majority of the inventory in the basin has been well defined.

Our next question comes from the line of Paul Cheng with Scotiabank.

Thank you. Hey, good morning, guys. Charles or Kaes, I'm just curious that, I mean, based on your comment, is the business model need to be changed? I mean, historically, that the company has growth acquisition and have a growth bias, but if you're already consolidating most of the best assets, does that mean that you have to go outside the Permian or that the entire business model perhaps that needs to be changed going forward?

Yes, Paul, I don't think there's a need to go outside the Permian, because I don't see any other basin, and certainly in the U.S., that has the inventory quality and depth of the Permian. We have a big motto internally, and it's know, what you don't know, and we're really, really good at the Permian Basin. We're really, really good at drilling wells in the Permian Basin, and that's our expertise, so I don't think we need to go outside the basin. On the business model comment, I think we've grown the business through acquisition.

We're obviously extremely large now. We've always focused on per share metrics. I think there's still a world where we grow per share metrics significantly with our current asset base, and while it's a long way off from today, I do think there's going to be a time period where significant organic growth is going to be required from someone like Diamondback to fill the gap in U.S. supply that probably struggles over the next 5 to 10 years, and that, in our mind, is what we've been positioning the company for long term for that proverbial pot of gold on the end of the rainbow, and we're last man standing in the basin drilling high return wells at high oil prices.

Excellent. The second question is that, just curious, is that something happened in the first quarter in the NGL and natural gas production? Seems like dropping far more than that tight curve we have suggested.

Yes. We had some adjustments that we made to some contracts that went from fixed fee to POP, percent of proceeds, and we think that reverses a bit in Q2, so I think you can run essentially 55% oil as your baseline for us going forward.

Our next question comes from the line of Leo Mariano with ROTH.

I just wanted to ask about a couple of these cost items. Certainly in your guidance, it looks like LOE came down a little bit, but transportation rose a little bit. Not sure if that's related to, perhaps, some of the adjustments you just talked about on the gas and NGL side, but just looking for a little bit of color there.

Yes, I'll take GPT quickly and give LOE to Danny, but GPT, basically, we decided to take more molecules in kind on the gas side, so GPT goes up, but our gas realizations as a percent of NYMEX should go up a little bit, so that's the shift there, and I'll let Danny talk about the decrease in LOE.

Yes, on the LOE side, really, we had a little bit of one-time issue or noise around the Endeavor closed with regards to some of the water business, and we anticipate that there's a little conservatism based around the close, and we anticipate that LOE will come up from the 1Q number, but we do like a little lower number than we had originally planned for the year, and so we like our forward guide for LOE and know that it's going to come up from 1Q, but will be lower than we originally planned, which is interesting.

I wanted to just ask a little bit more kind of around the buyback here, so you guys were kind of good enough to kind of articulate your sort of red light, yellow light, kind of green light sort of activity levels with some good oil price kind of commentary there. Should we really kind of think about the buyback kind of being sort of in the opposite direction, so when you guys are kind of green light and we're 65 plus oil approaching 70, should we just naturally assume that the buyback comes down a little bit, or obviously in the red light situation, it's where you guys kind of push the pedal a little bit more.

Is that generally how you're kind of thinking about the framework?

Yes, that's right. I think that's a great way to think about it, and it's as we said in the letter, in our mind, it's the first test of our new business model of high free cash generation, high return of capital, and making the right decision to cut drilling cutbacks in exchange for buying back shares at these levels. So again, I think in today's environment, it makes sense to pay down, continue to pay down some debt, but allocate more capital to the buyback. Again, we see our dividend as a fixed obligation, and every million shares we get rid of in the market is a $4 million reduction annually to our dividend payment.

So that, in our mind, translates to about a 3.5% to 4% dividend yield, depending on the day, and that's a fixed obligation that goes away.

Our next question comes from the line of Kalei Akamine with Bank of America.

Good morning, guys. I've got a couple here. Maybe first, can you talk about frac efficiency? I think on a prior call, you guys mentioned that you were doing 100 per year, kind of up from 80, and you've highlighted visibility on call it 120. Now, if all four fleets are doing 120, then I think you're replacing a good chunk of one fleet.

So can you just update us on where the progress is with respect to that goal? And if you kind of get these efficiencies before oil gets back to 65, I guess there wouldn't be much to add back.

Yes, I mean, look, we always look at what is the well count required to execute our plan, but I certainly think the completions team has done a fantastic job of driving execution and efficiencies. I think we highlighted in the release that they're completing mid-3,000 feet per day on average, but we've certainly seen them touch well above 4,000 feet per day on a pad. And so we know that's possible and we know that number, 100 to 120 wells a year per crew is certainly achievable. It's just doing the things we need to do from a well work instruction, from a pad configuration and water infrastructure standpoint to be able to execute to that level on a programmatic basis.

And I don't think we're that far away from being able to achieve that. And certainly once we do, it just means less fleets to achieve our total well count for the program.

Thanks for that. The second one is on the ‘25 capital range. It's kind of been lowered here, but it's not been narrowed. It's still a $400 million spread between the low and the high end. Can you help us understand the path to the lower number at 3.4, i.e. what needs to go right to hit that number?

I don't think it's going to be, it wouldn't necessarily be a positive thing for the macro if we got to the low end, right? At 3.4, that's kind of the, use the analogy, the red light scenario, sub 50 probably dropping another crew. I do think the midpoint at today's service prices is kind of the world where we level off at 485,000 barrels of oil a day in Q3 and bring back a fifth crew to stay there in Q4. So that's kind of midpoint high end feels far away today, but there is a world where prices do snap back and we want to get back to our 500,000 barrels of oil a day run rate. And while that seems far away today, it would be a good problem to have.

Our next question comes from the line of Doug Leggett with Wolf Research.

Hey guys, thanks for getting me on. Kaes and Travis, again, I'll add my congrats to both you guys and I look forward to seeing what's next for you both. I want to ask a question about the capital efficiency because you made quite a big deal about that in your presentation deck and I kind of want to walk you through the math very quickly. You've cut $400 million off your capital and you've lost 5 million barrels for the year.

So I'm trying to understand what's trade-off to decide to add that capital back? Because it seems to me that you get higher free cash flow in the current plan than you would if you added $400 million back to get 5 million barrels. So how do you think about sustaining capital and what's your optimization decision around that? I've got a quick follow-up, please.

Yes. I think, Doug, the nuance there is the path of the production throughout the year, right? We were well above 500,000 barrels of oil a day net in April declining off and so you put this big gap in activity in the middle of the year that's really not a full year run rate number. So I think it comes down to what level of production are you sustaining and how much capital does it take?

I still think that if we were at 500,000 barrels of oil a day run rate, we're closer to a $1 billion a quarter of CapEx but down to 485, 480 it's closer to this 900 a quarter with two quarters below 900 in Q2 and Q3. So I think there's just a little nuance here with how quickly things are changing and how quickly production is heading down for a couple quarters while then stabilizing in Q4.

Got it. That's really helpful. My follow-up is I think you're moving the oil market today, frankly, and I wonder if you could share, maybe Travis asked you to elaborate a little bit on some of the comments you made. You basically called a top on US oil production of shale anyway.

What is your non-operated insight to what others are doing? And I'm just curious if you could maybe put some numbers as to how you see the sensitivity of rig decline relative to the rollover in production, Any color you can add from the work you've done would be helpful.

Yes, Doug, I think we really focus on anecdotes, right? We know a lot of people in the business. We know a lot of people on both the public and the private side. And Midland's a, while we're a large public company based in Midland, we know everybody that's picking up a rig to go drill three Barnett wells or three Dean wells or this unit they picked up in the Delaware basin.

And every single conversation I've had with those types of operators is that this oil price doesn't work and they're going to be very, very, and then traditionally those are acreage positions that have higher breakeven, right? So all of that is getting pushed to the right. Very clearly other basins that don't have sub 40 breakeven inventory like the Permian are having these same discussions. And so our kind of commentary is that the marginal barrel in the U.S. is just not being produced today.

And we're seeing it already in terms of frac activity, frac count even some pipeline scrapes are down. You look at Midland Houston spreads those have narrowed. So I just think the marginal barrel is being pushed to the right. Again, we don't have a crystal ball in the rest of the world, but we have a very good view of what the U.S. looks like.

And right now that's a business that's slowing dramatically and likely declining in terms of production.

Thank you. I'm showing no further questions at this time. I would now like to turn it back to Travis Stice for closing remarks.

Thank you, guys for listening in today and for your questions. And thanks for your support over these last, I think, 15 years as well. If y'all have any questions, you know how to get a hold of us. Y'all have a great day. God bless you.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.