Diamondback Energy, Inc. (NASDAQ:FANG) Q2 2023 Earnings Call Transcript

Diamondback Energy, Inc. (NASDAQ:FANG) Q2 2023 Earnings Call Transcript August 1, 2023

Operator: Good day, and thank you for standing by. Welcome to the Diamondback Energy Second Quarter 2023 Earnings Conference Call. [Operator Instructions] Please be advised that today’s conference is being recorded. I would now like to hand the conference over to the VP of Investor Relations, Adam Lawlis. Please go ahead.

Adam Lawlis : Thank you, Jules. Good morning, and welcome to Diamondback Energy’s Second Quarter 2023 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 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.

Travis Stice : Good morning, and thank you, Adam. As Adam mentioned, last night we released a shareholder letter in conjunction with our press release, and this is our second quarter in a row we’ve tried this. I hope you find it useful. We believe that it not only increases the transparency directly to our shareholders but also improves efficiency, and those of you who have followed our story for a long time know how important improving efficiency is to us. So with that, operator, let’s move right into questions, if you’ll open the line.

Q&A Session

Operator: At this time, we will conduct the question-and-answer session. [Operator Instructions]. Our first question comes from the line of Neal Dingmann of Truist Securities. Your line is now open.

Neal Dingmann : Morning, Travis. Guys. Nice quarter. Travis, my first question, maybe get right to it, is on service cost, and we’ve heard a lot of chatter about. Specifically, could you speak to maybe the current rig and frac rate environment today versus a couple of months ago? And maybe more importantly, what are you all assuming the change in cost for the remainder of the year, and how this could impact the ’24 levels?

Travis Stice : Neal, Good morning That’s a good question. When you look at our business partners on the service side, they have always been responsive to declining and increasing rig count, and the Permian Basin rig count continues to decline. And with the discipline we’re seeing across the E&P space with the reluctance to increase spending, we believe that we will continue to see a softening in cost on our — from our friends on the service side. Now with that, that’s only part of the calculus. The other part, which we view more as the variable side, we continue to drive cost out of the equation with increased efficiency. And like we talked about in May, we also see continued input costs coming down on steel, cement and other items.

So it’s hard to forecast into the future, but we definitely believe that we’re going to see a softening in many of the costs that we’ve seen from the first half of the year. And we also continue to rely on the organization to do things more efficiently, which they continue to do quarter-over-quarter.

Neal Dingmann : So Travis, is it too early to call any deflation for next year at this point?

Danny Wesson: I think it’s premature to call it deflation from where we’re headed at the end of the year, Neal. I think high level, we entered the year in the Midland Basin in like in the low 700s a foot, drilling complete and equipped costs, and we’ll probably exit the year in the low 600s a foot. Again, we’re not calling for a cratering of the service market, we’re just calling for a rationalization of it where costs certainly went up into the right for all service lines and raw materials for 7 or 8 quarters, and now that’s coming back down to earth a little bit. So we can kind of enter 2024 and rest of 2023 in the low 600s per foot in the Midland Basin. That feels like a pretty good baseline for 2024.

Neal Dingmann : Great. Great point, guys. And then my second question on capital spend. Specifically, it looked like you slightly increased the midstream and upstream CapEx guidance very, very slightly. But I’m just wondering, are you able to give a little color on maybe how this will be allocated both for the upstream and midstream? And then potential benefits with this slight push in cost, especially noticeable around the midstream, but I’m curious around both, maybe any benefits that we could see from this upturn?

Danny Wesson: Yes. I’ll start with the upstream. We drilled a lot of wells in Q2, right. We’ve drilled a record amount of wells, 98 wells in the quarter. That would imply we’re drilling almost 400 wells a year versus guidance at 340; so a lot of pipe in the ground, a lot of — lot of footage drilled, almost a little over 1 million — 1.1 million lateral feet. So it was a good quarter operations-wise, which is why we’re slowing down the drilling pace in the second half of the year and building a few DUCs, so that’s kind of part of the main bump on the DC&E side. And then on the midstream side, we have a lot of infrastructure in the Midland Basin that most of it is — does have extra capacity. And if the neighbor needs water or needs to dispose the water and we have that capacity, we will spend a few dollars to connect to that person.

So a few unique opportunities came up in Martin County throughout the last three or four months, and we’re going to spend some dollars to get a lot of barrels, and that’s high payback, high-return midstream spend.

Operator: Thank you. [Operator instructions] Our next question comes from the line of Neil Mehta of Goldman Sachs. Your line is now open.

Neil Mehta : Thank you so much, guys. The first question, Travis, is just on the M&A landscape in the Permian. And maybe you could talk about, do you see a role for Diamondback to continue to be a consolidator in the basin? And then also provide an update on the asset sales, as that program has gone very well for you guys?

Travis Stice : I’ll take those in reverse order. If you’re talking about the deals that we did earlier in the year, they’ve been seamlessly integrated with absolutely no issue. I will say that both of those companies we acquired were running more rigs than we’re currently running now, which again continues to be the trend as you see acquisitions occur, operators that are acquiring or dropping rigs as they focus on increased profitability. The landscape, Neil, certainly relative to what we’ve seen in the last couple of quarters, there’s just really a few opportunities out there, I mean there was a rush primarily on the private equity side to get deals into the market. And relative to what we see right now, it’s very, very limited.

As to Fang’s roll in M&A, we have created a lot of shareholder value through M&A but our discipline has also been noteworthy as well, too. It’s not important to win every deal. It’s important to win deals that make us not bigger, but better, and so we’ll continue to always hold ourselves accountable to that. But I’ll go back to my earlier comment that relative to what we’ve seen in the first half of the year, it’s pretty parsed on a go-forward basis.

Neil Mehta : Thanks, Travis, and the follow-up is just optimal capital structure. We’ve talked about this in the calls over the years, but just how do you think about what the optimal cash level, leverage level is for the business? And it will help us sort of calibrate the return of capital profile for Q2? Thank you.

Travis Stice : Sure. The leverage obviously moves around with the oil price, but I think having a leverage ratio of less than one is appropriate for the size and scale of a company of Diamondback size. I do think also with building a little bit of cash on the balance sheet continues to make sense in order to be opportunistic for share repurchases in a countercyclical way. But those are kind of the two inputs that we build our capital structure and return model around.

Operator: [Operator instructions]. Our next question comes from the line of Arun Jayaram from JPMorgan. Your line is now open.

Arun Jayaram : Good morning, Travis and team. Both of my questions relate to CapEx. My first question is on your updated guide, you’re guiding to an $80 million decline in sequential CapEx in 4Q versus 3Q, which you’re pegging as the new baseline. I was wondering if you could help us understand the drivers of the lower CapEx in 4Q versus 3Q?

Kaes Van’t Hof: Yes, Arun. I would say 4Q versus 3Q is a combination of lower activity and lower costs going through the system. As you know, we’re a cash CapEx payer, so we can see a few months in advance what CapEx is looking like and certainly coming down in the outlines. I would say generally, that’s probably the low end of a baseline for the next year. I certainly think that a low 600s a quarter kind of runrate feels okay — $600 million a quarter run rate feels okay for 2024. It is on the August 1, so we’re going to put that in pencil and see where service costs shake out. But certainly, things tend to be moving our way from a well cost perspective. I gave some kind of cost per foot language earlier in the Midland Basin down to the low 600s by the end of the year. Still feels very achievable, and that kind of sets our targets for the upcoming year.

Arun Jayaram : Great. And kind of stole my thunder here on the second question, but your 2024 outlook is to drive low single digits oil growth. I know the Street is now modeling around $650 million per quarter in CapEx, but it sounds like you’re comfortable, case as we stand here today, at something in the low 600s.

Kaes Van’t Hof: Yes, I’d say that today. Obviously, still a lot of things to shake out, but I think the quality of the inventory that we have coming up as well as the high mineral interest in the core of the basin, completely undeveloped sections and units feels like a very capital-efficient plan. We’ve kind of been highlighting this for the last couple of years. The guide on in QEP transactions provided a lot of undeveloped inventory that we can bring a large-scale execution machine to, and now we’re seeing the benefits of those couple of deals.

Travis Stice : Arun, just as a reminder, we’ve been guiding for kind of lower CapEx all year long in the back half, and we’re seeing it play out now. And as we laid out on Slide 6 of our investor deck, sort of a forecast by quarter of what that looks like.

Operator: Our next question comes from the line of Derrick Whitfield of Stifel. Your line is now open.

Derrick Whitfield : Good morning all and congrats on a strong quarter.

Travis Stice : Thanks, Derrick.

Derrick Whitfield : Staying on 2024, now that you’ve fully integrated FireBird and Lario, what is the right base level of activity that would support the 2024 outlook from a rig and frac spread perspective?

Danny Wesson: Yes. I’ll kind of highlight what we’ve done in 2023, and that feels like a good baseline for the floor plan, not forever, but how we think about capital allocation. We have a business where we can run four simul-frac crews efficiently, right? And simul-frac crew on the completion side completes about 80 wells a year. And for us, in this new business model of capital efficiency and profit value over volumes, we’re focused on running the most efficient plan possible which would be that four simul-frac crew plan. Absent a major change in commodity price, that’s — the plan is the plan, and that allows the teams to plan their business and also allows us to execute at the lowest cost from a CapEx perspective. So kind of that 15-ish rigs and four simul-frac crews feels like a really good baseline for us.

Travis Stice : And Derrick, just to add to that, this profitability model that we’ve been demonstrating now for multiple quarters in a row and the industry has pivoted to, I hope we have been able to demonstrate that volume growth is an output of efficient capital allocation that’s laser-like focused on profitability. So as here on August 1, as we’re entertaining questions on 2024, the volume growth will be an output of efficient capital allocation that maximizes the value for our capital allocation decisions.

Derrick Whitfield : Understood. Thanks for that, Travis and as my follow-up, I wanted to touch on well productivity, which you’ve rightly highlighted on Page 15 as a positive. When you look out to 2024, how do you guys think about well productivity relative to 2023? And then how does that project over the next few years? It feels like you guys have a very deep portfolio that has quite a bit of stability over the next several years.

Kaes Van’t Hof: Yes, Derrick. I think generally, we feel very confident in the forward outlook for productivity. I think that’s going to be a unique position in North American shale. We’ve been — we timed deals very, very well, and we’ve made the shift to co-development four or five years ago now, and that’s resulting in very steady productivity. As you can see within 1% of 2022 levels already in ’23. And I would just say flat feels like the baseline, and if it’s better than that, that’s one for the good guys.

Travis Stice : Derrick, we continue to lay out on Slide 16 in this deck what our inventory looks like. And as I look into the future, I couldn’t be more confident about the long-term quality of our inventory. And in fact, that confidence in the future business plan is part of the reason that we’re confident in being able to increase our base dividend. I mean that’s, to me, the clearest indication from management to our owners about the future of our business and the quality of our inventory, is our ability to continually increase our base dividend. I think our quarterly CAGR for dividend increases is around 10% since we initiated it in 2018. So I hope that helps.

Operator: Our next question comes from the line of Charles Meade of Johnson Rice. Your line is now open.

Charles Meade : Good morning, Travis, Kaes and Adam and the rest of the FANG crew there. Travis, I wonder if you could drill down a little bit on the improved cycle times that’s allowing you to increase your gross well count for the year? Is this something that’s — I can think about a few possibilities. Is this something that where you have a couple of rigs that have just increased their performance? Or is this something that’s more widespread across your whole rig fleet, like perhaps a bit selection or something like that which is letting every rig just to get through the laterals quicker? What’s the driver there?

Travis Stice : Charles, I wish I could say it was one individual piece of technology that’s transferable across our entire rig fleet, but it’s much more subtle than that. And I’m going to let Danny give you some specific examples. But we get this question a lot, and it’s always phrased in different ways about why does Diamondback do what they do, but the answer remains unchanged. It’s the culture that we have that has an extreme focus on cost control and efficiencies. And the reason that that’s important to our culture is because when we make those gains in efficiencies, those gains become permanent in part to our future capital allocation decisions, which makes us more competitive for the same dollar that’s that we’re competing with relative to our peers.

And it’s not — again, it’s not one or two items. It’s thousands of items that are decided upon every one of these rigs. And look, we have a healthy competition among our rigs and completion crews that we incentivized monetarily for efficiency and cost control measures. And Dan, do you want to add some specifics on that?

Danny Wesson: Yes. I think we’ve seen certainly our year-over-year days reduced by some measurable percentage. And what it boils down to is the team is measuring every little thing they can on the rig and measuring which way those operational metrics are trending. And when one is not trending in the right direction, they attack it with a fervor that is unlike anything I’ve ever seen, and that continues to output year-over-year improvements in execution. And this past month, we had a couple of wells that they’ve drilled at their all-time records for us for 7,500-foot laterals that were sub five-day wells for just over four days TD. And those results are remarkable, and we don’t talk about individual well results a lot, but those are the things that we continue to do in the day-to-day of the company that can continue to drive our execution downward.

Travis Stice : Charles, just one add to that. We just completed our quarterly reviews several weeks ago, and the teams present to us levels of details of measurement that Daniel was talking about, which is almost stunning to me, but we do it almost every quarter. And that is, they measure how long it takes to physically screw pipe together for 300 times for every trip they have to make. And in that measurement of just simply screwing pipe together in five minutes versus the next rig over that was 6 minutes, you think doesn’t matter. But you do that several bit trips, bit runs per well, it adds up, and that’s the level that our organization focuses on efficiency. And we have a lot of Diamondback employees listening into this call this morning, and I want them to hear that I’m proud of that work that they continue to do and deliver those results of four days, 7,500-foot wells that Danny just alluded to.

Charles Meade : Thank you, Travis. It reminds me that’s saying what gets measured gets done. But second question, and this kind of gets to the capital structure question. I wanted to ask how you view the decision or the trade-off between that the share buybacks and the note buybacks? I’d like to see those no buybacks, and it looks like you guys did some good prices, but sometimes that could perhaps get lost in the — because it’s not technically cash returns to shareholders, but it is a return to shareholder. So how do you guys approach that that look on buying back notes versus shares?

Travis Stice : Let me talk to you about how we discussed it at the Board level. The primary form of shareholder return is in our base dividend. And we put that in place to be not only a sustainable, but a growing base dividend. And as I talked about earlier this quarter, we increased our base dividend another 5%. And so as you look into the future, that base dividend will remain of paramount importance to us, and we believe that we have that base dividend covered down to $40 a barrel of oil. So I’ll just give you some confidence as to that base dividend. The second piece of the equation is share buybacks, and share buybacks are determined based on our future expectation of future cash flows and turned into a stock price so that we can measure where we want to repurchase shares back.

And so you can tell from the last several quarters, the fact that we’ve leaned in all of our discretionary free cash flow after our base dividend to repurchase shares. And in a general sense and not specific, because everybody wants to know what stock price we’re using, which we won’t say until the quarter is behind us. But the lower the stock price, the more you get share repurchases. The higher the stock price, you tend to purchase less. So I hope that makes sense. And then anything left over from that calculus, Charles, is going to be distributed in the form of a variable dividend because we made a commitment to our owners that we would return 75% of our free cash flow. So I hope that makes sense.

Charles Meade : Thank you for that elaboration. Appreciate it.

Operator: Our next question comes from the line of Subash Chandra from Benchmark Company. The line is now open.

Subash Chandra: Hi. Good morning, everyone. The first question is how you think of oil cuts going forward into ’24? Is that a function of maybe the zones you’re drilling or just spatially where the acreage is located? Or perhaps other factors like gas capture, et cetera?

Kaes Van’t Hof: Yes. Good question. Listen, we’re allocating a lot of capital to the Northern Midland Basin where it’s very oily particularly early time. I think we kind of guide people to 59%, 60% oil. I think that’s probably a fairly good baseline for the next few years. In a world where we’re not growing as much, that oil cut stays flat and comes down slightly because the oil declined a little faster than the gas piece. But generally, we had a couple of higher gas cut wells in the Delaware Basin in the beginning of this year that boosted the gas production as a company. But overall, kind of high 50s, 60% in a good quarter would be a good range for oil cut.

Subash Chandra: Right. Terrific. And the follow-up is, I guess, on asset sales. So they’ve been largely midstream. How do you think the market now is for upstream assets now that oil has returned back to 80 in the bid ask? And in the cash flow statement, I think there was $140 million, $150 million of asset purchases. Just curious if that’s just a flow — overflow from the first quarter on deals announced already or just immaterial acquisitions?

Kaes Van’t Hof: Yes. I’ll take that two ways. Generally, on the purchase side, we’ve been doing a little bit of leasing as well as a little bit of netting up. We try to make our asset teams involved in BD. They’re making offers on undeveloped interests and those non-op pieces that we don’t own in our development. So they’re doing work there. We’ve been looking at leasing some of the deeper rights in the Midland Basin across some of our positions, so that’s tied to some of those purchases in the cash flow statement. And then on the divestiture side, we’ve divested a good amount of what we deem noncore acreage and acreage that doesn’t compete for capital in the next kind of 10 years of development, and have received some good prices there.

I’d say we’re on the sidelines more on the divestiture side today outside of what would be a very unique offer. Instead, we’re more focused on the noncore midstream type divested like the OMOG divestiture we announced this earnings. We didn’t increase our noncore asset sale target. We certainly have some more assets that make sense to sell, we’ll just most likely be tagging along and not controlling the process.

Operator: [Operator Instructions] Our next question comes from the line of Leo Mariani of ROTH MKM. Your line is now open.

Leo Mariani : Hi guys.Want to talk a little bit about production here, so second quarter, a very nice beat versus the guidance. I think you guys said that you kind of drilled a record number of wells in the quarter. Looking at third quarter production guide, it does indicate that on a total basis, production should be down a little bit this quarter. Can you just help us kind of think through that dynamic a little bit with kind of record drilling last quarter, but production is coming down? Maybe you guys are kind of holding some wells off in terms of turning them in line until later in the year? What’s kind of happening there?

Kaes Van’t Hof: Yes, Leo. I kind of see — we kind of think about the oil guidance is what drives the decisions here at the company. I kind of see Q3 as flat to maybe up a little bit from Q2. But Q2 was a very good quarter from a completions perspective. The drilling side doesn’t really drive the production profile. We were probably building a few ducts in the back half of the year to set us up well for the next year. Completion cadence was also high in the first half of the year. I think we completed 89 wells in Q2, come down to kind of 80-ish for Q3 and Q4. So I think, again, the production is the output of smart capital-efficient decisions. If this was 2017 or 2018, we’d be stepping on the accelerator and spending more capital. But instead, we’re focused on generating more free cash flow in the second half of the year and returning that cash to shareholders.

Leo Mariani : Okay. That’s helpful. And then just on capital here. So kind of looking at kind of where you guys were in the second quarter. I mean, it looks like that’s going to be the peak. So we should be expecting CapEx to come down, I guess, both in 3Q and in 4Q. How much of that is kind of related to service cost? You just talked about fewer completions in the second half, but is it really fourth quarter where you start to see maybe more service cost benefit? You talked about going from low 700s per foot start the year at a kind of low 6s by the end of the year. So are you starting to get some of that benefit here in 4Q? A similar number of completions, 80, should be down kind of a fair bit on capital here in 4Q? Just help us think of that a little bit.

Kaes Van’t Hof: Yes. I think right now, we’re seeing the benefits of the raw materials decreases coming through the system, mainly pipe, cement, diesel. And now, it’s kind of after this call through the — into Q3 into Q4, some of the true service side rolling through the numbers. As we mentioned, we’re a cash CapEx payer, so today, we’re paying for activity in June. So we kind of have a good forward outlook that that CapEx is coming down. I think the cost per foot we’re seeing on wells put in the ground today is lower even than Q2, and that’s all going to translate to a lower average well cost in the — at the end of the year.

Operator: Our next question comes from the line of Paul Cheng of Scotiabank. Your line is now open.

Paul Cheng : Thank you. Good morning, guys two questions, please. One of your large customers is bragging about how much is their EUR recovery way has improved or is going to improve based on the work that they are doing. Just wondering that, Travis, that in this debate, I mean, are you guys looking into that? Or that — what does that — based on today’s technology and commodity price, is it economic for you to pursue trying to substantially improve the recoverable way? That’s the first question. Second question is on — yes.

Kaes Van’t Hof: Why don’t we answer the first one first. I think Diamondback is really a technology company that produces oil, and we spend a lot of time looking at improving EURs, we spend a lot of time looking across the bench-line of what competitors and peers are doing. There’s not a ton of secrets in the Permian Basin, so if there is a better mousetrap, we’re going to find a way to do it. I think our advantage is that we can do it at a lower cost. So generally, we’re constantly pursuing, improving EURs, improving recoveries, improving technologies. You’d expect us to be on our front foot there. I don’t think we’re going to spend a ton of dollars testing that, but would instead be a fast follower on anything that looks to be working.

Paul Cheng : Yes. I mean based on what you can see today on the technology and the current pricing, is it profitable that you pursue such activities?

Kaes Van’t Hof: I don’t think it’s possible today. I certainly think there’s some people spending money to look at it. But for us, we really want to allocate capital to the best returning projects that we have today. And that for us is high-return, multi-zone development in the Midland Basin.

Paul Cheng : Great. The second question is on the lateral length You guys have been very successful, continue to lengthen it. I think the third quarter is expecting about 10,800 feet. Based on your existing land position in your portfolio, do you think that there’s far more room for you to [indiscernible] is going to be able to push substantially higher than here? Or that we are pretty close to the max, unless that there’s some meaningful portfolio changes?

Kaes Van’t Hof: Yes. I think it’s a risk-reward decision, Paul. There are certainly some areas where we can drill longer. I think — but I think generally, the way our land position is laid out and the way our acreage sits today, that 10,000 to 11,000 range feels about right on average. We’d rather drill a 15,000 footer than 2 7,500 footers. But I think today, we’d rather drill 2 10,000 footers versus 1 20,000 footer. So I think the drilling guys can do it on the drilling side. There’s no doubt about that. But it’s it’s a risk-reward decision because if something bad happens at 18,000 feet, that’s expensive mistake. So we’d rather continue to get wells down at 10,000 feet in 8, 9 days consistently versus risking a 30, 40-day well when something goes wrong.

Operator: Thank you. At this time, I would now like to turn it back to Travis Stice for closing remarks.

Travis Stice : Appreciate everyone listening in this morning. Good set of questions. I hope you have a fantastic day. If you’ve got any questions, just reach out to us at the number provided.

Operator: Thank you. At this time, that concludes today’s conference. You may now disconnect.