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Diamondback Energy Inc
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Good day, and thank you for standing by. Welcome to the Diamondback Energy First Quarter 2023 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.
I would now like to hand the conference over to your first speaker today, Adam Lawlis, Vice President of Investor Relations. Please go ahead.
Thank you, Gina. 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 Stice, Chairman and CEO; Kaes Van't Hof, President and CFO; and Danny Wesson, COO.
During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.
I'll now turn the call over to Travis Stice.
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.
[Operator Instructions] Our first question comes from the line of Neal Dingmann of Truist Securities. Your line is now open.
First, thanks, Travis for the new format. Appreciate it. Travis, my first questions for you or Danny, on one of the top [indiscernible] that service costs. Specifically, are you able to quantify how your continued operational efficiencies have recently mitigated the cost? And just wondering how you all think about spot versus long-term contracts in the current environment?
I think Neal, the read through 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 will 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 -- that'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 to $25 a foot.
And then we've also got the rigs we talked about what we’re involved with a couple of rigs, and that allows us to do -- 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, it's -- while it's not necessarily a CapEx issue, we're seeing improved efficiencies as we've got that second e-fleet that's -- that started last week. And we've also got rid of our two spot frac crews and replace them with one simulfrac crew. So we're seeing $10 to $20 a foot efficiency gains there as well.
So regardless, Neal, 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?
No, I think Travis covered everything that we're -- 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 simulfrac fleet replacing the two traditional zipper fleets that we took over as far as the two acquisitions at the end of the year.
Great. Thank you for that. And then my second question for Kaes on shareholder return. Kaes, specifically it seems you all plan to stick to or you are sticking to that 75% free cash flow payout. Can you give me your opinion on maybe why not pay more like some peers and 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?
Yes, Neal, we always -- when we upped the shareholder return program to 75% of free cash going back to shareholders, we bought 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, like they have in the last couple of years, 75% feels like a max number to go back to equity while continuing to improve the balance sheet.
Really the test of this new business model and returns -- return of capital based business models 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 at today. So we've kept a flexible return of capital program since the beginning. I think we like that. We 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 is down significantly in the quarter, variable dividend doesn't matter. And that's what we did in Q1 and allocated a lot more cash to the buyback.
Glad to see it. Thank you all.
Thanks, Neal.
Thank you. One moment for our next question. Our next question comes from the line of Neil Mehta of Goldman Sachs & Co. Your line is now open.
Yes. Good morning, team. And again, thanks for the new format. The first question was around gas price realizations. Obviously, they were soft in the quarter. There's some one-time dynamics it felt like. But just curious on your views on how local gas pricing is going to play out here? And what protections you guys have built in place in order to mitigate pricing negativity?
Yes, 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 contracts that moved from selling at the wellhead to taking on our -- taking kind rights downstream. So that's kind of an intercompany issue, but I recognize it did hit gas presence for the quarter.
What we've done from a hedging perspective and from a physical perspective to protect against future gas price loss in the basin, which we think there's going to be periodic points of weakness throughout this year and next. 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 combination of Henry Hub and Houston Ship Channel prices.
And then on the Henry Hub side, we have protected with 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, I think we tried to give the Street some guidance on future unhedged gas realizations and the hedging piece has been a tailwind for us as gas prices weakened both at Henry Hub and in the basin.
Okay. Thanks for that, Kaes. And then just a follow-up on some of the recent acquisitions that you've done here that you've had them in your portfolio now for a couple of 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?
Yes, that's a great question as well. I would say, generally, Lario, we knew what we were getting. That asset is nearby all of our existing production in Martin County. So that's as advertised. I think at the end of the day, when we look back at the FireBird acquisition, in a few years that's going to be one of the better value deals 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 Spraberry and the Wolfcamp 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 are going to develop over time.
Second to that, the ops team, they're going into a new area. We are already completing or drilling a 15,000 foot lateral and 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, guys.
Thank you, Neil.
Thank you. One moment for our next question. Our next question comes from the line of Arun Jayaram of JPMorgan Securities LLC. Your line is now open.
Good morning, guys. We do appreciate the new format. So that was really helpful. My first question is on CapEx. Your first half CapEx guidance plus the 1Q actual 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 I was wondering maybe Kaes, if you could describe your confidence on hitting, call it, the midpoint of the range of $2.6 billion for the full year?
Yes.
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?
Yes. Good question, Arun. On the cash CapEx thing, the prime example was Q2 of 2020, while I don't want to relive that particular quarter, we reduced our rig count from 15 -- or 23 rigs down to 6, 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 faced here, right.
We are talking about things at the margin like a $50 million reduction in run rate CapEx, which is, in my mind, very achievable based on three things: lower activity, we are going to reduce our rig count by 2 rigs as expected at the end of this quarter through the back half of the year.
Second, lower service costs and 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 [indiscernible] fleets with Halliburton and two simulfrac 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. We 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.
Yes. And just again to -- Arun to reiterate my opening comment to the first question is that our commitment to our shareholders remain unchanged to be the low-cost leader in efficiency and in execution. And it'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.
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 this obviously could have some positive implications for VNOM. So I was wondering if you could maybe talk about how FANG's leases are structured and maybe positive implications for VNOM?
Yes. There's really no one size fits all to leases in the Midland Basin. I would say generally, we have most of our leases cover the Wolfcamp B, which is a deeper zone that's going to get a lot more attention over the coming years and some to a lesser extent, we have the Barnett and Woodford covered now. 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 testing that zone and looking at it for future development in the end of this decade, into the next decade. We'll say, generally, that's the benefit of owning a lot of minerals is that we have the other side of our business card that is going to have a front seat to leasing any of those deeper rights should they be unleased throughout the basin.
Great. Thanks a lot.
Thank you, Arun.
Thank you. One moment for our next question. Our next question comes from the line of Scott Gruber of Citigroup. Your line is now open.
Yes, good morning. Turning back to service rates, 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 nat gas fuel 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 this spectrum?
Scott, I think that's partially true. Certainly, on the frac side, the higher quality equipment, the superspec e-fleet those have real contracts associated with them with less global room on pricing. So that's why we think generally, we make more money or save more money there on the efficiency side. On the rig side, I think generally, the 10% of your market is going away in a quarter or 2, it's going to have an impact on pricing. There's just no doubt about that. So leading edge rates certainly are lower. I think we've also proven in the past to do more with less when it comes to equipment on the rig side, particularly in the Midland Basin, where it's a lot easier to drill in general than other places around the country.
Got it. 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, go into operating costs?
Yes. Look, 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 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 generally, we received a benefit in terms of gas prices on the power side to lock in a lot of power. And I would say generally, we've locked in about 75% of our expected power needs for the foreseeable future that should keep LOE generally lower for longer and less exposed to the price spikes that we saw last summer.
Got it. Appreciate the color, Kaes. Thank you.
Thank you, Scott.
Thank you. One moment for our next question. Our next question comes from the line of David Deckelbaum of Cowen. Your line is now open.
Good morning, Travis, Kaes, Danny and team. Thanks for taking my questions today.
Sure. Good morning, David.
Morning. Just longer term from an efficiency gains perspective, you all made some headway and you highlighted the benefits of using e-fleets and moving that second e-fleet this year. How do you think about as we progress into '24 and '25, the mix between simulfrac fleet and e-fleets, if we assume sort of this flattish rig count towards the two to two mix, the expectation for longer-term development?
Yes, David, good question. I think our plan right now looking out into '24, '25 is probably to stick with the kind of 50-50 mix. We would basically have to underwrite the e-fleets and sign up for a longer-term commitment with them which is a little harder to do 100% of your capacity committed for a long-term commitment. But the additional simulfrac fleet as more e-fleets come to market and are available in a, I guess, spot basis, we would certainly migrate to more e-fleets that we have some flexibility around utilization.
Got it. And then my second question just around asset sales. You already did around $773 million or so the 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 slide back in the back, mostly on the midstream side might be a source of funds going forward. Could you place like -- is there a high probability that we'll see another asset sale this year?
Yes. I would place a pretty high probability on that, David. We wouldn't have increased our target from $500 million to $1 billion of noncore divestitures if we didn't have a pretty good line of sight. I can't guarantee it's going to happen today, but certainly there's a few things in the works, either on the JV side or some of the small operated midstream assets that could be up for sale. So we still feel very comfortable with that $1 billion target. I would just say it's tailored more towards midstream versus upstream.
Appreciate it. Thanks for the time guys.
Thank you.
Thank you. One moment for our next question. Our next question comes from the line of Roger Read of Wells Fargo Securities. Your line is now open.
Rod, you're on mute if you're on the line.
So let's move to the next question, please.
One moment for our next question. Our next question comes from the line of Kevin MacCurdy of Pickering Energy Partners. Your line is now open.
Hey, good morning. With the 1Q release, you've kind of given the pictures to figure out what the 4Q '22 or '23 CapEx and activity is. As we look into potential 2024 maintenance CapEx program, is the 4Q activity kind of a good activity and CapEx is a good starting point? Or would you need to add any activity to keep production flat next year?
That's a good question, Kevin. I'm not fully ready to commit to 2024 today. But I would say, if we had to commit today, running some sort of plan with for simulfrac crews is probably the most efficient and capital efficient plan we can put together. Now whether that spits out slight growth to flat production is to be determined. But I think generally running this capital efficient plan without changing activity levels too much and letting growth be the output has been, I think, rewarded over the last couple of years with this new business model, and that's kind of where we are circling things going forward.
Great. That’s the only question for me. Thanks guys.
Thank you, Kevin.
Thanks, Kevin.
Thank you. One moment for our next question. Our next question comes from the line of Derrick Whitfield of Stifel. Your line is now open.
Good morning all and congrats on a strong start to the year.
Thank you, Derrick.
Thank you, Derrick.
Building on an earlier question on Waha price weakness, could you perhaps elaborate on the degree of tightness you're projecting with in-basin fundamentals?
Yes, Derrick, good question. I think generally, we are going to see very -- a lot of volatility and some pockets of extreme weakness. Obviously, there's a few expansions coming on, three expansions in the back half of this year and the beginning of next year, ahead of a large flat coming on at the end of 2024. I just think there -- 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, the tune of bcf a day or more 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 for 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 from deals that we bought have not come with taking kind rights, and we've worked to improve that over time and control more of our molecules further downstream.
Great. And then as my follow-up, I wanted to touch on well productivity, which 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 Lario and FireBird acquisitions?
Yes. Good question. I think we said multiple times to investors, flat to 2022 is probably the base case, and we do a little better. That's one for the good guys. I think we are on pace for that, particularly in the Midland Basin where we've had a really strong start to the year. And 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.
Well done, guys.
Yes, Derrick, 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 Kaes just said.
Thanks for the added color, Travis.
Thank you. One moment for our next question. Our next question comes from the line of Scott Hanold of RBC Capital Markets. Your line is now open.
Hey, thanks. Could you all provide a little bit of color on the cadence of activity moving forward? I mean you all talk about having some larger pads going forward. And you all have had a very smooth production trajectory. Does 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?
Yes. 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 are 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, right. It's -- there's a lot going on beneath the surface, and that's what makes the Diamondback operations team the best in the business.
Great. And then if we could talk about M&A a little bit. And it looks like some of the private equity companies are dropping rigs in the Permian. And obviously there have been some sales and talks of more sales coming up. Like what are you all seeing on the private side in terms of activity? And what's your interest level in looking at some of additional M&A opportunities?
Yes, we've commented a couple of times about the increase in activity through 2022 was largely driven by independents and the challenge there is depth of inventory, right? And the secondary challenge is how much can 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, private, just try to figure out a way to monetize. And I think you've also got while their 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 be -- continue to be relevant in the future. And then there's always the large private unicorns that's still flowing 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.
Yes. So do you believe though that some of these private equities that have burned through a lot of their acreage? Does that make -- 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 kind of manage them down there in interest?
Well, Scott, when you do M&A, and if you do it correctly, you want to extend inventory life, you want to make sure that your free cash flow or cash flow accretive and you don't want to impact your balance sheet. So just doing PDP type acquisitions doesn't necessarily fit into that calculus, but it's -- I think that's what you're going to end up seeing with some of these exit strategies or just kind of straight PDP divestitures.
Fair enough. Thank you.
Thank you, Scott.
Thank you. One moment for our next question. Our next question comes from Jeoffrey Lambujon of TPH. Your line is now open.
Good morning, everyone and thanks for taking my questions.
Hi, Jeff.
The 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 compares to that same mix or waiting to that type of acreage last year and just how to think about that mix over the near-term?
Yes, 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. So it was 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 the high-end development is going to drive organic production growth at the entity.
Great. I appreciate that. And then on the services side, I 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 how some of these improvements will layer in from Diamondback specifically over the course of the next couple of quarters?
Yes. I'd say on the rig size, everything is kind of a rolling 3 to 6-month contracts. So we see -- 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, our two e-fleets on the simulfrac e-fleets are pretty locked up on pricing. I would say we saw some weakness in the spot frac pricing in Q1 versus Q4. And as we move those other two fleets to simulfrac fleets, I think the more benefit will be on the efficiency side than the price per horsepower side. But generally, a simulfrac fleet saves up $20 or $30 a foot regardless of the price of actual horsepower.
Jeff, in addition to that, we talked earlier about purchasing steel multiple quarters in advance. So we are seeing the steel that we are purchasing for our 3Q, 4Q, 1Q costs 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.
Appreciate it guys. Thank you.
Thanks, Jeff.
Thank you. One moment for our next question. Our next question comes from the line of John Freeman of Raymond James. Your line is now open.
Good morning, guys.
Hey, John.
You all had -- in fourth quarter, when you all are 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 final fracs as you now go to towards four with funnel fracability, if we end up in a similar spot where you have efficiency gains later this year, is it likely that you all -- and again, it's a first class problem, but would you similarly make a decision like last year where you would sort of, I don't know, pump the brakes is the right word, but maybe slowdown in touch so that the budget is intact? Or do you just sort of plow ahead with the efficiency gains and just bring more wells online?
No. Listen, I think we are highly incentivized to hit the budget. I think high incentivized to increase free cash flow, which is part of the new business model, which has used growth for returns, and that's been the mentality. It's been a working mentality that has worked for the last couple of years. So it would be a first class problem. We are still early in the year, but generally that would be the plan now. I think the only nuance to that is we would like to keep rigs running and building DUCs, particularly if rig costs are a little bit lower than they are today.
That's great. And then I really appreciate all the detail and color you've given on 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 are on track to potentially have lower total completed well costs 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?
Yes. I would say, yes, that's a fair answer. I mean particularly, listen, steel is the biggest driver. I'm not -- we are not forecasting a total capitulation in service costs here. But when steel went up for nine quarters in a row to over $110 a foot, 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 highest.
That’s great. I appreciate it guys.
John, listen, just to reemphasize, we run the business to maximize efficiency as well. And so Kaes made the point that whether it's on the rig side or the completion side, we are about efficiency because we think that that's the greatest driver of shareholder value in a business where you don't control the price of the product that you produce.
Thanks, Travis.
Thank you. One moment for our next question. Our next question comes from the line of Tim Rezvan of KeyBanc Capital Markets. Your line is now open.
Good morning, folks. Thank you for taking my question. I wanted to circle back 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 $1 billion or more on asset sales. So trying to understand, Kaes, what do you think a good kind of target debt level is? Do you think about it in terms of leverage or an absolute debt metric as you compare yourselves to the large cap peers? And I guess why wouldn't you go bigger than that $1 billion given you're not allocating a lot of capital to the Delaware right now?
Yes, Tim, that's a good question. I'm not going to go bigger because we want to beat the number, first of all. 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 of 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.
So we are 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, has been a common theme in the Delaware deals as well as the deal in Glasscock County, not only they pay for PDP, but they paid for some PUDs that didn't compete for us in the next 10 years plan. So if that happens, then we'll look at -- do what's right for our shareholders and look at divesting more in the Delaware Basin. But generally, that production and cash flow has a lot of value to us today.
Okay. And then just getting back to that number in an ideal world, how do you think about what the right debt number is, whether either in debt or in leverage terms for [multiple speakers]?
Sorry, I apologize, I forgot to reply to that part of the question. I think we think about that in terms of -- two ways to think about it, right. Not only absolute debt and the leverage ratio, but also duration. And 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 -- but when we have excess free cash flow, we are 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 next maturity.
Okay. I appreciate the color. That’s all I had. Thanks.
Thanks, Tim.
One moment for our next question. Our next question comes from the line of Charles Meade of Johnson Rice. Your line is now open.
Good day, Travis, Kaes and to the rest of Diamondback team there.
Hey, Charles.
Good morning, Charles.
Travis, this may be for you. I like the new format as well, but the -- 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 to pick up on a big thing for you this morning. But I was wondering also, does this -- 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 [technical difficulty] 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?
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 paid in the prepared remarks, felt like we could remove that. 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, there's 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.
I think it also allows us to talk directly to our shareholders, right? Because a lot of the times, the sell side is in control and narrative and this allows us to -- so a little bit of the story behind the numbers directly to our shareholders.
Insight into your thinking. I appreciate that. And, Kaes, 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, I know I recognize they never are, but all other things being equal, is the shift to buybacks that we saw in 1Q, does that kind of signal a durable shift? Or if not a durable shift to durable change in the preference towards buybacks?
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. So at the end of the day, we are 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 buyback program. So at the end of the day, again, our preference is buybacks, but we have a little bit of a governor on what share price we are going to be aggressive on and Q1 was the perfect example of that.
And Charles, we've tried to be mindful of sins of the past, our industry has been known for, which is oil price goes high, free cash flow goes up and share repurchases are done not counter cyclically like we are trying to do so, but in cycle with higher oil prices and that hasn't created a lot of value. So we may not always be perfect in the calculus, but as Kaes pointed out, whether it's the banking crisis here recently or other forms of volatility, we've had an opportunity to purchase $2 billion worth of shares back at roughly $120 a share. So we feel like we are following through on our commitment of not only being flexible in our return program, but also being mindful of the method and the timing at which you repurchase shares.
Thank you gentlemen. Appreciate the color.
Thanks, Charles.
Thank you. One moment for our next question. Our next question comes from the line of Roger Read of Wells Fargo Securities. Your line is now open.
Yes. Thank you. Good morning.
Good morning, Roger.
Hi, Roger.
Let's dig into the service cost in deflation, I guess, we could call it at this point. We haven'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 as well. I was curious.
Yes, I would say it's a quarter efficiencies and 75% actual costs. Now of the 75%, I would say two-thirds of that is due to raw materials and a third -- and the other third is due to the actual service piece of the equation.
Okay. Yes, that's helpful. 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 fleets? Or as you went from the zipper frac to the simulfrac in terms of how do 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.
I will give you the cost estimates, and Danny can give you the efficiencies. 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.
Yes. I mean an e-fleet towards 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-fleet versus the diesel simulfrac fleets, but we don't have a just a ton of data yet to quantify that, but we are hopeful that over time, the e-fleets will kind of widen the gap of execution efficiency just because of the lower maintenance and R&M stuff that's required on location.
Danny, the difference between zipper and simulfrac in terms of footage per day yield.
Yes, I mean -- so we kind of say simulfrac fleet depending on the jobs can do about twice as much lateral footage per day as a traditional zipper fleet.
Yes. So very, very large differences. One, just a little clarification on your comments 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?
No. It's just a hedge in the market. So it's just a financial hedge, not a physical trade.
Great. Thank you.
Thank you. One moment for our next question. Our next question comes from the line of Leo Mariani of ROTH MKM. Your line is now open.
I just wanted to follow-up quickly on LOE. I just wanted to clarify one of your earlier comments. It sounds like you guys are expecting LOE per barrel decline here in 2Q and 3Q versus where you were in 1Q. Just wanted to make sure I sort of heard that right?
No, we expect it to go up to the midpoint of guidance from $5 to midpoint of $5 to $5.50. So going up slightly due to third-party water handling.
Okay. And you're viewing that is somewhat temporary just based on where the rigs are going to be sort of be drilling location wise here in the middle part of the year?
Yes, just dependent upon where the completions are. The completions are on a third-party dedicated piece of acreage. The cost is higher than it would have been on a prior Rattler [ph] dedicated piece of acreage.
Right. Okay. And then just on cash taxes. Looking at first quarter, you guys kind of came in below the guidance. So far, I guess, quarter-to-date here in 2Q, commodity prices are kind of flat to down. You guys are expecting cash taxes to kind of increase here in 2Q per the guidance. Just wanted to kind of get a little bit more color in terms of how the year plays out? I mean do you generally see cash taxes increasing throughout the year? And maybe that just has to do with NOLs that are completely disappearing in your other tax shield that disappears. But -- any other color kind of around that cadence of cash taxes as the year progresses?
Yes. 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 write-off some of that, the hard assets that came with that right away.
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?
That's fair.
Okay. Thank you.
Thank you. One moment for our next question. Our final question comes from Paul Cheng of Scotiabank. Your line is now open.
Thank you. Good morning.
Good morning, Paul.
I just want to add my appreciation with the new format, I think that's great. Two questions, please. First, you've been increasing your overall activity in the Midland over the last several years. So now it's 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 [indiscernible] maybe sometime over the next 1 or 2 years?
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 0 wells in the Delaware. But on an annual basis, 85%, 15% feels like the right lateral footage mix.
Okay. And the second question is that you talked about the budget. You feel very comfortable about the midpoint of 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 the cost is coming down. How much of them is already or regionally building into that budget? Or that in other words, was that a reasonable probability, you're actually going to be below the midpoint of your budget?
I don't know if I'm ready to commit to that today, Paul. We certainly have some work to do, but we have 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 2 rigs coming down. Now I think that will happen a little bit in Q3 and more in Q4, but it's still early.
Okay. Can you share with us that, I mean, how much of the saving your rate, generally, $1 billion? Or how much is the deflation in the second half that you have [indiscernible] into your budget?
I would say if we saw more service cost deflation that would be upside to what we've modeled here.
Okay. [Indiscernible].
[Indiscernible] not raw materials.
Okay. [Indiscernible]. Thank you.
Thank you, Paul.
Thank you. This concludes our Q&A session. I would now like to turn it over to Travis Stice, CEO, for closing remarks.
Thank you for joining us this morning. I think another benefit of this new format is to allow more questions based on the amount of questions we had this morning. 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.