Good day, thank you for standing by. Welcome to the Diamondback Energy first quarter 2023 earnings conference call. At this time, all participants are in a 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, and 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 your first speaker today, Adam Lawlis, Vice President of Investor Relations. Please go ahead. Thank you, Gina. Welcome to Diamondback Energy's first quarter 2023 conference call. During our call today, we will reference an updated investor presentation and stockholder letter, 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 Daniel 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. Thank you, Adam. Adam mentioned that we released a shareholder letter last night in conjunction with our press release. I hope you find that useful. We believe that it not only increases transparency, directly to our shareholders, but also, improves efficiency. We'll move right into questions. Operator, if you would open the line and begin with our first question. Thank you. 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 for our first question. Our first question comes from the line of Neal Dingmann of Truist Securities. Your line is now open. First, thanks, Travis, for the new format. I think, appreciate it. Travis, my first question is for you or Daniel on, one of the topic deserves that service cost. Specifically, are you able to quantify how your continued operational efficiencies have recently mitigated the your cost? Just wondering how you all think about spot versus long-term contracts in the current environment. You know, I think, Neal, the read through that question is, you know, kinda what the CapEx is gonna look like in the back half of the year. You know, I think there's I'll let Daniel talk about the specific operational efficiencies we've seen, you know, year to date, so that's offset most of the inflationary pressures. When we talk about deflation, it's really, it's raw materials, it's diesel, it's sand, it's steel. Particularly on steel because we're buying our steel needs multiple quarters in advance. We know what that steel cost is, and it's already down for the future purposes, $20-$25 a foot. We've also got, you know, the rigs we've talked about, we're going to drop two rigs, and that allows us to look at our entire rig fleet and the cost associated with those rigs, and we see rig costs are coming down as well. Lastly, while it's not necessarily a CapEx issue, we're seeing improved efficiencies as we've got that second e-fleet that started last week. We've also got rid of our two spot frac crews and replaced them with one simul-frac crew. We're seeing, you know, $10-$20 a foot efficiency gains there as well. Regardless, Neal, of what's going on with CapEx, you know, our commitment has always been to be the low-cost leader, you know, when it comes to prosecuting our development plan out here. We've got now almost a decade of demonstrating that. We anticipate that we're gonna continue to do that, and that's what our shareholders should be comfortable in. Daniel, do you have some additional color for near term? No, I think Travis covered everything that we're, you know, we've kinda seen on the drilling services side and consumable side on the drilling side, that's leading us to see, you know, leading edge costs coming down. Then on the completion side, just with the additional efficiencies from the additional e-fleets as well as the replacement simul-frac fleet replacing the two traditional zipper fleets that we took over as part of the two acquisitions at the end of the year. Great. Thank you for that. My second question for Kaes on shareholder return. Kaes, specifically, it seems you all plan to stick to or you are sticking to that 75% free cash flow payout. Can you give me your opinion on maybe why not pay more like some peers and, you know, on the capital allocation part of the shareholder return, is that planned still, just to see what your stock price is doing versus the mid-cycle, or how do you determine that? Yeah, Neal, you know, we always When we upped the shareholder return program to 75% of free cash flow back to shareholders, we thought the mix of 75% to equity and 25% to the balance sheet was a good mix. We still believe that's a good mix. I think when things are going well, you know, like they have the last couple of years, 75% feels like a max number to go back to equity while continuing to improve the balance sheet. You know, really the test of this new Business model return of capital-based business model is when things go south. In a potential downturn, you know, that's, I think, the time when we should be allocating more capital to buying back shares, reducing the share count a lot more efficiently than it is, you know, even when things are going well, like today. You know, we've kept a flexible return of capital program since the beginning. I think we like that, wanna keep that. Q1 is an exact reason why we maintain that flexibility. We don't wanna blow out the balance sheet to buy back stocks, but we also recognize that when your stock's down significantly in a quarter, a variable dividend doesn't matter. That's what we did in Q1 and allocated a lot more cash to the buyback. We're glad to see it. Thank you all. Thanks, Neal. Thank you. One moment for our next question. Our next question comes from the line of Neil Mehta of Goldman Sachs & Co. Your line is now open. Good morning, team, again, thanks for the new format. The first question was around gas price realization, obviously they were softer in the quarter. There's some one-time dynamics it felt like, you know, just you're curious on your views on how local gas pricing is gonna play out here, what protections you guys have built in place in order to mitigate pricing negativity. Yeah, Neil Mehta, good question. I think it's two things, right? There's certainly the unhedged realized gas prices for us that were weaker in the quarter relative to the expectations. You know, really a lot of that comprised a $15 million true-up payment between a contract that moved from selling at the wellhead to, you know, taking in kind rights downstream. It's kind of an intercompany issue, but I recognize it did hit gas prices for the quarter. You know, what we've done from a hedging perspective and from a physical perspective to protect against future gas price blowouts in the basin, which we think, you know, there's gonna be periodic points of weakness throughout this year and next. You know, we've hedged all of our Waha exposure in the basin, which is about 2/3 of our gas through the end of 2024. The other 1/3 of our gas gets a combination of Henry Hub and Houston Ship Channel prices. You know, on the Henry Hub side, we have protected with, you know, wide collars with a $3 floor, about 2/3 of our gas this year in 2023 and probably 1/3 of it next year. In general, you know, I think we try to give the Street some guidance on future unhedged gas realizations and the hedging piece is has been a tailwind for us as gas prices weaken both at Henry Hub and in the basin. Thanks for that, Kaes. Just follow up on some of the recent acquisitions that you've done here that you've had them in your portfolio now for a couple months. Just any update on how they're executing, early thoughts on productivity and efficiencies that you're able to realize out of the new assets? Yeah, you know, that's a great question as well. I would say generally, you know, Lario, we knew, we knew what we were getting. You know, that asset is nearby all of our existing, production in Martin County, so you know that's as advertised. I think at the end of the day, when we look back at the FireBird acquisition in a few years, that's gonna be one of the better value deals, you know, we got. We estimated there's almost 500 locations on that acquisition without even pushing the limit on upside locations. There's been some well tests where we've co-developed the Lower Spraberry and the Wolfcamp A on the southern part of the position that gives us confidence that some of those upside locations are gonna become, you know, real locations that we're gonna develop over time. You know, second to that, the ops team, you know, they're going into a new area. We're already completing or drilling a 15,000 foot lateral in sub 10 days on the new field. Everything is going well on both those deals. I would say generally over time, Firebird will prove to be one of the better deals we did, because of the amount of acreage that came with it and the upside from a geologic perspective. Awesome. Thanks, Kaes. Thank you. Thank you, Neil. One moment for our next question. Our next question comes from the line of Arun Jayaram of J.P. Morgan Securities LLC. Your line is now open. Good morning, guys. We do appreciate the new format. It was really helpful. My first question is on CapEx. Your first half CapEx guidance plus, you know, the 1Q actuals implies around $1.36 billion in spending or about 52% of the budget. You know, you talked about having line of sight to some meaningful declines in service costs. I was wondering maybe, Kaes, if you could describe, you know, your confidence on hitting call it the midpoint of the range of $2.6 billion for the full year. Yeah. your cash... You know, I know you account for CapEx on a cash basis versus accrual basis. How does that influence the timing of CapEx in a rising service price environment versus when it's falling? Yeah, good question, Arun. You know, on the cash CapEx thing, you know, the prime example was Q2 of 2020. While I don't wanna relive that particular quarter, you know, we reduced our rig count from 15 or 23 rigs down to six, and we had to pay for that in the second quarter. There was a big disconnect between accrued and cash CapEx. That's not the issue we face here, right? We're talking about things at the margin, like a $50 million or so reduction in run rate CapEx, which is in my mind, very achievable based on three things. You know, lower activity, we're gonna reduce our rig count by two rigs, as expected, you know, end of this quarter through the back half of the year. Second, you know, lower service costs and, you know, Travis broke those down into the drilling side, which is a significant reduction in raw materials and a smaller reduction in the service piece of the drilling side. On the other side of that DC&E line completions, you know, down because of efficiencies, because of the high grading to two ZEUS fleets with Halliburton and two simulfrac fleets. Lastly, you know, midstream infrastructure. We spent a lot of money on midstream building out our Martin County water system, that's nearing its end so that the whole system is connected, and infrastructure, you know, generally slows down in the back half of the year. You know, that's the line of sight we have. I feel very confident that those things are coming our way based on what we can see in the accrued numbers that we pay for over the next 45 - 60 days on the cash side and CapEx. Yeah. Just again, to, Arun, to reiterate my opening comment, to the first question, is that our commitment to our shareholders remain unchanged to be the low-cost leader, in efficiency and in execution. That's certainly been our track record, and that's what we anticipate going forward. Our commitment hasn't changed regardless of what CapEx does. Great. Thanks a lot, Travis. My follow-up, team, we've heard about some industry activity in leasing in the Midland Basin in deeper zones. Can you remind us how your leases are structured? Do you have rights to those zones currently? Perhaps, you know, this obviously could have some positive implications for Venom. I was wondering if you could maybe talk about how FANG's leases are structured and maybe positive implications for Venom. Yeah. There's really no one size fits all to leases in the Midland Basin. You know, I would say generally, we have most of our leases cover the Wolfcamp B, which is a deeper zone that's gonna get a lot more attention over the coming years. Some, you know, a lesser extent, do we have the Barnett and Woodford covered. You know, we've been exploring the Barnett and Woodford on the western side of the Midland Basin for a very long time now with our Limelight play. It seems that the Barnett and Woodford play is going to extend more into the actual basin, and that's something that we're involved in, along with many other large peers, you know, testing that zone and looking at it, you know, for future development in this, you know, the end of this decade and the next decade. I will say, you know, generally, that's the benefit of owning a lot of minerals is that, you know, we have the other side of our business card that is gonna, you know, have a front seat to leasing any of those deeper rights should they be unleased throughout the basin. Great. Thanks a lot. Thank you, Arun. Thank you. One moment for our next question. Our next question comes from the line of Scott Gruber of Citigroup. Your line is now open. Yes, good morning. Turning back to service rates. You know, the service companies have been talking about a bifurcated market here for both rigs and frac pumps. Their characterization is that, you know, the highly efficient crews, the next gen kit, especially, you know, nat gas fueled rigs and pumps, will largely maintain pricing while it's gonna be the legacy equipment and/or lower quality crews, you know, where you'll see the more meaningful declines in rates. Is that how you see the market developing here, or do you see more, you know, more broad-based reductions in pricing kind of across the spectrum? You know, Scott, I think that's partially true. Certainly on the frac side, you know, the higher quality equipment, the super spec e-fleets, you know, those have real contracts associated with them with, you know, less wiggle room on pricing. That's why we think, you know, generally we make more money or save more money there on the efficiency side. You know, on the rig side, I think generally, you know, if 10% of your market is going away in a quarter or two, it's gonna have an impact on pricing. You know, there's just no doubt about that. Leading edge rates certainly are lower. I think we've also proven in the past to, you know, do more with less when it comes to equipment on the rig side, particularly in the Midland Basin, where it's a lot easier to drill in general than other places around the country. Got it. Then just turning to operating costs, you know, LOE came in at the low end of the range, but you kept the full year. Then you mentioned the fixed price contracts for power. Just any color you that you can provide on how operating costs should evolve over the course of the year, given, you know, the outlook for natural gas and power and other things, you know, chemicals, et cetera, that go into operating costs? Yeah. You know, listen, I think, obviously we had a very good start to the year on LOE. We still feel good about the midpoint of that range, mainly because, not because of power, but because of some of our activity is moving to areas where we have water dedicated to third parties, not ourselves. You know, that has a little higher rate, and so we expect LOE to trend up a little bit in Q2, Q3 as some of those big pads on third party areas are developed. You know, generally, we received a benefit in terms of gas prices on the power side to lock in a lot of power. You know, I would say generally we've locked in about 75% of our expected power needs for the foreseeable future. That should keep LOE generally lower for longer and less exposed to the price spikes that we saw last summer. Got it. Appreciate the call, Kaes. Thank you. Thank you, Scott. Thank you. One moment for our next question. Our next question comes from the line of David Deckelbaum of Cowen. Your line is now open. Morning, Travis, Kaes, Daniel and team. Thanks for taking my questions today. Sure. Good morning, David. Morning. Just longer term from an efficiency gains perspective, you all made some headway and you highlighted the benefits of using e-fleets and moving that second e-fleet this year. How do you think about, you know, as we progress into 2024 and 2025, the mix between simulfrac fleets and e-fleets if we assume sort of this flattish rig count? Or is the two - two mix a the expectation for longer term development? Yeah, David, a good question. I think, you know, our plan right now looking out into 2024 and 2025 is probably to stick with the, you know, kinda 50/50 mix. We basically have to underwrite the E fleets and sign up for a longer term commitment with them, you know, which is a little harder to do a 100% of your capacity committed for a long, you know, long-term commitment. The additional, you know, simulfrac fleet as more E fleets come to market and are available in a, I guess, spot basis, we would certainly migrate to more E fleets that we'd have some flexibility around utilization. Got it. My, my second question is around asset sales. You already did around $773 million or so to date. You point out that you've exceeded your target. You guys also highlight the remaining, you know, five or so outstanding investments that you're articulating on the slide deck in the back, mostly on the midstream side. Might be a source of funds going forward. Is there a high probability that we'll see another asset sale this year? I would place a pretty high probability on that, David. You know, we wouldn't have increased our target from $500 million - $1 billion of non-core divestitures if we didn't have, you know, pretty good line of sight. You know, I can't, I can't guarantee it's gonna happen today, but certainly there's a few things in the works, you know, either on the JV side or, you know, on some of the small operated midstream assets that could be up for sale. We still feel very comfortable with that billion-dollar target. I would just say it's tailored more towards midstream versus upstream. Appreciate it. Thanks for the time, guys. Thank you. Thank you. One moment for our next question. Our next question comes from the line of Roger Read of Wells Fargo Securities. Your line is now open. Roger, you're on mute if you're on the line. Joey, let's move to the next question, please. One moment for our next question. Our next question comes from the line of Kevin MacCurdy of Pickering Energy Partners. Your line is now open. Hey, good morning. With the 1Q release, you've kinda given the pictures to figure out what the 4Q 2022 or 2023 CapEx and activity is. As we look into potential 2024 maintenance CapEx program, is the 4Q activity kind of a good activity in CapEx a good starting point, or would you need to add any activity to keep production flat next year? Well, that's a good question, Kevin. You know, I'm not totally ready to commit to 2024 today, you know, I would say if we had to commit today, you know, running some sort of plan with four simulfrac crews is probably the most efficient and capital efficient plan we could put together. You know, whether that spits out slight growth to flat production is to be determined. You know, I think generally, you know, running this capital efficient plan without changing activity levels too much and letting growth be the output has been, I think rewarded, you know, over the last couple of years with this new business model, and that's kind of where we're circling things going forward. Great. That's the only question for me. Thanks, guys. Thank you, Kevin. Thanks, Kevin. Thank you. One moment for our next question. Our next question comes from the line of Derrick Whitfield of Stifel. Your line is now open. Good morning, all, and congrats on a strong start to the year. Thank you, Derrick. Thank you, Derrick. Building on an earlier question on Waha price weakness, could you perhaps elaborate on the degree of tightness you're projecting with in-basin fundamentals? Yeah. Derrick, good question. You know, I think generally, you know, we're gonna see very, very a lot of volatility and some pockets of extreme weakness. You know, obviously there's a few expansions coming on, three expansions, you know, the back half of this year and the beginning of next year ahead of a large fleet coming on at the end of 2024. You know, I just think the issue to date had been masked in the field as processing capacity in the field was short. Now that that processing capacity is coming on, you know, to the tune of a BCF a day or more, you know, that's gonna push the problem downstream to the downstream residue pipes. I think it's coming. It's gonna be, you know, pretty weak for periods, and then pressure will be relieved a little bit when these expansions come on. Generally, you know, our take is let's remove our risk to that pricing weakness by hedging everything through 2024 and getting more physical molecules to the Gulf Coast. You know, ideally, we'd like to have control of all of our molecules to the Gulf Coast, but most of our contracts we inherited, you know, from deals that we've bought have not come with taking kind rights, and we've worked to improve that over time and control more of our molecules further downstream. Great. As my follow-up, I wanted to touch on well productivity, which is, has been a positive development for you guys. Referencing slide 14, could you speak to your expectations for 2023 well productivity relative to 2022? How does that project over the next couple years as you think about the integration of Lario and FireBird acquisitions? Yeah, good question. You know, I think we said, and we've said multiple times to investors, you know, flat to 2022 is probably the base case, and if we do a little better, that's one for the good guys. I think we're on pace for that, you know, particularly in the Midland Basin, where we've had a really strong start to the year. I would just say Firebird and Lario only enhance that, you know, ability to do that for longer. You know, at the end of the day, you know, as we've said before, the shale cost curve is going up. It's our job to make sure we have the inventory duration and the cost structure to be at the low end of that shale cost curve, which we've done well for the last 10 years, and we expect to do well for the next 10 years. Well done, guys. Derrick, I think just to reiterate that point that I've made a couple of times now about, you know, Diamondback's commitment to our shareholders about maintaining the lead and efficiency and cost execution. You know, it's exactly what Chase just said. Thanks for the added color, Travis. Thank you. One moment for our next question. Our next question comes from the line of Scott Hanold of RBC Capital Markets. Your line is now open. Hey, thanks. Could you all provide a little bit of color on the cadence of activity, you know, moving forward? I mean, you all talk about having some larger pads, you know, going forward. You know, and you all have had a very, you know, smooth production trajectory. Do some of these large pads, will that create some lumpiness, or is there some timing considerations we need to think about as we see those being developed? Yeah, good question, Scott. I would say, internally, it certainly does. You know, this business is not easy to grow consistently and, you know, hit numbers consistently. Externally, you know, we think we're gonna grow, you know, fairly smoothly organically through the back half of the year. You know, in general, our target is to, you know, turn about 85 wells to sales a quarter. You know, some quarters are gonna be a little higher, some are a little lower based on timing. You know, in general, that's our job, right? It's, there's a lot going on beneath the surface, and that's what makes the Diamondback operations team the best in the business. Great. Then if we could talk about M&A a little bit, it looks like, you know, some of the, you know, private equity companies are, you know, dropping rigs in the Permian. Obviously there have been some sales and talks of more sales coming up. Like, what are you all seeing, you know, on the private side in terms of activity and, you know, what's your interest level in, you know, looking at some of these additional M&A opportunities? Yeah. We've commented a couple of times about the increase in activity through 2022 was largely driven by independence. You know, the challenge there is depth of inventory, right? And the secondary challenge is, you know, how much can an increase, you know, further beyond their max cadence that they achieved last year. I think both of those are playing out now. The max cadence may be softening, as you see by rigs getting laid down. Certainly the inventory depth is, you know, is getting accelerated, you know, with this rapid pace of bringing wells to production. I think, you know, from an M&A perspective, it's gonna be an interesting time over the next couple of years, as these entities, the small ones, privates, try to figure out a way to monetize. I think you've also got, you know, while the catalyst is unclear, you've also got, you know, some small cap public companies that are gonna need to figure out some form of exit strategy to continue to be relevant in the future. There's always the large, you know, private unicorns that still float around out there as well too. I really think the next couple of years are gonna be interesting in the M&A landscape. Yeah. Do you believe, though, that, you know, some of these private equities that have burned through a lot of their acreage, does that make it, you know, does the inventory factor make it less interesting to you all, or is there a case to be made if you can buy PDPs cheap enough and, you know, kind of manage them down, you know, their own interest? You know, Scott, when you do M&A, and if you do it correctly, you want to extend inventory life. You wanna, you know, make sure that your, you know, your free cash flow or cash flow accretive, and you don't want to impact your balance sheet. you know, just doing PDP type acquisitions, you know, doesn't necessarily fit into that calculus. you know, it's I think that's what you're gonna end up seeing with some of these exit strategies, are just kind of straight PDP divestitures. Fair enough. Thank you. Thank you. Thanks, Scott. One moment for our next question. Our next question comes from Jeoffrey Lambujon of TPH. Your line is now open. Good morning, everyone, and thanks for taking my questions. Good Jeoffrey. My first one is just on commentary in the supplemental release that talked about the trend continuing this year in terms of the large, high NRI pads coming on in the Northern Midland Basin. Is there any additional color you can give there in terms of how the mix of the total program going to that type of acreage, where you might have, you know, much less surrounding development compared to that same mix or weighting to that type of acreage last year and just how to think about that mix over the near term? Yeah. It's a good question, Jeoffrey. I would say, you know, the mix of undeveloped DSUs is probably similar to years past. The quality of the location of those undeveloped DSUs is probably a little bit higher this year than in 2022 even. You know, it's kind of related to our comment on productivity. You know, there's certainly a line of sight to, you know, very high productivity this year from development in the middle of Martin County. Some of that, you know, we have up to 6% or 7% NRI on, you know, large pads at the Viper level. You know, because we report consolidated financials, you know, that is a benefit to the total enterprise, where, you know, that high NRI development is gonna drive organic production growth at the entity. Great. appreciate that. On the services side, you know, certainly appreciate the detail just around where you see potential improvements and the timing around that throughout the year. I was just hoping you could speak maybe high level to how your contracts are set up, I guess, across the services spectrum, just to give a sense for, you know, how some of these improvements, will layer in for Diamondback, specifically over the course of the next couple quarters. Yeah. I think on the rig side, you know, everything's kind of a rolling three-six month contract. We see. You know, we can see that our Q2 average day rate is down from Q1 today. That's gonna continue to come our way on the rig side. On the frac side, you know, our two e-fleets on the simulfrac e-fleets are pretty locked up on pricing. I would say, you know, we saw some weakness in the spot frac pricing in Q1 versus Q4. You know, as we move those other two fleets to simulfrac fleets, you know, I think the more the benefit will be on the efficiency side than the price per horsepower side. Generally, a simulfrac fleet saves us $20 or $30 a foot, you know, regardless of the price of the actual horsepower. You know what, Jeoffrey in addition to that, we talked earlier about, you know, purchasing steel multiple quarters in advance. We're seeing the steel that we're purchasing for our 3Q, 4Q, 1Q costs, you know, already coming down. While it's not necessarily a service cost deflation, it is a cost deflation that's, you know, could be as much as $20 or $25 a foot, additionally. Appreciate it, guys. Thank you. Thanks, Jeoffrey. Thank you. One moment for our next question. Our next question comes from the line of John Freeman of Raymond James. Your line is now open. Good morning, guys. Hey, John. Y'all are the... In fourth quarter, when y'all were running ahead of schedule and you moved some of those pops from the fourth quarter into the first quarter, and just given all the commentary on the big efficiency gains on the simulfracs as you now go to toward four with simulfrac abilities, if we end up in a similar spot where you have efficiency gains later this year, is it likely that y'all would, and again, it's a first-class problem, but would you similarly make a decision like last year where you would, you know, sort of, I don't know, pump the brakes is the right word, but maybe slow down a touch so that the budget is intact? Or do you just sort of, you know, plow ahead with the efficiency gains and just bring more wells online? I think we're highly incentivized to hit the budget. I think, you know, highly incentivized to increase free cash flow, which is part of the new business model, which issues growth for returns. That's been the mentality, and it's been a working mentality, a mentality that has worked for the last couple years. You know, it would be a first-class problem. We're still early in the year, but generally, that would be the plan. Now, I think the only nuance to that is, you know, we would like to keep rigs running and building DUCs, you know, particularly if rig costs are a little bit lower than they are today That's great. Really appreciate all the detail and color y'all have given on there. The service cost front. Does it sound like, obviously, things are coming down from the peak levels of 1Q? Are y'all basically indicating that y'all are on track to potentially have lower? Total completed well cost by year-end 2023 versus year-end 2022. Like, when you factor in what you're seeing on the cost side, but maybe more importantly, the efficiency gains from the simulfracs? Yeah, I would say yes, that's a fair answer. I mean particularly, you know, listen, steel is the biggest driver. You know, I'm not forecasting a total capitulation in service costs here. You know, when steel went up for nine quarters in a row to over $110 a foot, you know, we see in Q3 our steel costs are gonna be closer to $90 a foot. I mean, that in itself makes up for a significant percentage of the savings. I would say yes, Q4 2023 well costs below Q4 2022, because generally Q4 2022 and Q1 2023 were the highest. That's great. Appreciate it, guys. John, listen, just to reemphasize, we run the business to maximize efficiency as well. Kaes made the point that whether it's on the rig side or the completion side, you know, we're about efficiency because we think that that's the greatest driver of shareholder value in a business where you don't control the price of the product that you produce. Thanks, Travis. Thank you. One moment for our next question. Our next question comes from the line of Tim Rezvan of KeyBanc Capital Markets. Your line is now open. Good morning, folks. Thank you for taking my question. I wanted to circle back David's questions previously on asset sales. I'm sure you won't give a good answer on the Bloomberg story about Pecos County, but I think it highlights the, you know, the number of levers that you can pull to get, you know, to $1 billion or more on asset sales. Trying to understand, Kaes, you know, what do you think a good, you know, kind of target debt level is? Do you think about it in terms of leverage or an absolute debt metric, you know, as you compare yourselves to the large cap peers? I guess, you know, why wouldn't you go bigger than that $1 billion, given you're not allocating a lot of capital to the Delaware right now? Yeah, Tim, that's a good question. We're not gonna go bigger 'cause we wanna beat the number, first of all. You know, second to that, listen, the Delaware Basin overall still produces a lot of barrels and a lot of cash flow for us, and that's important to, you know, the credit ratings. It's important to our, you know, our free cash flow forecast, you know, and all the above. I think, you know, we have sold a few small things in the Delaware on the acreage side. The recurring theme of what we sold is that someone paid for upside. You know, we're not gonna sell PDP cheap just to sell PDP. At the end of the day, someone has to pay for upside and pay for a faster pace of development than we're expecting. That, I think, you know, has been a common theme in the Delaware deals as well as the deal in Glasscock County. Not only did they pay for PDP, but they paid for some PUDs, you know, that didn't compete for us in the next 10-year plan. If that happens, then we'll look at, you know, do what's right for our shareholders and look at divesting more in the Delaware Basin. Generally, you know, that production and cash flow has a lot of value to us today. Okay. Just getting back to that number, you know, in an ideal world, you know, how do you think about what the right debt number is, whether either in debt or in leverage terms, you know, versus where you are today? Yeah, good question. Sorry, I apologize. I forgot to re-reply to that part of the question. I think we think about debt in terms of two ways to think about it, right? Not only, you know, absolute debt and the leverage ratio but also duration. You know, I think we obviously want less debt over time, but we feel comfortable with the amount of duration we have between now and our next maturity, which is 2026. I'd like to take that out so that Travis won't bother me about it until 2029. You know, but when we have excess free cash flow, we're gonna use it to reduce absolute debt. I think in a perfect world, a turn of leverage at a $55 or $50 oil price would be, in my mind, you know, an ideal debt level with no debt due for multiple years before your next maturity. Okay. I appreciate the color. That's all I had. Thanks. Thanks, Tim. Thank you. One moment 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 to the rest of the Diamondback team there. Hey, Charles. Good morning, Charles. Travis, this may be for you. Yeah, I like the new format as well, but I was also thinking about the shareholder letter. You know, Travis, in your prepared comments, I think you said you were hoping this format would be more efficient, you know, to pick up on a big theme for you this morning. I found myself wondering also, does this, you know, the iteration on your communication style, I mean, does this also reflect an element of maybe dissatisfaction with how either your story is being understood or the traction that you're getting, or that you maybe feel like you should be getting that you're not? If that is true or if that's the case that there's some element of it, what do you think the market might be missing? No, we didn't put this letter in place trying to fix the communication issue. We've got, you know, incredible transparency communication, format that we, that we have with our shareholders. We just thought that, you know, based on a decade of doing these earnings calls and the lack of attention really paid in the prepared remarks, felt like we could remove that. We also know that other industries are well ahead of the oil and gas sector by not doing prepared remarks. The other thing is that we could communicate more in this shareholder letter than what we traditionally would put in a truncated CEO quote in the earnings release. Then we didn't have to have anybody, you know, spending Sunday night, you know, preparing our transcript either as well, too. I mean, from a staff perspective, it was a lot more efficient there. No, that's we did this because we think it's a better way to communicate, not that we need to improve the message or the understanding in our stock price. I think it also allows us to talk directly to our shareholders, right? Because, you know, a lot of the times, you know, the sell side is in control of the narrative, and this allows us to tell a little bit of the story behind the numbers directly to our shareholders. Insight into your thinking. I appreciate that. Kaes, I wanna go back to the question on the buybacks. I know this has been addressed at least in one other, earlier question. All other things being equal, and I know, I recognize they never are, but all other things being equal, the shift to buybacks that we saw in 1Q, does that, does that kind of signal a durable shift? Or if not a durable shift, a durable change in the preference towards buybacks? You know, listen, I think our preference has always been to buy back shares. What we wanted was a governor on what fundamentally are we buying back shares for? Are we buying back oil in the market cheaper than we can buy it in the ground? That's our NAV versus looking at a deal like Lario Over FireBird, you know? At the end of the day, we're still gonna run our NAV at a conservative mid-cycle deck, which is $60 oil. The market has presented us opportunities to buy back shares every quarter since we started this buyback program. At the end of the day, our, again, our preference is buybacks, but we have a little bit of a governor on, you know, what share price we're going to be aggressive on, and Q1 was the perfect example of that. Charles, we've tried to be mindful of sins of the past our industry has been known for, which is oil price goes high, free cash flow goes up, and share repurchases are done, you know, not countercyclically, like we're trying to do so, but in cycle with higher oil prices, and that hasn't created a lot of value. You know, we may not always be perfect in that calculus, but as Kaes pointed out, whether it's the banking crisis here recently or other forms of volatility, we've had an opportunity to purchase $2 billion worth of shares back at, you know, roughly $120 a share. We feel like we're following through on our commitment of not only being flexible in our return program, but also being mindful of, you know, the method and the timing at which you repurchase shares. Thank you, gentlemen. Appreciate the color. Thanks, Charles. Thank you. One moment for our next question. Our next question comes from the line of Roger Read of Wells Fargo Securities. Your line is now open. Yeah. Thank you. Good morning. Morning, Roger. Hey, Roger. Let's go back and kinda dig into the service cost and, or deflation, I guess we could call it at this point. We got so used to using inflation. Can you talk to us a little bit as you think about well costs being lower in the fourth quarter, how much of that is efficiencies and how much of that is, you know, just a decline in the cost of doing something, being drilling rigs or whatever? 50/50. Well. ... 60/40, 80/20, something like that is what I was curious about. Yeah, I would say it's a quarter efficiencies and 75%, actual costs. Of the 75%, I would say two-thirds of that is due to raw materials and the other third is due to the actual service piece of the equation. Okay. Yeah, that's helpful. The other follow-up question I had was, is there any sort of rule of thumb approach you use as you switch to E fleets or as you went from, you know, the Zipper frac to the simul-frac in terms of, however you wanna think about it, stages per day, cost per stage, something like that? Again, just trying to understand some of these changes as they get applied all across the entire complex. Yeah. I'll give you the cost estimates, and Danny can give you the efficiencies. You know, I'd say generally, a simul-frac fleet is $20-$30 a foot cheaper than a conventional fleet, and an e-fleet is $20-$30 a foot cheaper than a simul-frac fleet. I mean, e-fleets we're utilizing are simul-frac fleets. They're just, you know, powered with, you know, electric power that we generate on location or that we pull off the grid. You know, really the savings on the e-fleet comes from, comes from the fuel consumption piece and just being more efficient on location. We do think we see a little bit of disparity between the kind of lateral footage completed per day by the e-fleets versus the, you know, diesel simul-frac fleets. We don't have a just ton of data yet to quantify that. We're, you know, we are hopeful that over time, the e-fleets will kind of widen the gap of execution efficiency. Just because of the, you know, lower maintenance and R&M stuff that's required on location. The difference between zipper and simulfrac in terms of footage per day, do you have? Yeah, I mean, we kinda say a simulfrac fleet, depending on the jobs, can do about twice as much lateral footage per day as a traditional zipper fleet. Yeah. Very, very large differences. One just little clarification on your comment at the very beginning about, you know, locking in some of your electricity costs, being able to, you know, predict your LOEs a little better, during the summer. Is there any interruptible risk with those contracts? I mean, I'm not talking outages, which would affect everybody, but just, you know, that to get the lower cost or a fixed cost, you have to accept, you know, the risk of being turned off. No. No, it's just a hedge in the market. It's just a financial hedge, not a physical trade. Great. Thank you. Thank you. One moment for our next question. Our next question comes from the line of Leo Mariani of Roth MKM. Your line is now open. I just wanted to follow up quickly on LOE. Just wanted to clarify one of your earlier comments. It sounds like you guys are expecting LOE per barrel to climb here, you know, in 2Q and 3Q versus where you were in 1Q. Just wanted to make sure I sort of heard that right? No. We expect it to go up to the midpoint of guidance from $5 to midpoint of $5-$5.50. Going up slightly due to third party water handling. Okay. You're viewing that as somewhat temporary just based on where the rigs are gonna be, sort of be drilling, you know, location-wise here, in the middle part of the year? Yeah, it just depends upon where the completions are. If the completions are on a third party dedicated piece of acreage, the cost is higher than it would've been on a prior Rattler dedicated piece of acreage. Right. Okay. Just on cash taxes. You know, looking at first quarter, you guys kinda came in below the guidance. You know, so far, I guess quarter to date here in 2Q, you know, commodity prices are kind of flat to down. You guys are expecting cash taxes to kind of increase here, you know, in 2Q, you know, per the guidance. Just wanted to kinda get, you know, a little bit more color in terms of how the year plays out. I mean, you generally see cash taxes increasing throughout the year, and then maybe that just has to do with NOLs that are, you know, completely disappearing, your other tax shield that disappears. Any other color kind of around that cadence of cash taxes as the year progresses? Yeah. I think the only real added benefit that Q1 had versus Q2, even in, if c-commodity prices were flat, is that we closed Lario in the quarter and got to, you know, write off some of that, the hard assets that came with that right away. All right. Sounds like it's just M&A driven on the tax shield side, and now maybe 2Q is more of a normal representative rate going forward. That's fair. Okay. Thank you. Thank you. One moment for our next question. Our final question comes from Paul Cheng of Scotiabank. Your line is now open. Thank you. Good morning. Good morning. Just want to add my appreciation with the new format. I think it's great. Two question, please. First, you've been increasing your overall activity in the Midland over the last several years. Now you have 85/15% between the two. Should we assume this is going to be pretty steady and stable for the next several years or that you may start to doing more Delaware, say, maybe sometime over the next one or two years? I think over the next few years that the 85/15 is a very fair yearly estimate. You know, obviously some quarters will be higher than others. We wanna continue to complete multi-well pads in the Delaware. You know, you have a quarter like Q1 of 2023, which was higher Delaware when Q4 was, you know, zero wells in the Delaware. On an annual basis, 85/15 feels like the right lateral footage mix. Okay. The second question is that you talk about the budget. You feel very comfortable about the midpoint for the full year. Just curious that, in that budget, how much is the cost saving or that the, you're talking about the line of sight of costs coming down. How much of them is already originally built into that budget? In other words, will that say a reasonable probability you're actually going to be below the midpoint of your budget and not? You know, I don't know if I'm ready to commit to that today, Paul. You know, we certainly have some work to do, but, you know, we have very good line of sight from an activity and a cost perspective that, you know, we've seen the peak in well costs and, you know, a little bit of a tailwind from the activity of two rigs coming down now. You know, I think that'll happen a little bit in Q3 and more in Q4, but, you know, it's still early. Mm-hmm. Okay. Can you share with us that, I mean, how much of the saving you originally built in, or how much is the deflation in the second half that you have built into your budget? I would say if we saw more service cost deflation, that would be upside to what we've modeled here. I see. Okay. True, true service, not raw materials. Okay. Will do. Thank you. Thank you. Thank you, Paul. This concludes our Q&A session. I would now like to turn it over to Travis Stice, CEO, for closing remarks. Thank you for joining us this morning. I think another benefit of this new format is to allow more questions based on the amount of questions we had this morning. If you have any additional follow-up that you need, just reach out to us using the numbers that we provided earlier. Thanks again for joining. Have a great day.