Good day, and thank you for standing by. Welcome to the Diamondback Energy First Quarter 2024 Earnings Conference Call. Please be advised that today's conference is being recorded. I would now like to hand the conference over to Adam Lawlis, VP of Investor Relations. Please go ahead.

Thanks, Jose. 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 and CFO; and Danny Wesson, COO. 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 reconciliation of 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, and I appreciate everyone joining again this morning. I hope you continue to find the stockholders' letter that we issued last night an efficient way to communicate. We spend a lot of time putting that letter together, and there's a lot of material in that. So operator, with that as a brief introduction, would you please open the line for questions?

Our first question comes from Neil Mehta of Goldman Sachs.

A lot of good stuff in the letter. Two quick follow-ups. First, just on natural gas. You spent a lot of time talking about some of the steps you've taken to mitigate some of the softness that we're seeing in Waha pricing. Can you spend more time on that? And as it relates to that, how do you think about the timing of debottlenecking Permian gas?

From a macro perspective, we've been clear that we will continue to need pipelines constructed every 12 to 18 months in the Permian to manage the associated gas that accompanies the 6 million barrels a day that we produce. Currently, natural gas is almost treated as a waste product, but we have it. When Matterhorn starts operations this fall, we expect some changes in that dynamic. Kaes, could you provide an overview of our efforts regarding the rest of the gas?

Yes, Neil, I mean, this will be long term, we want to be able to contribute to more pipes. We've done that in the last couple of years with commitments on Whistler and Matterhorn. We've relinquished taking kind rights in other areas to commit to other pipes that are being built. As Travis said, we just need to do more. And I think with our size and scale and balance sheet, we should be taking a leadership position on these new pipes. We've talked to a lot of people that are working on them today, and it seems that there are projects in the works that will help alleviate the bottleneck past the end of this year. But as we control or have the ability to control more gas flows on our side, as contracts roll off, et cetera, we're going to keep pushing on more pipes and more markets out of this basin.

Yes. And then the second is capital efficiency. You talked about the 10% improvement that you're expecting per lateral foot. So just talk about what you're seeing real-time in terms of deflation. And then also, what are the next steps in terms of driving your cost structure lower as we think about the efficiency of the fleet?

I believe the ongoing deflationary pressures in the Permian are largely due to the decrease in both the rig count and the completion crew count. These factors will benefit us as we progress through the rest of this year. Additionally, aside from these deflationary influences, we are continually enhancing our drilling and completion operations. For this quarter, we averaged nearly 13,000 feet, and we are making strides in drilling wells more quickly. Our completion teams are also increasing the number of lateral feet completed within a 24-hour timeframe. We are focused on improving both our capital efficiency and are optimistic about how the remainder of the year is shaping up for us.

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

Travis, you and the team had highlighted up to $550 million of annualized synergy capture in the transaction in the Midland Basin, including a 150-foot decline. And do you see any costs in the Midland Basin to that $600 million to $650 million range? Maybe a follow-up to Neil's question, but where are you seeing kind of leading-edge costs today in the Midland Basin as you continue to push those lateral links a bit longer?

Yes, this is Kaes. I think the combination of those longer laterals, 12,000-plus with some efficiencies on the completion side that we probably weren't expecting going into the year, as well as some softening on the service side makes us feel pretty good that we're in the lower half of that $600 to $650 a foot in the Midland Basin. As you know, 90% of our capital is being allocated to that basin. So with those costs trending in the right direction, I think on a real-time basis, closer to $600 a foot, we feel really good about our plan this year as well as carrying that momentum into a Q4 close. The Endeavor deal and into 2025. Very clearly, we laid out some strong synergy targets and a very strong capital-efficient 2025 plan, and we still feel very confident in that plan.

Great. Kaes, regarding the quarter, how much activity has there been in terms of TILs in the Delaware Basin? Can you share some insights on the Delaware program? I know it represents 10% of the overall program, but what are your thoughts on the Delaware as we look ahead to the latter part of this year and into next year?

Yes. Listen, there's still a place for the Delaware program. There are still some really good projects coming up in Q2. I think we have a project in that Romeo area, Northern East County that's going to be very good. I think generally, with large pad development, you're going to see pockets of development in the Delaware rather than consistent development because we want to go over there and complete multiple wells, multiple pads in a row and keep that capital efficiency high versus the Midland Basin where 3 or 4 simultaneous frac crews are going to be running at all times.

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

Maybe this question is for both of you guys. But considering the positioning a bit early with the debt that you raised earlier this month, now the expectation that the deal will close at the end of the year with Endeavor. You talked about kind of the synergy expectations in the last series of questions. Can you give us an update on how you're thinking about that initial sort of noncore sale asset target and maybe some of the updated timing around those thoughts, considering the market's changed a bit, especially around the cash consideration portion?

Yes. I think what's changed is just timing, right? I think the projects we see as noncore asset sales or the asset sales to subsidiaries we have is still the same. Endeavor has a really good midstream business that would fit well with our midstream joint venture. They have a significant mineral business that I think is going to be a game changer for Viper if those 2 businesses are combined. And our strategy to execute on those trades has not changed. It's just been pushed out to the right. So on top of that, there's an $8 billion cash consideration that continues to be worked down with free cash flow between sign and close. I think that just means we have to pony up less cash at close in Q4. And we raised the money a couple of weeks ago because we were preparing to potentially close the deal as early as today. Unfortunately, the deal has been pushed out due to regulatory review, but we had to be ready to fund the deal, and that's where we were. Fortunately, the bond deal was pretty well-timed. We're actually earning very minimal negative carry on the cash that we have sitting at the banks today, and we'll be ready to use it when we close in a couple of quarters.

Maybe just to follow up a little bit more on just the gas pipeline side. Just for my own edification, just some clarity. Just you highlighted you didn't have any issues with egress. You have Matterhorn coming online in the third quarter. Is there a point as you look forward, where you anticipate egress issues? Or is this more appearing to be just more proactive to get involved with taking on firm capacity in future pipelines? Do you need to take a more active role beyond that?

Yes. Well, I mean, we're facing them right now, egress issues, right, not on the physical side, but it's really on the price side. So I think if we can remove the pricing aspect of pricing modules in Waha versus pricing them further downstream and just paying a fixed fee on the pipe, that to us is a risk mitigation strategy that makes sense for Diamondback shareholders. So I think we see the gas forecast continuing to increase. If you look back at the big public third-party services and what they thought gas production was going to be in 2024, they've all been wrong. So it's always been more gas sooner. And so for us, we need to handle that physically where we can. And with our balance sheet and size and scale, we can sign those 10-year deals because we know we're going to be around to produce for a very, very long time.

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

I'm just going to stick on the gas team as well because it is very topical, but it sounds like, and just correct me if I'm wrong, you guys feel good about your development program on a Diamondback standalone basis as well as with Endeavor with gas capacity, at least for the foreseeable future and just confirm that's correct? And if you could also maybe opine on just broader Permian in general, do you expect other operators to see some physical constraints not being able to get their gas out and potential shut-ins related to that?

Yes, Scott, we're 100% confident in our plan. I think we have a lot of visibility. We have more and more physical space coming our way. Every molecule is moved to date. I don't like the speculation blame game in the Permian about who's going to be able to move or not. I'm focused on Diamondback, and we're going to be in really good shape.

Okay. Fair enough. And then my next question is on stock buybacks. Obviously, it sounds like it's going to be a little bit more tempered until the deal closes with Endeavor, but can you give us your thought process on buybacks post-merger and how you think about the intrinsic value of the combined company? And what mid-cycle price makes sense to underpin that?

Yes. I believe that returning 50% of free cash flow every quarter will enable us to build more cash, pay down debt more quickly, and also make larger investments in buybacks. If we have to distribute 75% of our free cash flow in a single quarter, it restricts our ability to invest in buybacks at optimal times. This flexibility will assist us in that regard. We have been somewhat limited on buybacks since announcing the deal, and I anticipate that situation will remain consistent in the second and third quarters, depending on market conditions. If we observe any weakness in the market, we will act to support the stock. However, in the long term, we aim to make substantial investments in buybacks when the timing is right. I believe we are currently in a mid-cycle price range of $60 to $70. We were stable at $60 for a significant period and are now possibly closer to $70, particularly with gas prices around $2 or $3. With the combined business and what we have with Endeavor, there is considerable inventory and strong net asset value growth, which possibly means a lower combined cost of capital. We feel we can slightly raise our buyback plans, but we will likely proceed with caution until the deal closes.

Yes. Just to clarify a couple of points. Just broadly speaking, how much accretion do you all feel Endeavor added? And can you give us a sense of like when you think about cost of capital, like what were you kind of thinking before when you did intrinsic value? Was it like a 10% kind of flat? Or do you get a little bit more scientific with that?

Yes. We've always been a little higher than 10%. I think in after-tax PV-12 felt like at a mid-cycle price, felt like a very conservative price to buy back shares. And that also makes sure we don't get trapped into a positive feedback loop of buying back shares all the way to the top. So I think an after-tax, 12% rate of return in this business is a really good rate of return at a mid-cycle price, and that keeps you in a good spot through the cycle.

Our next question comes from the line of Roger Read of Wells Fargo Securities.

Yes, I'd like to come back on the efficiencies and lower costs. Obviously, some part of that, as you mentioned, was service competition, rig on rig, crew on crew lowering costs. But if you look at the underlying improvements you cite e-fracs over a diesel frac, kind of where do you think we are in terms of running through continued efficiencies there as we alter the equipment, maybe alter the methods of doing some of the wells and with the danger of crossing the line here to post Endeavor, kind of what you see as maybe a year or 2 out in terms of continued efficiency gains.

Yes. Good question. We are continuing to drive costs out of the business through our operational plan and execution. On the completion side, a lot of that’s going to come in the way of getting any fleets off of generated power and onto some form of grid power where we can recognize a lower energy source cost. We're continuing to try to drive days out of our execution, and we're kind of on the asymptotic slope of those efficiency gains that we are getting to a point where the fixed cost of the wells are a significantly larger portion of the cost of the well than the variable cost. So we're getting to a point where the variable costs that we're going to impact are just minor compared to the larger fixed costs, and to get those large chunks, we're going to have to think about doing things differently as far as the physical plan for the wells and what we are going to consume as part of the fixed cost of the wells.

Roger, I joke with our guys a little bit on the drilling side because they're almost to the point where they're spending more time screwing pipe together and unscrewing pipe together than they are actual rotating hours in the lateral – not quite, but they keep certainly pushing the envelope. And really, if you go back to what we said during the acquisition announcement with the merger announcement with Endeavor, we talked about $150 a foot. $100 of that foot was from simply going to a simultaneous frac and the other $50 a foot was going to clear fluids. And really, that's what we're doing today. So we emphasized at the time that it’s not a big stretch; it's just simply doing what we're doing today on a new set of assets. And in Dan's comments, he's spot on as well.

Got you. So we just need somebody to come up with the next better mousetrap out there for the step functions. I appreciate that.

Listen, Roger, one other comment on that. I mean the guys are so good on the drilling side now. They're measuring how thick the threading is between casing and on the drilling side to say, 'Can I screw that pipe together half a second faster versus what I used to do?' I mean it is down to the absolute second on-site to reduce those variable costs.

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

Just following up on these efficiency drivers. Obviously, in the quarter, the wells that you all completed, the 101 wells, they were right in line on the lateral length of what your guidance was for the full year around that 11,500 feet. But obviously, you all point out the 69 wells that you all drilled in the Midland Basin that were significantly longer than that over $13,000 a foot, obviously, first-class problem given the capital efficiency you're seeing on these longer laterals. But should we still use that full year guide of 11,500-foot average for the year? Is that still applicable? Or should we consider that probably moving up relative to the original guide?

Yes, John. I think in the first quarter, those longer laterals were really just a function of where we were completing the wells that average lateral length of 11,500 is what we expect to see for the rest of the year.

Okay. And then just shifting gears a little bit on the topic of, I'm trying to get a sense of like how much you are able to do sort of in advance of the Endeavor deal closing. And I know that in those initial efficiencies that you all laid out, things like, maybe pricing power supply chain, things like that weren't even necessarily priced into those initial synergies. So I'm trying to get a sense of like how much can you all do in advance in terms of negotiating with some of your service providers in anticipation of sort of a larger combined entity buying in bulk, things like that, like how much of that, if at all, can you do in advance or you just kind of have to sit and kind of wait until the deal closes to kind of get running on that stuff?

Yes, John, we got to operate as separate companies until the deal closes, and those things will come to the benefits of the combined company, but certainly can't influence any outcomes until the deal is closed.

Our next question comes from the line of Neal Dingmann of Truist Securities.

Travis, my question for you is just on the marketing side. You are looking not only from a capital efficiency but it seems like from a takeaway you all continue to get better and better sort of realized margins. I'm just wondering, now with the larger size, or I guess when that closes, what type of benefits will you continue to see on the back end that you've been seeing on the company? Because it seems like noticeable that a lot of your margins and all just on the marketing side continue to improve.

Yes, Neal, I think we won't see much more improvement. For us, it's more about risk aversion and ensuring our barrels and molecules reach different, larger markets downstream. A significant portion of our oil goes to the Gulf Coast in Corpus and is exported, and we also have a considerable amount of oil going to refineries in Houston. We've matured as a company in terms of marketing, and we're very aware of the mistakes made 5, 6, or 7 years ago when the Permian became tight, so we are cautious about repeating those errors. With our size and scale, we'll be contributing to oil pipelines and new gas pipelines as well. We've invested in gatherers, processors, and various midstream projects over the years that have generated returns for our shareholders and provided us commercial protection. I expect this trend to continue as we grow larger.

That Kaes, you're saying you'll continue to contract more of those longer-term marketing contracts then?

Yes. I think our philosophy is to get our barrels to the most liquid, bigger market and very clearly, selling within Midland or in the Midland market has not always been the most beneficial to our shareholders. There are pockets of time when the Midland market is very loose, but there are also periods where it gets very tight. So the way we see this physical marketing protection is a long-term insurance policy to make sure our barrels move to the right market.

Okay. Regarding project size, you all are doing a great job not only with the larger projects, averaging 6 four-well pads, but you also seem to have the flexibility that larger companies often lack for these projects. Will you continue to maintain that flexibility as a standard for your larger projects going forward? Could you touch on that briefly?

Yes. I mean, you can go on for hours about that. I mean, that ties to our culture, right? And our biggest benefit at Diamondback is that we have a small company dynamic culture with a large asset base that's now growing larger. So we are going to have to make sure we maintain that gritty, quick, fast-moving adaptive culture to a larger asset base. I'm fully confident that we have the executive team and employee base at both Diamondback and Endeavor to do that. And I think these big projects, there's a lot of capital being put in the ground before first oil sometimes upwards of $250 million, $300 million, but as long as you have the ability to move crews and rigs within a quarter, within a year, and keep hitting numbers, we're going to keep doing that at a larger scale.

As we built this company over the last 10 years, we've consistently maintained a flat organization and avoided silos. The only way to effectively grow while maintaining these aspects is to foster an exceptional level of trust. As we welcome Endeavor employees, we will be demonstrating this trust, which is crucial to our evolving culture as we become a larger company. Both of these elements—having a flat organization and no silos—will remain unchanged.

Our next question comes from the line of Derrick Whitfield of Stifel.

Congrats on another solid brand. With my first question, I wanted to focus on the second request from the FTC at a high level. Art Research indicates that most of the larger transactions have received that. Is that consistent with how you're thinking about it?

Yes, that's consistent.

All right. Terrific. And then shifting over to ops. So during the quarter, you completed 3 additional Upper Spraberry wells. Based on those results and some from last year, could you speak to how the interval competes in your portfolio and if it's likely to get added to your inventory charts on Page 21?

Yes, Derrick. In the first quarter, we completed three additional Upper Spraberry wells, building on the success we had in the North Martin area with our initial test. We are pleased with the preliminary results from these wells, and from a cost standpoint, we find them to be quite competitive. We are likely to consider including this development in our future plans.

I think to fill this up to the top of that, Derrick. If you start to add in zones like Upper Spraberry, Wolfcamp D, we've got some really good Wolfcamp D tests in some of those same pads. If you start to add those in and you don't see degradation on a corporate basis in terms of the cumulative curves that everyone looks at so closely every year. That's inventory extension in our existing asset base. And with the combination of us and Endeavor, adding in zones like the Upper Spraberry, Wolfcamp D into full-scale development, only extends the duration of what we can do here in the Midland Basin.

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

Travis, in your presentation, you mentioned plans to invest in income-generating projects to more directly offset remaining Scope 1 emissions. Can you provide more details about the size of this investment? Are you anticipating it will develop into a new division or business for you, or will it remain small-scale and not warrant much attention? My first question is about that. The second question is regarding the E&P producer space; it seems that no one is discussing AI much, while service providers are starting to highlight how AI will enhance their revenue and improve well productivity. I'm curious if Diamondback has explored AI applications and whether you anticipate that they will significantly impact your EUR or well productivity.

Well, the first emphasis on AI has been not degenerative AI, but using AI to process data information a lot quicker. And so, look, we're really excited about the long-term implications of AI on our industry, whether that translates to improvements in AUR or improvements in efficiencies or hopefully both, I think, is yet to be determined. But it's one of those things that we're trying to be fast followers on. This is an arena of our industry that's moving incredibly fast. These electric frac fleets that we're using right now actually are accumulating more information than we can process. So we're storing some of that information and hoping to use smart algorithms or AI to help us process that information in a more usable and more real-time fashion. Kaes, this first question was about the income-generating tech to offset that.

Yes. I mean, we have a subsidiary company called Cottonmouth Ventures, that's kind of our new ventures angle, I'll call it. But it's not a huge business today. I think one of the more exciting projects we're working on is with our Verde Clean Fuels partnership where we are in the scoping phase of building a plant, a gasoline plant in the basin that's going to be tapped into one of the pipelines that we are participants in. That plant will convert 35 million cubic feet a day of lean natural gas into 3,000 barrels a day of gasoline. So that, I think, fits our model of if we can contribute molecules and expertise to a project, not just capital but the other things to drive value, we're going to look at it. I would say that project might reach Financial Investment Decision by the end of this year and be up and running in a couple of years, and that might be a good little off-take for 35 million a day of gas. And if it works, we're going to build more of them.

Paul, when you look at the capital program, it's going to spend between $4 billion and $5 billion a year on a pro forma basis. The percent of that that we're going to allocate to income-generating projects is probably pretty small and that in an individual sense, it will probably have a larger impact, but I wouldn't expect it to move up to a noticeable level on a company that's spending between $4 billion and $5 billion a year.

Our next question comes from the line of Leo Mariani of ROTH MKM.

I just wanted to touch base on sort of activity cadence this year. It looks like you guys had kind of 89 first quarter completions, all in the Midland, but that's a pretty healthy percentage, about 32% of your full year budget on completions. Is there some anticipation that maybe some slowdown as the year goes and just seem like a quicker pace than I expected here in the first quarter?

Yes, Leo, we had a strong finish to last year and carried that momentum into Q4, which led us to push some completions into Q1. As a result, Q1 appears a bit elevated compared to our usual expectation of about 70 to 80 completions per quarter as a baseline. Q2 might trend towards the higher end of that range. However, since we're slightly ahead of our efficiency and timing goals, we plan to decrease our frac crew count by one for part of the summer and reduce our drilling rigs to around 12 or 13 to maintain our well completion numbers. We review our plan almost weekly with the planning team, and overall, our efficiencies are resulting in reduced activity levels but greater capital efficiency, positioning us well as we approach the potential close with Endeavor in Q4.

No, that's helpful color. And then just shifting over to asset sales. You obviously talked a little bit about sort of when the Endeavor deal closes, maybe moving some midstream assets into your Deep Blue joint venture and also a drop-down to Viper. Outside of some of the Endeavor-related asset sales, is there anything else that you guys are sort of working on? You talked about raising cash from free cash flow here over the next handful of months until the deal closes. But just trying to get a sense if you guys are looking at other asset sales in the interim.

Yes. Not many. We sold a piece of our Viper ownership in the first quarter, and that plugged another $450 million of cash on the balance sheet. And I think I'll go back to when we structured this deal. We certainly do not want to put so much cash into the deal with Endeavor that we had to be a seller of assets, and that's exactly what we've done. Now, I think we've had some price help here in the last couple of months that has boosted free cash flow and reduced the cash portion of the transaction. And listen, I think the price has got to be right for any asset sale, whether it's the Deep Blue, Viper or otherwise. And we're going to be patient post-close. I do think those assets make sense in other hands, but it's got to be the right value.

Okay. That's helpful. And then just wanted to ask about your production kind of severance tax here. You give the guidance to kind of 7% of revenue. It's kind of come in below that the last handful of quarters, closer to 5% to 6%. Just wanted to see what was kind of going on there. Maybe that was kind of anomalous in the last handful of quarters, and 7% is the right number going forward?

Yes. It was just higher than that before then, a couple of quarters before that, and we had to work off the accruals. That number has been 7% for 10 years. We had a consultant that told us it was going to be higher last year, and that consultant is no longer working for us, but it's going to be 7% on an annual basis on average.

This concludes the question-and-answer session. I would now like to hand the call back over to Travis Stice.

Thank you again to everyone participating in today's call. If you've got any questions, please reach out to us using the contact information provided. Thank you, and have a great day.

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