Good day, and thank you for standing by. Welcome to the Diamondback Energy second quarter 2023 earnings conference call. At this time, all participants are in listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star one, one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one, one again. 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. 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. Good morning. Thank you, Adam. As Adam mentioned last night, we released a shareholder letter in conjunction with our press release. 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. Those of you who have followed our story for a long time know how important improving efficiency is to us. With that, operator, let's move right into questions, if you'll open the line. Thank you. At this time, we will conduct the question-and-answer session. As a reminder, to ask a question, you will need to press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one, one again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Neal Dingmann of Truist Securities. Your line is now open. Morning, Travis, guys. Nice quarter. Travis, my first question, maybe get right to it, is on service costs, that 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? Maybe more importantly, what are you all assuming the change in cost for the remainder of the year and how this could impact the 2024 levels? You know, Neil, good morning. That's a good question. You know, when, when you look at, our business partners on the service side, they have always been responsive to declining and increasing rig count. The, the Permian Basin rig count continues to decline. You know, with the discipline we're seeing, across the E&P space, with the reluctance to, you know, increase spending, we believe that, you know, we will continue to see a softening, you know, in cost on our-- from our friends on the, on the service side. Now, with that, that's only part of the calculus. The other part, which we, we view more as the variable side, you know, we continue to, to drive costs out of the equations with increased efficiency. Like we talked about in May, we also see continued input costs coming down, steel, cement and other items. You know, it's, it's, it's hard to, you know, forecast, you know, 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. We also continue to rely on our organization to, to do things more efficiently, which they continue to do quarter-over-quarter. Travis, it's too early to call any deflation for next year at this point? I think, I think it's premature to call deflation from where we're headed at the end of the year, Neil. You know, I think high level, you know, we entered the year in the Midland Basin in, like, the low $700s a foot, drilling, drilling, complete and equipped costs, and we'll probably exit the year in the low $600s a foot. You know, again, we're not calling for a cratering of the service market. We're just calling for a rationalization of it, where, you know, costs only went up into the right for all service lines and raw materials for seven or eight quarters, and now that's coming back down to earth a little bit. You know, we can kind of enter 2024 and or exit 2023 in the low $600s per foot in the Midland Basin. That feels like a pretty good baseline for 2024. Great. Great point, guys. Then my second question on capital spend. Specifically, it looked like you slightly increased the midstream and upstream CapEx guidance, you know, very, very slightly. I'm just wondering, are you able to give a little color around maybe how this will be allocated both for the upstream and midstream, and then potential benefits that 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, this, upturn? Yeah, I'll start with the upstream. You know, we, we drilled a lot of wells in Q2, right? We've drilled a record amount of wells, 98 wells in the quarter. You know, that would imply we're drilling almost 400 wells a year versus guidance at, at 340. A lot, a lot of, a lot of pipe in the ground, a lot of lateral footage drilled, almost a little over 1 million, 1.1 million lateral ft. 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. That, that's kind of part of the main bump on the, on the DC and E side. You know, on the midstream side, you know, we have a lot of infrastructure in the Midland Basin that most of it is, you know, does have extra capacity. You know, if a neighbor needs water or needs to dispose of water, and we have that capacity, we will, you know, spend a few dollars to connect to that, to that person. A few unique opportunities came up in Martin County throughout the last three or four months, and we're gonna spend some dollars to go get a lot of barrels, and that's, you know, high payback, high return, midstream spend. Helpful. Thanks, guys. Thank you, Neil. Thank you. Please stand by for our next question. Our next question comes from the line of Neil Mehta of Goldman Sachs. Your line is now open. Thank you so much, guys. The first question, Travis, is just on the M&A landscape in the Permian, maybe you could talk about, do you see a role for Diamondback to continue to be a consolidator in the basin? Then also provide an update on the asset sales, as that program has gone very well for you guys. Yeah, well, I'll take those in reverse order. If you're talking about the, the, the deals that we did earlier in the year, they've been seamlessly integrated with, 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, you know, continues to be the trend as you see acquisitions occur, operators that are acquiring or dropping rigs as they focus on the increased profitability. The, the landscape, Neil, certainly relative to what we've seen in the last, you know, couple of quarters, there's just really few opportunities out there. I mean, there was a, a rush, primarily on the private equity side, to, to get deals into the market, and relative to what we see right now, it's very, very, very, very limited. You know, as to FANG's role in M&A, you know, 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, to win deals that make us not bigger, but better. We'll, you know, we'll continue to always hold ourselves accountable to that. I'll go back to my earlier comment, that relative to what we've seen in the first half of the year, it's, it's, it's pretty sparse on, on a go-forward basis. Yep. Thanks, Travis. 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'll help us sort of calibrate the return of capital profile for the company, too. Thank you. Sure. You know, the, the leverage, you know, obviously moves around with, with 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 that building a little bit of cash on, on the balance sheet continues to make sense in order to be opportunistic for share repurchases in a countercyclical way. But, but those are, those are kind of the two, the two inputs that we, that we build our capital structure and return model around. Thanks, Travis. Thank you. Please stand by for our next question. Our next question comes from the line of Arun Jayaram from JPMorgan. Your line is now open. 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 4 Q versus 3 Q, which you're pegging as the new baseline. I was wondering if you could help us understand the drivers of the lower CapEx in 4 Q versus 3 Q. Yeah, Arun, I, I would say, you know, 4Q versus 3Q is a combination of lower activity and lower costs going through the, going through the system. You know, as you know, we're a cash CapEx payer, so, you know, we can see a few months in advance what, what, what CapEx is looking like, and certainly coming down in the out months. You know, I would say generally, you know, that's probably the low end of a baseline for, for the next year. Certainly think that a low six hundreds a quarter kind of run rate feels okay. $600 million a quarter run rate feels okay for 2024. You know, it is, it is only August first, so, you know, we're, we're gonna put that in pencil and see where service costs shake out. Certainly things tend to be moving our way from a, from a well cost perspective. You know, I gave some kind of cost per foot language earlier in the Midland Basin, you know, down to the low $600 by the end of the year. You know, still feels very achievable, and, and that kind of sets our, our, our targets for the upcoming year. Great, and kind of stole my thunder there 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 Kaes, as we stand here today, at that, that's something in the low $600s? Yeah, I'd say that today. You know, obviously, still a lot of things to, to shake out, but I think the quality of the inventory that we have coming up, as well as, you know, the high mineral interests, you know, in the, in the core of the basin, you know, completely undeveloped sections and units, you know, feels like a very capital-efficient plan. You know, we've kind of been highlighting this for the last couple of years. You know, the Guidon and QEP transactions provided a lot of undeveloped inventory that we can bring, a large-scale execution machine to, and now we're, you know, seeing the benefits of, of those couple deals. You know, Arun, just as a reminder, we've been, we've been guiding for kind of lower CapEx, you know, all year long in the back half, and we're, we're seeing it play out now. As we laid out on slide six of our investor deck, you know, sort of a, a forecast, you know, by quarter of what that looks like. Great. Thanks a lot, gents. Thanks, Arun. Thank you. Please stand by for our next question. Our next question comes from the line of Derrick Whitfield of Stifel. Your line is now open. Hey, good morning, all, and congrats on a strong quarter. Thanks, Derrick. Staying on 2024, now that you've fully integrated FireBird and Lario, what is the, the right base level of activity that would support the 2024 outlook from a rig and frac spread perspective? Yeah, you know, I- I'll kind of highlight, you know, what we've done in 2023, that feels, feels like a, a good baseline for, you know, the forward plan, not forever, but, how, how we think about capital allocation. You know, we, we have a business where we can run four simul-frac crews efficiently, right? A simul-frac crew, on the completion side, completes about 80 wells a year. For us, you know, in this new business model of capital efficiency and profit, you know, value over volumes, you know, we're, we're focused on running the most efficient plan possible, which would be that four simul-frac crew plan. You know, absent of 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. Kind of that 15-ish rigs and 4 simul-frac crews feels like a really good baseline for us. You know, 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, you know, I, I hope we have been able to demonstrate that volume growth is an output of efficient capital allocation that's, that's laser-like focused on profitability. As, you know, as here on August 1st, as we're entertaining questions on 2024, the, the volume growth will be an output of efficient capital allocation that maximizes the value for our, for our capital allocation decisions. Understood. Thanks for that, Travis. As my follow-up, I wanted to touch on well productivity, which, which you've rightfully highlighted on page 15 as a positive. When you look out to 2024, how do you guys think about well productivity relative to 2023? 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. Yeah, Derrick, you know, I, I think, you know, generally, we feel very confident in the forward outlook for productivity. I think that's gonna be a unique position in North American shale. You know, we've, we've been, we've timed deals very, very well, and we've, we've made the shift to co-development four or five years ago now, and that, that's resulting in very steady productivity, as you can see, you know, within 1% of 2022 levels already in 2023. You know, I would just say flat, you know, flat feels like the baseline, and, and if it's better than that, that's, that's 1 for the good guys. You know, Derrick, we continue to, to, to lay out on slide 16 in this, this deck, you know, what our inventory looks like. As I, as I look into the future, you know, I, I couldn't be more confident about the long-term quality of our inventory. In fact, that confidence in the future business plan, you know, 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, our base dividend. I think our, our quarterly CAGR for dividend increases is around 10% since we initiated it in 2018. I hope that helps. Great. Well done, guys. Thanks for your time. Thank you. Please stand by for our next question. Our next question comes from the line of Charles Meade of Johnson Rice. Your line is now open. Good morning, Travis, Kaes, and Adam, and the rest of the gang crew there. Good morning, Charles. Travis, I, I wonder if you could drill down a little bit on the improved cycle times that's that's allowing you to increase your gross well count for the year. Is this something that's... You know, I can think of a few possibilities. Is this something where you have a couple of, couple of rigs that have just increased their performance, or, or is this something that's more widespread across your whole rig fleet, that, you know, perhaps bit selection or something like that, which is letting every rig just get through their laterals quicker? What, what's, what's the driver there? You know, Charles, I wish I could say it was one individual piece of technology that's transferable across, you know, our entire rig fleet. It's much more subtle than that. I'm gonna let Danny give you some specific, you know, examples. You know, we get this question a lot, and it's, and it's always phrased in different ways about why does Diamondback do what they do? The answer remains unchanged. It's the culture that we have that has an extreme focus on cost control and efficiencies. The reason that that's important to our culture is because when we make those gains in efficiencies, those gains become permanent in, in part to our future capital allocation decisions, which makes us more competitive for the same dollar that we're competing with relative to our peers. It's not, again, it's, it's not one or two items, it's thousands of items that are decided upon every one of these rigs. Look, we have, you know, a healthy competition, you know, among our rigs and completion crews that we incentivize monetarily for efficiency and cost control measures. Danny, do you want to add some specifics on that? Yeah. You know, I think we, we've seen, you know, certainly our year-over-year days, you know, reduced by, by, you know, some measurable percentage. You know, what it boils down to is the teams measuring, you know, every little thing they can on the rig, and, you know, measuring which way those operational metrics are trending. When one's not trending in the right direction, they attack it, you know, with a fervor that is, you know, unlike anything I've ever seen. That continues to output, you know, year-over-year improvements in execution. You know, this past month, we had a couple wells that they've drilled at our all-time records for us, for 7,500 foot laterals that were, you know, some five-day wells, just over four days to TD. Those results are remarkable. We don't talk about individual well results a lot, but those are the things that, you know, we continue to do in the, you know, in the day-to-day of the company that continue to drive our execution downwind. You know, Charles, just one added to that. We just completed our quarterly reviews, several weeks ago, The, the teams present to us levels of details of measurement that Danny was talking about, which is, is almost stunning to me, but we do it almost every quarter. That is, you know, they measure how long it takes to physically screw pipe together for, you know, for 300 times for every trip that they make. That measurement of just simply screwing pipe together in five minutes versus the next rig over that was six minutes, you know, you think doesn't matter, but you do that several bit, bit trips, bit runs, you know, per well, it, it adds up. That's the level that our organization focuses on efficiency. We have a lot of Diamondback employees listening in to 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-day, 7,500 foot wells that Danny just alluded to. Thank you, Travis. That reminds me of that, that saying, "What, what gets measured gets done." Second question. This kind of gets to the capital structure question. I want to ask how you view the decision or the trade-off between the share buybacks and the note buybacks. I, I, I'd like to see those note buybacks, and looks like you guys, you know, did it some good prices. I, I, you know, sometimes I could perhaps get lost in the, you know, because it's not technically a cash return to shareholders, but it is a return to shareholders. How do you guys approach that, that look on buyback notes versus shares? Let me, 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, we put that in place to be not only a sustainable, but a growing base dividend. As I talked about earlier this quarter, we increased our base dividend another 5%. You know, 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 /bbl of oil. That just gives you some confidence as to that base dividend. The second piece of the equation is share buybacks. Share buybacks, you know, are determined based on, you know, our future expectation of future cash flows and turned into a stock price so that we can measure, you know, where we wanna, where we wanna repurchase shares back. 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. 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's behind us, but the lower the stock price, you know, the more you get share repurchases, the higher the stock price, you know, you tend to, you tend to purchase less. I hope that makes sense. Anything left over from that calculus, Charles, is gonna 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. I hope that makes sense. Thanks, thank you for that elaboration. Appreciate it. Thank you. Please stand by for our next question. Our next question comes from the line of Subash Chandra from The Benchmark Company. Your line is now open. Hi, good morning, everyone. The first question is how you think of, you know, oil cuts going forward into 2024. You know, is that a function of maybe the zones you're drilling or just spatially where the acreage is located, or perhaps other factors like, you know, gas capture, etc? Yeah, good, good question. You know, listen, we're, we're allocating a lot of capital to the Northern Midland Basin, where, you know, it's very oily, particularly early time. You know, I think we kind of guide people to, to 59%, 60% oil. I, I think that's probably a fairly good baseline for the next few years. You know, in, in, in a world where we're not growing as much, you know, that, that oil cut stays flat, comes down slightly because, you know, the oil declines a little faster than the, than the gas piece. But, you know, generally, you know, we, we had a couple higher, gas cut wells in the Delaware Basin at the beginning of this year that, you know, boosted the gas, gas production as a company. Overall, you know, kind of high 50s%, 60% in a good quarter would be a, a good range for oil cut. Terrific. Thanks. 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's returned back to $80, the bid-ask? In the cash flow statement, I think there was, you know, $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. Yeah, I, I'll take that two, two ways. You know, generally, on the, on the purchase side, you know, we've been doing a little bit of leasing as well as a little bit of, you know, netting up. You know, we, we, we try to make our asset teams involved in BD. You know, they're, they're making offers on undeveloped, you know, interests and, and the, those non-op pieces that we don't own in, in our development. They're doing work there. You know, we've been looking at, at leasing some of the deeper rights in the Midland Basin across some of our positions. That's, that's tied to some of those purchases in the cash flow statement. You know, on, on the divestiture side, you know, we've, we've, we've divested a good amount of what we deem non-core acreage, you know, acreage that doesn't compete for capital in the next kind of 10 years of development and have received some good prices there. I, I, I'd say we're on the sidelines more on the, on the divestiture side today, outside of, you know, what would be a very unique offer. Instead, we're more focused on the, you know, non-core midstream type divestitures like the OMOG divestiture we announced, this, this earnings. You know, we didn't, we didn't increase our non-core asset sale target. We certainly have some more assets that, that make sense to sell. We'll just most likely be, you know, tagging along and not controlling the process. Thanks so much. Thank you. Thank you. Please stand by for our next question. As a reminder, to ask a question, you will need to press star one one on your telephone. Again, that's star one one on your telephone. Our next question comes from the line of Leo Mariani of Roth MKM. Your line is now open. Hi, guys. I wanna talk a little bit about production here. Second quarter, you know, very nice beat, you know, versus the guidance. I think you guys said that you kind of drilled a, a record number of wells, you know, in the quarter. You're looking at third quarter production guide, it does indicate that, on a total basis, production should be down a little bit, you know, 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 till, till later in the year. What, what's kind of happening there? Yeah, Leo, you know what? I kind of see... We kind of think about the oil guidance as, as what drives the decisions here at, at the company. You know, I kind of see Q3 as, as flat, maybe up a little bit from, from Q2. You know, Q2 was a, a very good quarter from a completions perspective. You know, the drilling side doesn't really, doesn't really drive the production profile. You know, we were probably building a few DUCs in the back half of the year to, to set us up well for, for the next year. You know, completion cadence was also high in the first half of the year. I think we completed 89 wells in, in Q2. You know, that'll come down to kind of 80-ish for Q3 and Q4. You know, I think, again, the production is the output of, of smart, capital-efficient decisions. You know, if this was 2017 or 2018, we'd, we'd, you know, be stepping on the accelerator and, spending more capital. Instead, we're focused on generating more free cash flow in the second half of the year and, and returning that cash to shareholders. Okay, that's helpful. Then just on, on capital here. Kind of looking at kind of where you guys were in, in the second quarter, I mean, looks like that's gonna be the peak. We should be expecting, you know, CapEx to come down, I guess, both in, in 3Q and in 4Q. How much of that is kind of related to service costs? 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, to kind of low 6s by the end of the year. Are you starting to get some of that benefit here in, in 4Q? You know, similar number of completions, 80 should be down kind of a fair bit on capital here in 4 Q. Just help us think through that a little bit. Yeah, I, I think right now we're seeing the benefits of the raw materials decreases coming through the system, you know, mainly pipe, cement, diesel. Now, you know, kind of after this call through the end of Q3 into Q4, you know, some of the true service side, you know, rolling through the numbers. You know, as we, as we mentioned, we're a cash CapEx payer, so today we're paying for activity in June. We kind of have a, have a good forward outlook that CapEx is coming down. I think the cost per foot we're seeing on wells put in the ground today is, is lower even than Q2. You know, that's all gonna translate to a, a lower average well cost at the end of the year. Okay, thanks. Thanks, Leo. Thank you. Please stand by for our next question. Our next question comes from the line of Paul Cheng of Scotiabank. Your line is now open. Thank you. Good morning, guys. Two question, please. One of your large customer is bragging about how much is their EUR recovery rate has improved or is going to improve now based on the work that they are doing. Just wondering that, Travis, that, in this debate, I mean, are you guys looking into that? Whether that, based on today's technology and commodity price, is it economic for you to pursue trying to substantially improve the recoverable rate? That's the first question. Second question is. Yeah, Paul. Yep. Well, I'll answer the first one first. You know, I, I think, you know, Diamondback is, 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 fence line at what competitors and peers are doing. You know, there's not a ton of secrets in the Permian Basin, so if, if there is a better mousetrap, we're gonna find a way to do it. I think our advantage is that we can do it at, at a lower cost. So, generally, you know, we're constantly pursuing improving EURs, improving recoveries, improving technologies. So you'd expect us to be on our front foot there. I don't think we're gonna spend a ton of dollars, testing that, but I would instead be a fast follower on, you know, anything that looks to be working. Yeah. I mean, based on what you can see today on the technology and the current pricing, is it possible that to pursue, such an, such an activities? I don't think it's possible today. I, I certainly think there's some people spending money to look at it. You know, for us, you know, we really wanna allocate capital to the best returning projects that we have today, and, and that for us is, you know, high return, multi-zone development in the, in the Midland Basin. Great. The second question is on the lateral length. You guys have been very successful continuing to lengthen it. I think the third quarter is expecting about 10,800 ft. Based on your existing land position, your portfolio, do you think that there's far more room for you to, you know, average length is going to be able to push substantially higher than here? Or that we are pretty close to the max, unless there's some meaningful portfolio changes? Yeah, I, you know, I think it's a risk/reward decision, Paul. There, 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, our, you know, acreage sits today, that, that 10,000 ft-11,000 ft range feels about right on average. You know, we'd rather drill a 15,000 footer than two 7,500, 7,500 footers, but I think today we'd rather drill two 10,000 footers versus one 20,000 footer. I think the drilling guys can do it on the drilling side, there's no doubt about that. It's a, it's a risk/reward decision, because if something bad happens at 18,000 ft, that's an expensive mistake. We'd, we'd rather continue to get wells down at 10,000 ft in eight, nine days, you know, consistently, versus risking a 30, 40-day well when something goes wrong. All right. Great. Thank you. Thanks, Paul. Thank you. At this time, I would now like to turn it back to Travis Stice for closing remarks. Appreciate everyone listening in this morning. Good, good set of questions. Hope you have a fantastic day. If you've got any questions, just reach out to us at the number provided. Thank you. At this time, That concludes today's conference. You may now disconnect.