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spk09: Good day and 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 1-1 on your telephone, and you will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1-1 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 Lawless, Vice President of Investor Relations. Please go ahead.
spk25: Thank you, Joanne. Good morning, and 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 Dice, Chairman and CEO of Case Mantoff, President and CFO, and Danny Watson, 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 gap measures can be found in our earnings release issued yesterday afternoon.
spk24: I'll now turn the call over to Travis Stutz. Thank you, Adam. And 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. So we'll move right into questions. Operator, if you would open the line and begin with our first questions.
spk09: 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 Neil Dingham of Truist Securities. Your line is now open.
spk41: First, thanks, Travis, for the new format. I appreciate it. Travis, my first question is for you or Danny on one of the topic visitors, that service cost. Specifically, are you able to quantify how your continued operational efficiencies have recently mitigated your cost? And I'm just wondering how you all think about spot versus long-term contracts in the current environment.
spk24: I think, Neil, the read-through to that question is kind of what the CapEx is going to look like in the back half of the year. And I think there's – and I'll let Danny talk about the specific operational efficiencies we've seen year-to-date that's offset most of the inflationary pressures. But 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. So we know what that steel cost is and it's already down, for the future purposes, $20, $25 a foot. And then we've also got the rigs. We talked about we're going to drop a couple of rigs and that allows us to to look at our entire rig fleet and the cost associated with those rigs, and we see rig costs are coming down as well. And then 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, and we've also got rid of our two spot frack crews and replaced them with one simul-frack crew, so we're seeing, you know, $10 to $20 a foot efficiency gains there as well. So regardless, Neil, of what's going on with CapEx, our commitment has always been to be the low-cost leader when it comes to prosecuting our development plan out here, and we've got now almost a decade of demonstrating that. So we anticipate that we're going to continue to do that, and that's what our shareholders should be comfortable in. Danny, do you have some additional color for near-term?
spk26: No, I think Travis covered everything that we've kind of seen on the drilling services side and consumable side on the drilling side that's leading us to see leading edge costs coming down. And then on the completion side, just with the additional efficiencies from the additional E-Fleet as well as the replacement, simultaneously replacing the two traditional E-Fleets. zipper fleets that we took over as part of the two acquisitions at the end of the year.
spk41: Great. Thank you for that. And then my second question for Kay is on shareholder return. Kay, 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 plan still just to see what your stock price is doing versus the mid-cycle or how do you determine that?
spk30: Yeah, Neil, you know, we always kind of, when we upped the shareholder return program to 75% of free cash going back to shareholders, we thought the mix of 75% 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, to equity while continuing to improve the balance sheet. Really, the test of this new business model and return of capital-based business model is when things go south. In a potential downturn, that's, I think, the time when we should be allocating more capital to buying back shares and reducing the share count a lot more efficiently than it is even when things are going well like today. We've kept a flexible return of capital program since the beginning. I think we like that and want to keep that, and Q1 is an exact reason why we maintain that flexibility. We don't want to blow out the balance sheet to buy back stocks, but we also recognize that when your stock's down significantly in a quarter, variable dividend doesn't matter. That's what we did in Q1 and allocated a lot more cash to the buyback.
spk42: We're glad to see it. Thank you all. Thanks, Jim.
spk09: 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.
spk46: Yeah, good morning, team, and again, thanks for the new format. The first question was around gas price realizations. Obviously, they were softer in the quarter. There's some one-time dynamics, it felt like, but, you know, just if you're curious on your views on how local gas pricing is going to play out here and what protections you guys have proposed built in place in order to mitigate pricing negativity?
spk30: Yeah, Neil, 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. Really, a lot of that comprised a $15 million true up payment between a contract that moved from selling at the wellhead to taking on our taking kind rights downstream. So 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 going to 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 two-thirds of our gas, through the end of 2024. And then the other one-third of our gas gets a combination of Henry Hub and Houston Ship Channel prices. And then, you know, on the Henry Hub side, we have protected with, you know, wide collars with a $3 floor, about two-thirds of our gas this year in 2023 and probably a third of it next year. So, in general, you know, I think we try to give the streets some guidance on future unhedged gas realizations, and the hedging piece has been a tailwind for us as gas prices weaken both at Henry Hub and in the Basin.
spk46: Thanks for that case. And then just follow up on some of the recent acquisitions that you've done here. 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?
spk30: Yeah, that's a great question as well. I would say generally, Larry, 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. And I think at the end of the day, when we look back at the Firebird acquisition in a few years, that's going to 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. And there's been some well tests where We've co-developed the Lower Sprayberry and the Wolf Camp A on the southern part of the position that gives us confidence that some of those upside locations are going to become real locations that we're going to develop over time. Second to that, the ops team, 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. So 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.
spk49: Awesome. Thanks, guys.
spk09: Thank you.
spk49: Thank you, Neil.
spk09: One moment for our next question. Our next question comes from the line of Aaron Jirem of JP Morgan Securities LLC. Your line is now open.
spk43: 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 the 1Q actuals implies around $1.36 billion in spending. or about 52% of the budget, you talked about having line of sight to some meaningful declines in service costs. So is there maybe a case if you could describe your confidence on hitting, call it the midpoint of the range of $2.6 billion for the full year? And how does your cash, 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?
spk30: Yeah, good question, Arun. You know, on the cash CapEx thing, you know, the prime example was Q2 of 2020. Well, I don't want to 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. So there's a big disconnect between accrued and cash CapEx. Now, 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 going to 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. And on the other side of that DC&E line, completions down because of efficiencies, because of the high grading to two Zeus fleets with Halliburton and two Simulprac fleets. And lastly, 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 generally slows down in the back half of the year. So 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 to 60 days on the cash side and CapEx.
spk24: Yeah, and just again, 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. And That's certainly been our track record, and that's what we anticipate going forward. But our commitment hasn't changed regardless of what CapEx does.
spk43: 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? And perhaps, you know, this obviously could have some positive implications for Venom, so I was wondering if you could maybe talk about
spk30: um how fangs 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 um we have most of our leases covered the wolf can't be which is a deeper zone that's going to get a lot more attention over the over the coming years and and some you know lesser a lesser extent do we have the uh barnett and woodford covered now you know we've been exploring the barnett and woodford on the eastern 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 and, 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 going to, 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.
spk09: 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.
spk33: Yes, good morning. Turning back to service rates you know the service companies have been talking about a bifurcated market here uh for both rigs and frac pumps and their characterization is that you know the highly efficient clues the next gen kit especially in that gas fuel rigs and pumps will largely maintain pricing while it's going to be the the legacy equipment and or lower quality crews you know where you where you'll see the the more meaningful declines in rates Is that how you see the market developing here, or do you see more broad-based reductions in pricing kind of across the spectrum?
spk30: 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. So 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 going to have an impact on pricing. You know, there's just no doubt about that. So, you know, 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.
spk33: Got it. And then just turning to operating costs, you know, LOE came in at the low end of the range. We kept the full year. And then you mentioned the fixed price contracts for power. Just any color 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?
spk30: 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. And so, 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. But, 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.
spk31: Got it. Appreciate the call, guys. Thank you.
spk27: Thank you, Scott.
spk09: Thank you. One moment for our next question. Our next question comes from the line of David Deckelbaum of Cohen. Your line is now open.
spk52: Good morning, Travis, Casey, Danny, and team. Thanks for taking my questions today.
spk22: Sure. Good morning, David.
spk52: Good 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 24 and 25, the mix between Simulfrac fleets and E-Fleets if we assume sort of this flattish rig count, or is the two-to-two mix the expectation for longer-term development?
spk26: Yeah, David, good question. I think, you know, our plan right now looking out into 24 and 25 is probably to stick with the, you know, kind of 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 100% of your capacity committed for a long-term commitment, but The additional, you know, simulfrac fleet, as more E-Fleets come to market and are available in a, I guess, spot basis, we will certainly migrate to more E-Fleets that we'd have some flexibility around utilization.
spk52: Got it. And then 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 five or so outstanding investments that you're articulating on the slide deck in the back, mostly on the midstream side. It might be a source of funds going forward. Is there a high probability that we'll see another asset sale this year?
spk30: Yeah, I would place a pretty high probability on that, David. We wouldn't have increased our target from $500 million to $1 billion this of non-core divestitures if we didn't have, you know, pretty good line of sight. You know, I can't guarantee it's going to happen today, but certainly there's a few things in the works, you know, either on the JV side or, you know, some of the small operated midstream assets that could be up for sale. So we still feel very comfortable with that billion-dollar target. I would just say it's tailored more towards midstream versus upstream.
spk52: Appreciate it. Thanks for the time, guys. Thank you.
spk09: Thank you. One moment for our next question. Our next question comes from the line of Roger Reed of Wells Fargo Securities. Your line is now open.
spk37: Roger, you're on mute if you're on the line.
spk36: Let's move to the next question, please.
spk08: One moment for our next question.
spk09: Our next question comes from the line of Kevin McCurdy of Pickering Energy Partners. Your line is now open.
spk29: Hey, good morning. With the 1Q release, you've kind of given the pictures to figure out what the 4Q23 capex and activity is. As we look into a 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?
spk30: That's a good question, Kevin. I'm not totally ready to commit to 2024 today, but I would say if we had to commit today, running some sort of plan with four simulfrac crews is probably the most efficient and capital efficient plan we could put together. Now, you know, whether that spits out slight growth to flat production is to be determined. But, 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 years with this new business model. And that's kind of where we're circling things going forward.
spk28: Great. That's the only question for me. Thanks, guys. Thank you, Kevin. Thanks, Kevin.
spk09: Thank you. One moment for our next question. Our next question comes from the line of Derek Whitfield of Stiefel. Your line is now open.
spk16: Good morning, all, and congrats on a strong start to the year.
spk38: Thank you, Derek. Thank you, Derek.
spk16: 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?
spk30: Yeah, Derek, good question. You know, I think generally, you know, we're going to see 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 pipe 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, the tune of a BCF a day or more, you know, that's going to push the problem downstream to the downstream residue pipes. So I think it's coming. It's going to be you know, pretty weak for periods, and then pressure will be relieved a little bit when these expansions come on. But 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
spk16: um you know from deals that we've bought have not come with taking kind rights and we've worked to uh improve that over time and control more of our molecules further downstream great and then 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 And how does that project over the next couple of years as you think about the integration of Delario and Firebird acquisitions?
spk30: Yeah, good question. I think we said, we said multiple times to investors, you know, flat for 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 ability to do that for longer. At the end of the day, 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.
spk16: Well done, guys.
spk24: Yes, Derek, I think just to reiterate that point that I've made a couple of times now about Diamondback's commitment to our shareholders about maintaining the lead and efficiency and cost execution. It's exactly what Case just said.
spk15: Thanks for the attikilla, Travis.
spk08: Thank you. One moment for our next question.
spk09: Our next question comes from the line of Scott Hanold of RBC Capital Markets. The line is now open.
spk10: Hey, thanks. Could you all provide a little bit of color on the cadence of activity moving forward? I mean, you all talk about having some larger pads going forward. And you all have had a very 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?
spk30: Yeah, good question, Scott. I would say internally it certainly does. This business is not easy to grow consistently and hit numbers consistently. But externally, we think we're going to grow fairly smoothly, organically through the back half of the year. In general, our target is to turn about 85 wells to sales a quarter. Some quarters are going to be a little higher, some are a little lower based on timing, but in general, that's our job. There's a lot going on beneath the surface, and that's what makes the Diamondback operations team the best in the business.
spk10: Great. And then if we could talk about M&A a little bit. And it looks like some of the private to private equity companies are dropping rigs in the Permian. And obviously, there have been some sales and talks of more sales coming up. What are you all seeing on the private side in terms of activity? And what's your interest level in looking at some of these additional M&A opportunities?
spk24: Yeah, we've commented a couple of times about The increase in activity through 2022 was largely driven by independence. And the challenge there is depth of inventory, right? And the secondary challenge is how much can they increase further beyond their max cadence that they achieved last year? And I think both of those are playing out now. The max cadence may be softening, as you see by rigs getting laid down. And certainly the inventory depth is getting accelerated with this rapid pace of bringing wells to production. So I think from an M&A perspective, it's going to 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. And I think you've also got, while the catalyst is unclear, you've also got some small public companies that are going to need to figure out some form of exit strategy to continue to be relevant in the future. And then there's always the large private unicorns that still float around out there as well, too. So I really think the next couple of years are going to be interesting in the M&A landscape.
spk10: So do you believe, though, that 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, they're an interest?
spk24: Well, you know, Scott, when you do M&A and if you do it correctly, you want to extend inventory life. You want to, you know, make sure that you're, you know, you're free cash flow or cash flow accretive and you don't want to impact your balance sheet. So, you know, just doing PDP type acquisitions, you know, doesn't necessarily fit into that calculus. But, you know, I think that's what you're going to end up seeing with some of these exit strategies are just kind of straight PDP divestitures.
spk10: Fair enough. Thank you.
spk09: Thank you. Thanks, Scott. One moment for our next question. Our next question comes from Joffrey Lumbudgen of TPH. Your line is now open.
spk18: Good morning, everyone, and thanks for taking my questions. My first one is just on commentary and 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?
spk30: Yeah, that's a good question, Jeff. I would say, you know, the mix of undeveloped DSUs is probably similar to years past. Now, the quality of the location of those undeveloped DSUs is probably a little bit higher this year than in 2022 even. It's kind of related to our comment on productivity. There's certainly a line of sight to very high productivity this year from development in the middle of Martin County. And some of that, we have up to a 6% or 7% NRI on large pads at the VIPER level. And so because we report consolidated financials, that is a benefit to the total enterprise where, you know, that high NRI development is going to drive organic production growth at the entity.
spk18: Great. Appreciate that. And then 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 of quarters.
spk30: Yeah. I think on the rig side, you know, everything's kind of a rolling three to six month contract. So we, we see, you know, we can see that our Q2 average day rate is down from Q1 today. And so that's going to continue to come our way on the rig side. On the frac side, you know, our two E fleets on the final price 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. And, you know, as we move those other two fleets to Simul-track fleets, you know, I think the more the benefit will be on the efficiency side than the price per horsepower side. But generally, a simul-track fleet saves up $20 or $30 a foot, you know, regardless of the price of the actual horsepower.
spk24: You know, Jeff, in addition to that, we talked earlier about, you know, purchasing steel multiple quarters in advance. So we're seeing the steel that we're purchasing for our 3Q, 4Q, 1Q cost, you know, already coming down. And so 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.
spk17: Appreciate it, guys. Thank you. Thanks, Jeff.
spk09: 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.
spk50: Hey, John.
spk13: Y'all, 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 spinal fracs as you now go toward four with spinal frac 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 the 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?
spk30: No, you know, listen, 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. And that's been the mentality. It's been a working mentality, a mentality that has worked for the last couple of years. So, 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 ducts, you know, particularly if rig costs are a little bit lower than they are today.
spk13: That's great. And then I really appreciate all the detail and color you all have given on there. The service cost front, so does it sound like obviously things are coming down from the peak levels of 1Q, but is it, are you all basically indicating that you all are on track to potentially have lower total completed well cost by year end 23 versus year end 22? Like when you factor in what you're seeing on the cost side, but maybe more importantly, the efficiency gains from the simulfracs?
spk30: Yeah, I would say yes, that's a fair answer. I mean, particularly, you know, listen, steel is the biggest driver. You know, we're not forecasting a total capitulation in service costs here, but, 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 going to be closer to $90 a foot. So, I mean, that in itself makes up for a significant percentage of the savings. So I would say, yes, Q4 2023 well costs below Q4 2022 because generally Q4 22 and Q1 23 were the highs. That's great. Appreciate it, guys.
spk24: And John, listen, just to re-emphasize, we run the business to maximize efficiency as well. And so Case 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.
spk11: Thanks, Travis.
spk09: Thank you. One moment for our next question. Our next question comes from the line of Tim Resvin of KeyBank Capital Markets. Your line is now open.
spk07: Good morning, folks. Thank you for taking my question. I wanted to circle back Dave'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 number of levers that you can pull to get to a billion or more on asset sales. trying to understand a case, 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? Um, you know, as you compare yourself to the large cap peers, and I guess, you know, why wouldn't you go, go bigger than that 1 billion, um, given you're not allocating a lot of capital to the Delaware right now?
spk30: Yeah, Tim, that's a good question. I don't, I'm not going to go bigger cause we want to beat the number. Um, first of all, but, uh, But, 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. So I think, you know, we have sold a few small things in the Delaware on the acreage side. And the recurring theme of what we sold is that someone paid for upside. So... you know, we're not going to 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 were expecting. And that, I think, you know, has been a common theme in the Delaware deals as well as the deal in Glasgow 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. So 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. But generally, you know, that production and cash flow has a lot of value to us today.
spk07: Okay. And then 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... Yeah, good question.
spk30: Sorry, I apologize. I forgot to 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. And, 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. So I'd like to take that out so that Travis won't bother me about it until 2029. And, you know, but when we have excess free cash flow, we're going to 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, an ideal debt level with no debt due for multiple years before your next maturity.
spk06: Okay. I appreciate the college. That's all I had. Thanks.
spk37: Thanks, Tim.
spk09: Thanks. One moment for our next question. Our next question comes from the line of Charles Mead of Johnson Rice. Your line is now open.
spk03: Good morning, Travis Case, and to the rest of the Diamondback team there.
spk24: Hey, Charles. Good morning, Charles.
spk04: Travis, this may be for you. I like the new format as well, but I was also thinking about the shareholder letter. And, 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 thing for you this morning. But 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 and that you're not? And 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?
spk24: No, we didn't put this letter in place trying to fix the communication issue. We've got an incredible transparency communication format that we have with our shareholders. We just thought that based on a decade of doing these earnings calls and the lack of attention really And 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. And then we didn't have to have anybody spending Sunday night preparing our transcript either as well, too. So, I mean, from a staff perspective, it was a lot more efficient there. So, no, 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.
spk30: 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.
spk04: Insight into your thinking. I appreciate that. And in case, I want to go back to the question on the buybacks. I know this has been addressed at least in one other earlier question, but 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 kind of signal a decline a durable shift, or if not a durable shift, a durable change in the preference towards buybacks?
spk30: You know, listen, I think our preference has always been to buy back shares. Now, 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? And that's our NAV versus looking at a deal like Lario or Firebird. You know, so... At the end of the day, we're still going to run our NAV at a conservative mid-cycle deck, which is $60 oil, and the market has presented us opportunities to buy back shares every quarter since we started this buy back program. At the end of the day, again, our preference is buy back, but we have a little bit of a governor on what share price we're going to be aggressive on, and Q1 was the perfect example of that.
spk24: Charles, we've tried to be mindful of sins of the past. Our industry has been with higher oil prices, and that hasn't created a lot of value. So we may not always be perfect in that calculus, but as Case 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 roughly $120 a share. So 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 revert your shares.
spk05: Thank you, gentlemen. Appreciate the call. Thanks, Charles.
spk09: Thank you. One moment for our next question. Our next question comes from the line of Roger Reed of Wells Fargo Securities. Your line is now open.
spk35: Yeah, thank you. Good morning. Good morning, Roger. Let's come back in time.
spk40: dig into the service cost or deflation, I guess we could call it at this point. We aren't 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 just a decline in the cost of doing something, being drilling rigs or whatever? 50-50, 50-40, 80-20, something like that is what I was curious about.
spk30: Yeah, I would say it's a quarter efficiency than 75% actual costs. Now, 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.
spk40: Okay. And then 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 frack to the saddle frack in terms of however you want to 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.
spk30: I'll give you the cost estimates, and Danny can give you the efficiencies. You know, I said generally a simulfrac fleet is $20 to $30 a foot cheaper than a conventional fleet, and an E-fleet is $20 to $30 a foot cheaper than a simulfrac fleet.
spk26: Yeah, I mean, an E-fleet for utilizing our simulfrac fleets, They're just powered with electric power that we generate on location or that we pull off the grid. Really, the savings on the E-Fleet 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 lateral footage completed per by the E-Fleets versus the, you know, diesel simulacrate fleets, but we don't have just a ton of data yet to quantify that, but 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.
spk24: Danny, the difference between zipper and simulfrac in terms of footage per day?
spk26: Yeah, I mean, so we kind of say a simulfrac fleet, depending on the jobs, can do about twice as much lateral footage per day as a traditional zipper fleet.
spk40: Yeah, so very, very large differences. One, just a little clarification on your comment at the very beginning about locking in some of your electricity costs, being able to 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 to get the lower cost or fixed cost, you have to accept the risk of being turned off?
spk26: No. No, it's just a hedge in the market. So it's just a financial hedge, not a physical trade.
spk39: Great. Thank you.
spk09: 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.
spk44: I just wanted to follow up quickly on LOE. I just wanted to clarify one of your earlier comments. It sounds like you guys are expecting LOE per barrel to climb here in 2Q and 3Q versus where you were in 1Q. Just wanted to make sure I sort of heard that right.
spk30: No, we expect it to go up to the midpoint of guidance from $5 to midpoint of $5 to $5.50. So going up slightly due to third-party water handling.
spk44: OK. And you're viewing that as somewhat temporary just based on where the rigs are going to sort of be drilling, you know, location-wise here in the middle part of the year?
spk30: Yeah, it's just dependent upon where the completions are. If the completions are on a third-party dedicated piece of acreage, the cost is higher than it would have been on a prior Rattler dedicated piece of acreage.
spk44: Right. Okay. And then just on cash taxes, you know, looking at first quarter, you guys kind of came in below the guidance. So far, I guess quarter to date here in QQ, commodity prices are kind of flat to down. You guys are expecting cash taxes to kind of increase here in QQ per the guidance. Just wanted to kind of get 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 maybe that just has to do with NOLs that are, you know, completely disappearing or other tax shield that disappears. But any other color kind of around that cadence of cash taxes as the year progresses?
spk30: Yeah, I think the only real added benefit that Q1 had versus Q2, even if commodity prices were flat, is that we closed Lario in the quarter and got to, you know, write off some of the hard assets that came with that right away.
spk44: All right, so it 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?
spk30: That's fair.
spk44: Okay, thank you.
spk09: Thank you. One moment for our next question. Our final question comes from Paul Chang of Scotiabank. Your line is now open.
spk19: Thank you. Good morning.
spk21: I just want to add my appreciation with the new format. I think it's great. Two questions, please. First, you've been increasing your overall food activity in the midland over the last several years. So 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 there as well? say maybe sometime over the next one or two years?
spk30: I think over the next few years, the 85-15 is a very fair yearly estimate. Obviously, some quarters will be higher than others. We want to continue to complete multi-well pads in the Delaware. So you have a quarter like Q1 of 2023, which was higher Delaware when Q4 was zero wells in the Delaware. But on an annual basis, 85-15 feels like the right lateral footage mix.
spk21: Okay. And 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 cost is coming down, how much of them is already originally built into that budget or that, in other words, Will that be a reasonable probability you're actually going to be below the midpoint of your budget?
spk30: I don't know if I'm ready to commit to that today, Paul. We certainly have some work to do, but we have a very good line of sight from an activity and a cost perspective that we've seen the peak in well costs and a little bit of a tailwind from the activity of two rigs coming down. Now, I think that'll happen. a little bit in Q3 and more in Q4, but, you know, it's still early. Okay.
spk21: Can you share with us that, I mean, how much of the savings you're originally building or how much is the deflation in the second half that you have building into your budget?
spk30: I would say if we saw more service cost deflation, that would be upside to what we've modeled here.
spk20: I see.
spk30: True service, not raw materials.
spk20: Okay, we do. Thank you.
spk09: Thank you, Paul. This concludes our Q&A session. I would now like to turn it over to Travis Dice, CEO, for closing remarks.
spk24: 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. So 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. Hello. Thank you. Thank you. Thank you. Thank you.
spk09: Good day and 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 11 on your telephone, and you will then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 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 Lawless, Vice President of Investor Relations. Please go ahead.
spk25: Thank you, Joanne. Good morning, and 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 Dice, Chairman and CEO of Case Vantoff, 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 gap measures can be found in our earnings release issued yesterday afternoon.
spk24: I'll now turn the call over to Travis Stutz. Thank you, Adam. And 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. So we'll move right into questions. Operator, if you would open the line and begin with our first question.
spk09: Thank you. As a reminder, to ask a question, you will need to press star 1 1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1 1 again. Please stand by for our first question. Our first question comes from the line of Neil Dingham of Truist Securities. Your line is now open.
spk41: First, thanks, Travis, for the new format. I appreciate it. Travis, my first question is for you or Danny on one of the topic visitors, that service cost. Specifically, are you able to quantify how your continued operational efficiencies have recently mitigated your cost? And I'm just wondering how you all think about spot versus long-term contracts in the current environment.
spk24: I think, Neil, the read-through to that question is kind of what the CapEx is going to look like in the back half of the year. And I think there's – and I'll let Danny talk about the specific operational efficiencies we've seen year-to-date that's offset most of the inflationary pressures. But 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. So we know what that steel cost is and it's already down, for the future purposes, $20, $25 a foot. And then we've also got the rigs we talked about. We're going to drop a couple of rigs and that allows us to to look at our entire rig fleet and the cost associated with those rigs, and we see rig costs are coming down as well. And then 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, and we've also got rid of our two spot frack crews and replaced them with one simul-frack crew, so we're seeing, you know, $10 to $20 a foot efficiency gains there as well. So regardless, Neil, of what's going on with CapEx, our commitment has always been to be the low-cost leader when it comes to prosecuting our development plan out here, and we've got now almost a decade of demonstrating that. So we anticipate that we're going to continue to do that, and that's what our shareholders should be comfortable in. Danny, do you have some additional color for near-term?
spk26: No, I think Travis covered everything that we've kind of seen on the drilling services side and consumable side on the drilling side that's leading us to see leading edge costs coming down. And then on the completion side, just with the additional efficiencies from the additional E-Fleet as well as the replacement, simultaneously replacing the two traditional E-Fleets zipper fleets that we took over as far as the two acquisitions at the end of the year.
spk41: Great. Thank you for that. And then my second question for Kay is on shareholder return. Kay, 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 plan still just to see what your stock price is doing versus the mid-cycle or how do you determine that?
spk30: Yeah, Neil, you know, we always kind of, when we upped the shareholder return program to 75% of free cash going back to shareholders, we thought the mix of 75% 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, to equity while continuing to improve the balance sheet. Really, the test of this new business model and return of capital-based business model is when things go south. In a potential downturn, 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 even when things are going well like today. We've kept a flexible return of capital program since the beginning. I think we like that and want to keep that. And Q1 is an exact reason why we maintain that flexibility. We don't want to blow out the balance sheet to buy back stocks, but we also recognize that when your stock's down significantly in a quarter, variable dividend doesn't matter. That's what we did in Q1 and allocated a lot more cash to the buyback.
spk42: We're glad to see it. Thank you all. Thanks, Jim.
spk09: 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.
spk46: Yeah, good morning, team, and again, thanks for the new format. The first question was around gas price realizations. Obviously, they were softer in the quarter. There's some one-time dynamics, it felt like, but, you know, just if you're curious on your views on how local gas pricing is going to play out here and what protections you guys have proposed built in place in order to mitigate pricing negativity?
spk30: Yeah, Neil, 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. Really, a lot of that comprised a $15 million true-up payment between a contract that moved from selling at the wellhead to taking kind rights downstream. So that'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 going to 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 two-thirds of our gas, through the end of 2024. And then the other one-third of our gas gets a combination of Henry Hub and Houston Ship Channel prices. And then, you know, on the Henry Hub side, we have protected with, you know, wide collars with a $3 floor, about two-thirds of our gas this year in 2023 and probably a third of it next year. So, in general, you know, I think we try to give the streets some guidance on future unhedged gas realizations, and the hedging piece has been a tail end for us as gas prices weaken both at Henry Hub and in the Basin.
spk46: Thanks for that case. And then just follow up on some of the recent acquisitions that you've done here. 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?
spk30: Yeah, that's a great question as well. I would say generally, Larry, 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. And I think at the end of the day, when we look back at the Firebird acquisition in a few years, that's going to 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. And there's been some well tests where We've co-developed the Lower Sprayberry and the Wolf Camp A on the southern part of the position that gives us confidence that some of those upside locations are going to become real locations that we're going to develop over time. Second to that, the ops team, 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. So 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 catch thank you thank you neil one moment for our next question
spk09: Our next question comes from the line of Aaron Jirem of JP Morgan Securities LLC. Your line is now open.
spk43: 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 the 1Q actuals implies around $1.36 billion in spending. or about 52% of the budget, you talked about having line of sight to some meaningful declines in service costs. So is there maybe a case if you could describe your confidence on hitting, call it the midpoint of the range of $2.6 billion for the full year? And how does your cash, 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?
spk30: Yeah, good question, Arun. You know, on the cash CapEx thing, you know, the prime example was Q2 of 2020. Well, I don't want to 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. So there's a big disconnect between accrued and cash CapEx. Now, 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 going to 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. And on the other side of that DC&E line, completions down because of efficiencies, because of the high grading to two Zeus fleets with Halliburton and two Simulprac fleets. And lastly, 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 generally slows down in the back half of the year. So 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 to 60 days on the cash side and CapEx.
spk24: Yeah, and just again, 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. But our commitment hasn't changed regardless of what CapEx does.
spk43: Great. Thanks a lot, Travis. My follow-up, team, we've heard about some industry activity and 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? And perhaps, you know, this obviously could have some positive implications for Venom, so I was wondering if you could maybe talk about
spk30: um how fangs 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 um we have most of our leases covered that will can't be which is a deeper zone that's going to get a lot more attention over the over the coming years and and some you know lesser a lesser extent do we have the uh barnett and woodford covered now you know we've been exploring the barnett and woodford on the eastern 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 and, 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 going to
spk09: know have a front seat to leasing any of those deeper rights should they be unleashed throughout the basin great thanks a lot thank you 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 uh turning back to
spk33: Service rates, the service companies have been talking about a bifurcated market here for both rigs and frac pumps. And their characterization is that the highly efficient crews, the next-gen kit, especially in that gas-fueled rigs and pumps will largely maintain pricing while it's going to be the legacy equipment and or lower quality crews where you'll see the more meaningful declines in rates. Is that how you see the market developing here, or do you see more broad-based reductions in pricing kind of across the spectrum?
spk30: 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. So 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 going to have an impact on pricing. You know, there's just no doubt about that. So, you know, 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.
spk33: Got it. And then just turning to operating costs, LOE came in at the low end of the range. We kept the full year. And then you mentioned the fixed price contracts for power. Just any color that you can provide on how operating costs should evolve over the course of the year, given the outlook for natural gas and power and other things, chemicals, et cetera, that go into operating costs?
spk30: 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. And so, 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. But, 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.
spk31: Got it. Appreciate the call, Chase. Thank you.
spk27: Thank you, Scott.
spk09: Thank you. One moment for our next question. Our next question comes from the line of David Deckelbaum of Cohen. Your line is now open.
spk52: Good morning, Travis, Casey, Danny, and team. Thanks for taking my questions today.
spk22: Sure. Good morning, David.
spk52: Good 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 24 and 25, the mix between Simulfrac fleets and E-Fleets if we assume sort of this flattish rig count, or is the two-to-two mix the expectation for longer-term development?
spk26: Yeah, David, good question. I think, you know, our plan right now looking out into 24 and 25 is probably to stick with the, you know, kind of 50-50 mix. We basically have to underwrite the E-Police and sign up for a longer-term commitment with them, you know, which is a little harder to do 100% of your capacity committed for a long-term commitment, but The additional simulacrate fleet, as more E-Fleets come to market and are available in a, I guess, spot basis, we will certainly migrate to more E-Fleets that we'd have some flexibility around utilization.
spk52: Got it. And then 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 five or so outstanding investments that you're articulating on the slide deck in the back, mostly on the midstream side. It might be a source of funds going forward. Is there a high probability that we'll see another asset sale this year?
spk30: Yeah, I would place a pretty high probability on that, David. We wouldn't have increased our target from $500 million to $1 billion this of non-core divestitures if we didn't have, you know, a pretty good line of sight. You know, I can't guarantee it's going to happen today, but certainly there's a few things in the works, you know, either on the JV side or, you know, some of the small operated midstream assets that could be up for sale. So we still feel very comfortable with that billion-dollar target. I would just say it's tailored more towards midstream versus upstream.
spk52: Appreciate it. Thanks for the time, guys. Thank you.
spk09: Thank you. One moment for our next question. Our next question comes from the line of Roger Reed of Wells Fargo Securities. Your line is now open.
spk37: Roger, you're on mute if you're on the line.
spk36: Julia, let's move to the next question, please.
spk08: One moment for our next question.
spk09: Our next question comes from the line of Kevin McCurdy of Pickering Energy Partners. Your line is now open.
spk29: Hey, good morning. With the 1Q release, you've kind of given the pictures to figure out what the 4Q23 capex and activity is. As we look into a 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?
spk30: That's a good question, Kevin. I'm not totally ready to commit to 2024 today, but I would say if we had to commit today, running some sort of plan with four simulfrac crews is probably the most efficient and capital-efficient plan we could put together. Now, you know, whether that spits out slight growth to flat production is to be determined, but, 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 years with this new business model, and that's kind of where we're circling things going forward.
spk28: Great. That's the only question for me. Thanks, guys. Thank you, Kevin. Thanks, Kevin.
spk09: Thank you. One moment for our next question. Our next question comes from the line of Derek Whitfield of Stiefel. Your line is now open.
spk16: Good morning, all, and congrats on a strong start to the year.
spk38: Thank you, Derek.
spk16: Thank you, Derek. 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?
spk30: Yeah, Derek, good question. You know, I think generally, you know, we're going to see 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 pipe coming on at the end of 2024. You know, I just think the issue today had been masked in the field as processing capacity in the field was short. Now that that processing capacity is coming on, you know, the tune of a BCF a day or more, you know, that's going to push the problem downstream to the downstream residue pipes. So I think it's coming. It's going to be pretty weak for periods, and then pressure will be relieved a little bit when these expansions come on. But generally, 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. Ideally, we'd like to have control of all of our molecules to the Gulf Coast, but most of our contracts we inherited
spk16: um you know from deals that we've bought have not come with taking kind rights and we've worked to uh improve that over time and control more of our molecules further downstream great and then 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 And how does that project over the next couple of years, as you think about the integration of Delario and Firebird acquisitions?
spk30: Yeah, good, good question. You know, I, I think we've said, uh, we've said multiple times to investors, you know, flat, flat for 2022 is probably the base case. And if we do a little better, that's, that's one for the good guys. Um, I think we're, we're on pace for that. Um, you know, particularly in the Midland basin where we've had really strong start to the year. I would just say Firebird and Lario only enhance that ability to do that for longer. At the end of the day, as we've said before, the shell 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 shell cost curve, which we've done well for the last 10 years and we expect to do well for the next 10 years.
spk16: Well done, guys.
spk24: Yes, Derek, 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 Case just said.
spk15: Thanks for the attitude, Travis.
spk08: Thank you. One moment for our next question.
spk09: Our next question comes from the line of Scott Hanold of RBC Capital Markets. The line is now open.
spk10: Hey, thanks. Could you all provide a little bit of color on the cadence of activity moving forward? I mean, you all talk about having some larger pads 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?
spk30: 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. But externally, you know, we think we're going to grow fairly smoothly, organically through the back half of the year. In general, our target is to turn about 85 wells to sales a quarter. Some quarters are going to be a little higher, some are a little lower based on timing, but in general, that's our job. There's a lot going on beneath the surface, and that's what makes the Diamondback operations team the best in the business.
spk10: Great. And then if we could talk about M&A a little bit. And it looks like some of the private to private equity companies are dropping rigs in the Permian. And obviously, there have been some sales and talks of more sales coming up. What are you all seeing on the private side in terms of activity? And what's your interest level in looking at some of these additional M&A opportunities?
spk24: Yeah, we've commented a couple of times about The increase in activity through 2022 was largely driven by independence. And the challenge there is depth of inventory, right? And the secondary challenge is how much can they increase further beyond their max cadence that they achieved last year? And I think both of those are playing out now. The max cadence may be softening, as you see by rigs getting laid down. And certainly the inventory depth is getting accelerated with this rapid pace of bringing wells to production. So I think from an M&A perspective, it's going to 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. And I think you've also got, while the catalyst is unclear, you've also got some small cap public companies that are going to need to figure out some form of exit strategy to continue to be relevant in the future. Then there's always the large private unicorns that still float around out there as well, too. I really think the next couple of years are going to be interesting in the M&A landscape.
spk10: Do you believe, though, that 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, they're an interest?
spk24: Well, you know, Scott, when you do M&A and if you do it correctly, you want to extend inventory life. You want to, you know, make sure that you're, you know, you're free cash flow or cash flow accretive and you don't want to impact your balance sheet. So, you know, just doing PDP type acquisitions, you know, doesn't necessarily fit into that calculus. But, you know, I think that's what you're going to end up seeing with some of these exit strategies are just kind of straight PDP divestitures.
spk10: Fair enough. Thank you.
spk09: Thank you. Thanks, Scott. One moment for our next question. Our next question comes from Jeffrey Lumbagin of TPH. Your line is now open.
spk18: Good morning, everyone, and thanks for taking my questions. My first one is just on commentary and 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 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?
spk30: Yeah, that's a good question, Jeff. I would say the mix of undeveloped DSUs is probably similar to years past. Now, the quality of the location of those undeveloped DSUs is probably a little bit higher this year than in 2022 even. It's kind of related to our comment on productivity. There's certainly a line of sight to very high productivity this year from development in the middle of Martin County. And some of that, we have up to a 6% or 7% NRI on large pads at the VIPRO level. And so because we report consolidated financials, that is a benefit to the total enterprise where, you know, that high NRI development is going to drive organic production growth at the entity.
spk18: Great. Appreciate that. And then 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 of quarters.
spk30: Yeah, I think on the rig side, you know, everything's kind of a rolling three to six month contract. So we see, you know, we can see that our Q2 average day rate is down from Q1 today. And so that's going to continue to come our way on the rig side. On the frac side, you know, our two E-fleets on the final five 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. And, you know, as we move those other two fleets to Simultrack fleets, I think the more the benefit will be on the efficiency side than the price per horsepower side. Generally, a simultrack fleet saves up $20 or $30 a foot regardless of the price of the actual horsepower.
spk24: Jeff, in addition to that, we talked earlier about purchasing steel multiple quarters in advance. We're seeing the steel that we're purchasing for our 3Q, 4Q, 1Q cost already coming down. And so while it's not necessarily a service cost deflation, it is a cost deflation that could be as much as $20 or $25 a foot additionally.
spk17: Appreciate it, guys. Thank you. Thanks, Jeff.
spk09: 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.
spk50: Hey, John.
spk13: Y'all, 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 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 the 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?
spk30: No, you know, listen, 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. And that's been the mentality. It's been a working mentality, a mentality that has worked for the last couple of years. So, 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 ducts, you know, particularly if rig costs are a little bit lower than they are today.
spk13: That's great. And then I really appreciate all the detail and color you all have given on there. The service cost front, so does it sound like obviously things are coming down from the peak levels of 1Q, but is it, are you all basically indicating that you all are on track to potentially have lower total completed well cost by year end 23 versus year end 22? Like when you factor in what you're seeing on the cost side, but maybe more importantly, the efficiency gains from the simulfracs?
spk30: Yeah, I would say yes, that's a fair answer. I mean, particularly, you know, listen, steel is the biggest driver. You know, we're not forecasting a total capitulation in service costs here, but, 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 going to be closer to $90 a foot. So, I mean, that in itself makes up for a significant percentage of the savings. So, I would say yes, Q4 2023 well costs below Q4 2022 because generally Q4 22 and Q1 23 were the highs. That's great. Appreciate it, guys.
spk24: And John, listen, just to re-emphasize, we run the business to maximize efficiency as well. And so Case 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.
spk11: Thanks, Travis.
spk09: Thank you. One moment for our next question. Our next question comes from the line of Tim Resvin of KeyBank Capital Markets. Your line is now open.
spk07: Good morning, folks. Thank you for taking my question. I wanted to circle back Dave'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 number of levers that you can pull to get to a billion or more on asset sales. trying to understand a case, 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 yourself to the large cap peers? And 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?
spk30: Yeah, Tim, that's a good question. I'm not going to go bigger because we want to beat the number, first of all, but, you But 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 the credit ratings. It's important to our free cash flow forecast and all the above. So I think we have sold a few small things in the Delaware on the acreage side. And the recurring theme of what we sold is that someone paid for upside. you know, we're not going to 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 were expecting. And that, I think, you know, has been a common theme in the Delaware deals as well as the deal in Glasgow 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. So 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. But generally, you know, that production and cash flow has a lot of value to us today.
spk07: Okay. And then 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... Yeah, good question.
spk30: Sorry, I apologize. I forgot to 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. And, 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. So I'd like to take that out so that Travis won't bother me about it until 2029. And, you know, but when we have excess free cash flow, we're going to 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, an ideal debt level with no debt due for multiple years before your next maturity.
spk06: Okay. I appreciate the college. That's all I had. Thanks.
spk37: Thanks, Tim.
spk09: Thanks. One moment for our next question. Our next question comes from the line of Charles Mead of Johnson Rice. Your line is now open.
spk03: Good morning, Travis Case, and to the rest of the Diamondback team there.
spk24: Hey, Charles. Good morning, Charles.
spk04: Travis, this may be for you. I like the new format as well, but I was also thinking about the shareholder letter. And, 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 thing for you this morning. But 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 and that you're not? And 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.
spk24: No, we didn't put this letter in place trying to fix the communication issue. We've got an incredible transparency communication format that we have with our shareholders. We just thought that based on a decade of doing these earnings calls and the lack of attention really 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. And then we didn't have to have anybody spending Sunday night preparing our transcript either as well, too. So, I mean, from a staff perspective, it was a lot more efficient there. So, no, 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.
spk30: 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.
spk04: Insight into your thinking. I appreciate that. And in case, I want to go back to the question on the buybacks. I know this has been addressed at least in one other earlier question, but 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 kind of signal a decline
spk30: durable shift or mirror or if not a durable shift a durable change in the preference towards buybacks you know I think our preference has always been to buy back shares now what we wanted was a governor on what 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 and that's our nav versus looking at a deal like larry over firebird you know so I At the end of the day, we're still going to run our NAV at a conservative mid-cycle deck, which is $60 oil. And the market has presented us opportunities to buy back shares every quarter since we started this buy back program. So at the end of the day, again, our preference is buy back, but we have a little bit of a governor on what share price we're going to be aggressive on, and Q1 was the perfect example of that.
spk24: And, Charles, we've tried to be mindful of sins of the past. oil prices, and that hasn't created a lot of value. We may not always be perfect in that calculus, but as Case 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 roughly $120 a share, so 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 revert your shares.
spk05: Thank you, gentlemen. Appreciate the call. Thanks, Charles.
spk09: Thank you. One moment for our next question. Our next question comes from the line of Roger Reed of Wells Fargo Securities. Your line is now open.
spk35: Yeah, thank you. Good morning. Good morning, Roger. Let's come back in time.
spk40: dig into the service cost or deflation, I guess we could call it at this point. We aren't 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 just a decline in the cost of doing something, being drilling rigs or whatever? 50-50, 60-40, 80-20, something like that is what I was curious about.
spk30: Yeah, I would say it's a quarter efficiency than 75% actual costs. Now, 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.
spk40: Okay. And then 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 frack to the silo frack in terms of however you want to 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.
spk30: I'll give you the cost estimates, and Danny can give you the efficiencies. Generally, a simulfrac fleet is $20 to $30 a foot cheaper than a conventional fleet, and an E-fleet is $20 to $30 a foot cheaper than a simulfrac fleet.
spk26: Yeah, I mean, an E-fleet, we're utilizing our simulfrac fleets. They're just powered with electric power that we generate on location or that we pull off the grid. So really the savings on the E-Fleet 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 simulacrate fleets, but we don't have just a ton of data yet to quantify that, but 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.
spk24: Danny, the difference between zipper and simulfrac in terms of footage per day?
spk26: Yeah, I mean, so we kind of say a simulfrac fleet, depending on the jobs, can do about twice as much lateral footage per day as a traditional zipper fleet.
spk40: Yeah, so very, very large differences. One, just a little clarification on your comment at the very beginning about locking in some of your electricity costs, being able to 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 to get the lower cost or a fixed cost, you have to accept the risk of being turned off? No.
spk26: No, it's just a hedge in the market. So it's just a financial hedge, not a physical trade.
spk39: Great. Thank you.
spk09: 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.
spk44: I just wanted to follow up quickly on LOE. I just wanted to clarify one of your earlier comments. It sounds like you guys are expecting LOE per barrel to climb here in 2Q and 3Q versus where you were in 1Q. Just wanted to make sure I sort of heard that right.
spk30: No, we expect it to go up to the midpoint of guidance from $5 to midpoint of $5 to $5.50. So going up slightly due to third-party water handling.
spk44: OK. And you're viewing that as somewhat temporary just based on where the rigs are going to sort of be drilling, you know, location-wise here in the middle part of the year?
spk30: Yeah, it's just dependent upon where the completions are. If the completions are on a third-party dedicated piece of acreage, the cost is higher than it would have been on a prior Rattler dedicated piece of acreage.
spk44: Right. Okay. And then just on cash taxes, you know, looking at first quarter, you guys kind of came in below the guidance. So far, I guess quarter to date here in QQ, commodity prices are kind of flat to down. You guys are expecting cash taxes to kind of increase here in QQ per the guidance. Just wanted to kind of get 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 maybe that just has to do with NOLs that are, you know, completely disappearing or other tax shield that disappears. But any other color kind of around that cadence of cash taxes as the year progresses?
spk30: Yeah, I think the only real added benefit that Q1 had versus Q2, even if commodity prices were flat, is that we closed Lario in the quarter and got to, you know, write off some of the hard assets that came with that right away.
spk44: All right, so it 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?
spk30: That's fair.
spk20: Okay, thank you.
spk09: Thank you. One moment for our next question. Our final question comes from Paul Chang of Scotiabank. Your line is now open.
spk19: Thank you. Good morning.
spk21: I just want to add my appreciation with the new farmer. I think it's great. Two questions, please. First, you've been increasing your overall food activity in the midland over the last several years. So 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 there as well? say maybe sometime over the next one or two years?
spk30: I think over the next few years, the 85-15 is a very fair yearly estimate. Obviously, some quarters will be higher than others. We want to continue to complete multi-well pads in the Delaware. So you have a quarter like Q1 of 2023, which was higher Delaware when Q4 was zero wells in the Delaware. But on an annual basis, 85-15 feels like the right lateral footage mix.
spk21: Okay. And 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 cost is coming down. How much of them is already originally built into that budget or that, in other words, Will that be a reasonable probability you're actually going to be below the midpoint of your budget?
spk30: I don't know if I'm ready to commit to that today, Paul. We certainly have some work to do, but we have a very good line of sight from an activity and a cost perspective that we've seen the peak in well costs and a little bit of a tailwind from the activity of two rigs coming down. Now, I think that'll happen eventually. a little bit in Q3 and more in Q4, but, you know, it's still early. Okay.
spk21: Can you share with us that, I mean, how much of the savings you're originally building or how much is the deflation in the second half that you have building into your budget?
spk30: I would say if we saw more service cost deflation, that would be upside to what we've modeled here.
spk20: I see.
spk30: True service, not raw materials.
spk20: Okay, we do. Thank you. Thank you.
spk09: Thank you, Paul. This concludes our Q&A session. I would now like to turn it over to Travis Dice, CEO, for closing remarks.
spk24: 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. So if you have any additional follow-up, just reach out to us using the numbers that we provided earlier. Thanks again for joining. Have a great day.
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