Diamondback Energy Inc (FANG) — Q1 2023 Earnings Call Transcript

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 indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.

Thank you, Adam. Adam mentioned that we released a shareholder letter last night in conjunction with our press release. I hope you find that useful. We believe that it not only increases transparency directly to our shareholders but also improves efficiency. So we'll move right into questions. Operator, if you would open the line and begin with our first question.

First, thanks, Travis, for the new format. I appreciate it. Travis, my first question is for you or Danny, on one of the top 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 the question relates to what capital expenditures will look like in the latter half of the year. I’ll let Danny elaborate on the specific operational efficiencies we’ve achieved so far this year, which have countered most of the inflationary pressures. When we discuss deflation, it specifically refers to raw materials like diesel, sand, and steel. Particularly with steel, since we purchase it multiple quarters in advance, we already know the costs, which have decreased by $20 to $25 per foot for future purchases. Additionally, as we've been working with a couple of rigs, we've been able to assess our entire rig fleet, and we've noticed that rig costs are also declining. Lastly, although it's not purely a capital expenditure issue, we are experiencing enhanced efficiencies now that our second e-fleet has started up, and we've replaced two spot frac crews with one simulfrac crew, resulting in efficiency gains of $10 to $20 per foot. Regardless of what happens with capital expenditures, our commitment has consistently been to lead as the low-cost provider in executing our development plan, which we have demonstrated for nearly a decade. We anticipate continuing this approach, and I hope that reassures our shareholders. Danny, do you have any further insights for the near term?

No, I think Travis covered everything that we've observed on the drilling services side and consumable side. On the drilling side, the leading edge costs are coming down. And then on the completion side, we’re seeing additional efficiencies from the extra e-fleet as well as the replacement of the simulfrac fleet replacing the two traditional zipper fleets that we took over due to the acquisitions at the end of the year.

Great. Thank you for that. And then my second question is 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 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, when we increased the shareholder return program to 75% of free cash being returned to shareholders, we believed that allocating 75% to equity and 25% to the balance sheet was appropriate. We still think that's a solid approach. When times are good, as they have been in the past couple of years, 75% seems like the maximum we should return to equity while still enhancing the balance sheet. The real test of this new capital return business model will come during potential downturns. That's when we should focus on allocating more capital to share buybacks, reducing the share count more effectively than we do when things are going well. We've kept a flexible approach to capital returns from the start, and we want to maintain that flexibility. The first quarter is a prime example of why we hold onto this flexibility. We don't want to overextend the balance sheet for stock buybacks, but we also understand that when your stock price drops significantly in a quarter, a variable dividend loses its effectiveness. That's why in the first quarter, we chose to direct more cash toward buybacks.

Glad to see it. Thank you all.

Thanks, Neal.

Yes. Good morning, team. And again, thanks for the new format. My first question was around gas price realizations. Obviously, they were soft in the quarter. There are 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 do 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 the unhedged realized gas prices for us that were weaker in the quarter relative to expectations. A lot of that comprised a $15 million true-up payment between contracts that moved from selling at the wellhead to taking on 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 are going to be periodic points of weakness throughout this year and next, is that we've hedged all of our Waha exposure in the basin, which is about two-thirds of our gas through the end of 2024. The other one-third of our gas gets a combination of Henry Hub and Houston Ship Channel prices. On the Henry Hub side, we've 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 in your portfolio for a couple of months. 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, with 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 are almost 500 locations on that acquisition without even pushing the limit on upside locations. Some well tests have co-developed the Lower Spraberry and the Wolfcamp A on the southern part of the position, giving us confidence that some of those upside locations are going to become real locations that we are going to develop over time. Secondly, the ops team, they’re going into a new area. We are already completing or drilling a 15,000-foot lateral in under 10 days in 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.

Good morning, guys. We do appreciate the new format; 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 the midpoint of the range of $2.6 billion for the full year?

Yes.

How does your cash accounting for capital expenditures impact the timing of those expenditures in an environment of rising service prices compared to when prices are falling?

Yes. Good question, Arun. The cash CapEx thing, the prime example was Q2 of 2020, while I don't want to relive that quarter, we reduced our rig count from 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; we are 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: 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 lastly, midstream infrastructure. We spent a lot of money on midstream, building out our Martin County water system that's nearing its end, so 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 reiterate, Arun, to reiterate my opening comment to the first question is that our commitment to our shareholders remains unchanged to be the low-cost leader in efficiency and execution. 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 covering 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 and 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 into 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 get to take the front seat to leasing any of those deeper rights should they be unleased throughout the basin.

Great. Thanks a lot.

Thank you, Arun.

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 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 believe 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 two is going to impact pricing. There's just no doubt about that. So leading-edge rates are certainly lower. I think we've also proven in the past that we can 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, such as chemicals that factor 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 some of our activity is moving to areas where we have water dedicated to third parties, not ourselves. And so that has a slightly higher rate. We expect LOE to trend up a little bit in Q2 and Q3 as some of those large pads on third-party areas are developed. But generally, we've received a benefit regarding gas prices on the power side to lock in a lot of power. I would say generally, we've locked in about 75% of our expected power needs for the foreseeable future, which should help 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.

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 a two-to-two mix of the expectation for longer-term development?

Yes, David, good question. I think our plan right now looking out into '24 and '25 is probably to stick with a 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 with 100% of your capacity committed for a long-term commitment. The additional simulfrac fleet, as more e-fleets come to market and are available, we would certainly migrate to more e-fleets if we have some flexibility around utilization.

Got it. My second question is about asset sales. You've already accomplished around $773 million in sales to date, surpassing your target. You also mentioned the remaining five or so outstanding investments noted on the slide, primarily in the midstream sector, which could serve as a potential source of funds in the future. Is there a good chance that we will 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 non-core 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 are a few things in the works, either on the JV side or some of the small operated midstream assets could be up for sale. 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.

Rod, you're on mute if you're on the line.

So let's move to the next question, please.

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 the potential 2024 maintenance CapEx program, is the 4Q activity kind of a good activity and CapEx 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 simulfrac crews is probably the most efficient and capital-efficient plan we can put together. Now whether that results in slight growth or 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.

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 elaborate on the degree of tightness you're projecting with in-basin fundamentals?

Yes, Derrick, good question. Generally, we are going to see a lot of volatility and some pockets of extreme weakness. Obviously, there are 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 the issue to date has been masked in the field as processing capacity in the field was short. Now that that processing capacity is coming on, to 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 control all of our molecules to the Gulf Coast, but most of our contracts we inherited from deals that we bought haven't come with taking kind rights, and we’ve worked to improve that over time and to 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've said multiple times to investors that flat to 2022 is probably the base case, and we can 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. 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, and it's our job to ensure we have the inventory duration and 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 in efficiency and cost execution. It's exactly what Kaes just said.

Thanks for the added color, Travis.

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 all have had a very smooth production trajectory. Do some of these large pads 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 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.

Great. And then if we could talk about M&A a little bit. It looks like some of the private equity companies are dropping rigs in the Permian. 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? What's your interest level in looking at some additional M&A opportunities?

Yes, we've commented a couple of times that the increased activity through 2022 was largely driven by independents, and the challenge there is depth of inventory. The secondary challenge is how much can increase further beyond their max cadence that they achieved last year. I think both of those are playing out now. The max cadence may be softening, as evidence by rigs getting laid down. Certainly, the inventory depth is getting accelerated with the 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. I think you've also got while their catalyst is unclear, some small-cap public companies that are going to need to figure out some form of exit strategy to remain relevant in the future. There's always the large private unicorns that are still flowing around out there. So I 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 the inventory factor less interesting to you all? Or is there a case to be made if you can buy PDPs cheap enough and manage them down their interest?

Well, Scott, when you do M&A, and if you do it correctly, you want to extend inventory life, you want to ensure your free cash flow or cash flow is 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 I think that's what you're going to end up seeing with some of these exit strategies or just basic PDP divestitures.

Fair enough. Thank you.

Thank you, Scott.

Good morning, everyone, and thanks for taking my questions.

Hi, Jeff.

The first one is just on commentary in the supplemental release that talked about the trend continuing this year in terms of the large high NRI pads coming on in the Northern Midland Basin. Is there any additional color you can give there in terms of how the mix of the total program going to that type of acreage where you might have much less surrounding development compares to that same mix or weighting 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. The quality of the location of those undeveloped DSUs is probably a bit higher this year than in 2022 even. So it’s 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 we have up to a 6% or 7% NRI on large pads at the Viper level. 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 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 on rolling 3 to 6-month contracts. So we can see our Q2 average day rate is down from Q1 today. And 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. 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. Generally, a simulfrac fleet saves about $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 3Q, 4Q, 1Q costs already coming down. And 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.

Good morning, guys.

Hey, John.

In the fourth quarter, when you were ahead of schedule, you transferred some of those POPs from the fourth quarter to the first quarter. Considering the significant efficiency improvements on final fracs as you move toward simulfrac capability, if you find yourself in a similar situation with efficiency gains later this year, would you consider making a decision like last year where you might slow down a bit to keep the budget intact? Or would you just continue to push forward with the efficiency gains and bring more wells online?

No, listen, I think we are highly incentivized to hit the budget. I think we are highly incentivized to increase free cash flow, which is part of the new business model, which has used growth for returns. That has been the 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 want to keep rigs running and building DUCs, particularly if rig costs are a little lower than today.

That's great. I really appreciate all the detail you've shared about service costs. It seems that while things are coming down from the peak levels of the first quarter, are you indicating that you are on track for lower total completed well costs by the end of 2023 compared to the end of 2022? This consideration takes into account what you're observing on the cost side, but 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 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. I mean that in itself accounts for a significant percentage of the savings. So I would say yes, Q4 2023 well costs are 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'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.

Good morning, folks. Thank you for taking my question. I wanted to circle back to David's questions previously on asset sales. I'm sure you won't give a good answer on the Bloomberg story about Pecos County. But I think it highlights the number of levers that you can pull to get to $1 billion or more on asset sales. Trying to understand, Kaes, what do you think a good 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? Why wouldn't you go bigger than that $1 billion, given that 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. 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. The recurring theme of what we’ve sold is that someone paid for upside. We aren’t 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. That’s been a common theme in the Delaware deals as well as the deals in Glasscock County; they not only paid for PDP but also 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 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 in debt or in leverage terms?

Sorry, I apologize. I forgot to reply to that part of the question. I think we think about that in two ways: not only absolute debt and the leverage ratio but also duration. 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. 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 the next maturity.

Okay. I appreciate the color. That's all I had. Thanks.

Thanks, Tim.

Good day, Travis, Kaes and the rest of the Diamondback team there.

Hey, Charles.

Good morning, Charles.

Travis, this may be for you. I like the new format as well, but I was also thinking about the shareholder letter. In your prepared comments, I think you said you were hoping this format would be more efficient for picking up on a big thing for you this morning. But I was wondering also, does this iteration on your communication style reflect any element of dissatisfaction with how either your story is being understood or the traction you’re getting? Or do you feel like something is getting lost in translation? If yes, what do you think the market might be missing?

No, we didn't put this letter in place trying to fix a communication issue. We've got incredible transparency and communication with our shareholders. We thought that after a decade of doing these earnings calls, the lack of attention in the prepared remarks felt like we could remove that. Other industries are well ahead of the oil and gas sector by not doing prepared remarks. This letter allows us to communicate more efficiently and directly with our shareholders.

I think it also allows us to talk directly to our shareholders, right? Because a lot of the time, the sell-side is in control of the narrative, and this allows us to tell a story behind the numbers directly to our shareholders.

I appreciate your insight. Kaes, I would like to revisit the question regarding the buybacks. I know this has been touched upon earlier, but if we assume that all other factors are constant, which I understand they usually are not, does the transition to buybacks that we observed in Q1 indicate a permanent preference towards them, or is it likely to be temporary?

Listen, I think our preference has always been to buy back shares. What we wanted was a governor on what fundamentally we are buying back shares for. Are we buying back oil in the market cheaper than we can buy it in the ground? That's our NAV versus looking at a deal like Lario or FireBird. Ultimately, we are still going to run our NAV at a conservative mid-cycle deck, which is $60 oil. The market has continually presented us opportunities to buy back shares every quarter since we started this buyback program. So at the end of the day, our preference is buybacks, but we have a governor on what share price we will be aggressive on, and Q1 was a prime example of that.

And Charles, we've tried to be mindful of sins of the past. Our industry has been known for oil prices going high, free cash flow going up, and share repurchases being done not counter cyclically, but in cycle with higher oil prices, and that hasn't created a lot of value. 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. We feel like we are following through on our commitment to be flexible in our return program, being mindful of the method and timing at which you repurchase shares.

Thank you, gentlemen. I appreciate the color.

Thanks, Charles.

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 been 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, be it 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 about 75% actual costs. Of the 75%, I would say two-thirds of that is due to raw materials and a third of 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 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 using our simulfrac fleets is just powered by electric power we generate on location or that we pull off the grid. 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 ton of data yet to quantify that. However, we are hopeful that over time, the e-fleets will widen the gap of execution efficiency due to lower maintenance and R&M stuff required on location.

Danny, the difference in footage per day yield between zipper and simulfrac?

Yes, we believe that a simulfrac fleet can achieve about twice the lateral footage per day compared to a traditional zipper fleet.

Yes. So very, very large differences. One last question, just a little clarification on your comments about locking in some of your electricity costs and being able to predict your LOEs better during the summer. Is there any interruptible risk with those contracts? I am not talking outages, which would affect everybody, but just to get the lower cost or fixed cost, do 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.

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 decline here in Q2 and Q3 versus where you were in Q1. Just wanted to make sure I 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 as somewhat temporary just based on where the rigs are going to be sort of drilling location-wise here in the middle part of the year?

Yes, just dependent upon where the completions are. If the completions are in a third-party dedicated piece of acreage, the cost is higher than it would have been on a prior Rattler dedicated piece of acreage.

Right. Okay. And then just on cash taxes. Looking at the first quarter, you guys came in below the guidance. So far, I guess quarter-to-date here in Q2, commodity prices are kind of flat to down. You guys are expecting cash taxes to kind of increase here in Q2 per guidance. Just wanted to get a little bit more color on 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 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 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 Q2 is more of a normal representative rate going forward?

That's fair.

Thank you. Good morning.

Good morning, Paul.

I just want to add my appreciation for 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. 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 you may start to do more in maybe the Delaware 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. You had 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 of the cost saving or that you're talking about the line of sight of costs is coming down? How much of that is already or reasonably built into that budget? In other words, was that a reasonable probability that 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 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 how much of the savings you rate, generally about $1 billion? Or how much is the deflation in the second half that you have built into your budget?

I would say if we saw more service cost deflation that would be upside to what we've modeled here.

Okay. Thank you.

Thank you, Paul.

Thank you for joining us this morning. I think another benefit of this new format is allowing more questions based on the number of queries we had this morning. If you have any additional follow-up that you need, just reach out to us using the numbers that we provided earlier. Thanks again for joining. Have a great day.