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Diamondback Energy Inc
Earnings Call Analysis
Q2-2024 Analysis
Diamondback Energy Inc
Diamondback Energy's second quarter of 2024 earnings call highlighted several key aspects of their operations, financial strategies, and future directions, emphasizing efficiency improvements and shareholder returns.
A focal point of the call was the significant increase in operational efficiency. Diamondback has managed to drop its rig count from 14 to 10 while maintaining production levels. This was made possible by increasing the number of wells per rig from 24 to 26 per year and improving completion rates to over 100 completions per crew per year .
The addition of new assets from Endeavor has further leveraged Diamondback's efficiency. Travis Stice, CEO, noted that the cost-saving synergies from this acquisition have already surpassed initial expectations set in February. This acquisition is likely to double the size of Diamondback's operations, enabling the firm to apply its efficient drilling techniques on a larger scale .
Kaes Van't Hof, CFO, discussed the company's flexible capital return program. Depending on oil price scenarios ($70-$90 per barrel), the company plans to either increase share buybacks or pay higher variable dividends. The goal is to maintain stability even in lower oil price environments by using free cash flow effectively .
Diamondback remains financially prudent, targeting a base dividend breakeven at $40 per barrel of crude oil. This conservative approach allows the company to maintain operational and financial stability even in volatile commodity markets. The company aims to use any excess free cash flow for share buybacks if oil prices drop significantly .
The company raised its oil production guidance by approximately 1.5%, reflecting confidence in its operational efficiencies and future prospects. They also plan to slightly increase capital expenditure to ensure continuous improvement and production stability. The completion of 7% more feet of drilling is expected to bolster this growth further .
Diamondback is investing heavily in downhole sensing technology, which enhances drilling precision and efficiency. Such advancements allow the firm to stay ahead of competition by maximizing productive drilling times and stimulating rock volumes more effectively .
Looking forward, the company plans to maintain a stable rig count and continue focusing on core operational efficiencies post-2024. The combined assets from the Endeavor acquisition are expected to drive further improvements and ensure sustained growth in the coming years .
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Good day, and thank you for standing by. Welcome to the Diamondback Energy Second Quarter 2024 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, VP of Investor Relations. Please go ahead.
Thank you, Steven. Good morning, and welcome to Diamondback's Second Quarter 2024 Conference Call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, Chairman and CEO; Kaes Van't Hof, President and CFO; and Danny Wesson, COO.
During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC.
In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.
I'll now turn the call over to Travis Stice.
Thank you, Adam, and I appreciate everyone joining this morning. I hope you continue to find the stockholders' letter that we issued last night an efficient way to communicate. We spend a lot of time putting that letter together, and there's a lot of material contained in the text.
Operator, would you please open the line for questions?
[Operator Instructions] The first question comes from the line of Neal Dingmann of Truist.
Travis, nice results. Travis, my first question is on sort of the leading capital efficiencies you all continue to highlight. Specifically, could you talk about the latest announcement, I think you guys talked about dropping to 10 from 12 rigs and I think what that's even versus 14 a few months ago. And I'm just wondering how the drilling efficiency is so good that you're able to maintain the pace with nearly 30% rigs than just a few months ago and just wondering how you anticipate or if you anticipate the same type of efficiencies once you take over the Endeavor assets?
Sure. Good question, Neal. The first half of the year was really typified by us doing more with less and we gave some numbers there, but just to repeat some of those. In January of this year, we estimated that we could get 24 wells per rig per year. And now we're up to 26 wells per year for the rest of the year. And you see a similar efficiency gain on the completions where we previously signaled 80 completions per year per crew, and now we're up to over 100 completions per crew per year. Those are some of frac crews.
And look, as we look into the future, one of the things that I get excited about is that these efficiencies are things that we don't get back. And so as we incorporate after close the new assets from Endeavor, I fully anticipate our operations organization, combined with Endeavor's operations organization will be able to continue these results.
And what's significant about that is when we talk to the market on February 12, announcing this deal, one of the biggest -- the biggest synergy that we talked about was being able to apply Diamondback's current D&C cost on a larger asset. And I'm pleased to say today, we're significantly below where we were in February. So that just accrues the benefit to our shareholders and really supercharges the delivery of the synergies that we were talking about. So yes, Neal, I'm very confident that we'll be able to continue this leading-edge capital efficiency on a larger asset base.
Great to hear. And then I want to ask just quickly on shareholder return plans maybe just on sort of broad stroke specifically, how would your plan vary? I mean, obviously, oil prices are jumping around could be anywhere from $90 to $70 environment. I'm just wondering, given your market sort of the leading cost that we see on Slide 9, I'm just wondering, depending on where oil prices go, is that just a matter of having more free cash flow buybacks, some variable dividends? Or would there be any other changes we see in a high oil price environment for some lower oil price environment?
Yes, Neal. I mean, I think the key point here is we've always had a very flexible return of capital program since the very beginning. When we put this in place in 2021, we've said we'd like to be able to flex between buying back shares and paying a variable dividend. And we take that capital allocation decision very, very seriously. So we're set up in a way where if you have periods of weakness like we've seen over the last week or 2, that's when the buyback kicks in. And if it continues to be weak, we'll continue to buy back more shares. That's the benefit of having a low breakeven on your capital program, low breakeven on your base dividend and continuing to generate free cash flow down to much lower numbers than peers or than what the market is used to.
So I think we're excited. If things do stay weak, we'll flex that buyback and be aggressive there. And if things improve, and we have a good quarter in the 80s or 90s on crude, then -- and we'll have a big variable dividend. But I think that flexibility has been very, very advantageous to our shareholders over the last 3 years.
And Kaes, how long is that breakeven gotten down to?
Listen, we were very focused on looking at our base dividend breakeven at $40 crude. So mid-cycle capital costs, $40 crude, we could keep production flat. I don't think in a $40 crude scenario, and we do that. I think kind of lessons learned from what we've seen through the cycles over the years is that it's okay to let production decline, if we were in a very, very weak commodity price scenario. But in that scenario, we should be allocating 100% of our free cash flow or even more to buying back shares because in that situation, your share price is going to be -- likely be very weak. So we're really trying to move the capital allocation decision from the field and the assets to what do you do with your free cash flow. And that, I think, is a good place to be.
Our next question comes from the line of Neil Mehta of Goldman Sachs.
Congrats again on very strong execution here. You've talked about getting that net debt level lower post-transaction. Kaes and Travis, how do you see yourself doing it? Is it through asset sales or through organic free cash flow generation? Just your perspective on the asset sale market, recognizing you did some small deals here in the quarter.
Yes, Neil, I mean, I think when we announced the deal, we're very conscious of the cash stock mix that we put in place for the Endeavor merger. I don't think we put -- we didn't put so much cash in the deal that we had to be a seller of assets. But what you've seen us do is sell multiple things now over the last couple of quarters that start that up, right? We sold a little bit of our Viper ownership to take some risk off the table and get some cash in the door. We sold our interest in WTG, West Texas Gas to Energy Transfer, will get some cash in the door. And then little things like our low [indiscernible] that we did last quarter. All that kind of almost adds up to $1 billion which on top of free cash flow generation between January 1 and today is going to reduce the cash outflow burden for the Endeavor deal.
So I think we planned on looking at the deal as a delevering process through free cash flow, but the asset sales are a kicker that accelerates that. And I think we're highly focused on getting to $10 billion as quickly as possible. And then I think things can slow down from there. But I don't think you'll see us be a forced seller of assets post deal close. And I think we're going to be very, very stingy on keeping operated properties in the Permian because they're kind of worth their weight in gold right now.
Yes, it makes a ton of sense. And then just your perspective on managing gas price volatility. First of all, what are your latest thoughts on Matterhorn and when that comes in? And then secondly, how do you mitigate some of the risks around gas prices, so you can really from the margin that you deserve on the oil side of the equation?
Yes. That's been a big topic lately. Obviously, we need to start making more money on our gas in the Permian and Diamondback specifically. If you look back to the history of Diamondback, we've grown through acquisition. A lot of the deals that we've done have with marketing contracts where we don't control the molecule much further than the wellhead. And so what we've been doing over the last, I'll call it, 5 years is as contracts roll off, we've been taking advantage of that and getting -- taken kind rights on that molecule.
We started with our commitment to Whistler and have grown that, that combined with Matterhorn, will have a little of gas on both of those. And then I think you saw a press release last week that we're going to be able to spend in the next pipeline from those guys, the Blackcomb pipeline.
And I just think that's the strategy of, let's say, control of our molecules and see what we can do with them. And I don't think that stops at pipeline commitments. We're really looking at power needs in the basin, things like our Verde gas to gasoline plant and to try to find ways to create a local market here in the Permian because it's a shame that we continue to sell gas maybe 0 or below 0. So it's on us to continue to improve that portfolio. And I think with size and scale and time, we'll be able to do that.
Our next question comes from the line of Arun Jayaram of JPMorgan Securities.
My first question is just on the efficiency gains you highlighted in the letter. It looks like you're pushing your drilling cycle times to 26 wells per rig and on the completion side, pushing 100 wells per frac fleet, SimulFRAC fleet. I was wondering, Kaes and Travis, you could describe what the drivers of that -- those efficiency gains are? And perhaps help us think about what's underwritten in the pro forma $4.1 billion to $4.4 billion guide for Endeavor for calendar '25?
Sure. On the rig side, we specifically talked about a [ bit of auto ] assembly improvements. And again, that's not necessarily the adoption of some new emerging technology. I think it's really another example of what our guys do really, really good, which is a laser-like focus on every decision it's made. They measure almost every attribute of drilling the well and they seek for improvement and they compete against one well versus the other. And we pay bonuses to the crews out there when they execute in a stellar fashion.
So it's not something, again, that's easily repeatable and it's not a shelf item that someone can go take but it's a culture of execution that's always been part of this business.
On the completion side, there's been some design changes where we've increased rate, but we've also continued to try to optimize the exact way that we mobilize equipment. We've done some changes on some pipe downhole that allows at a greater rate with less friction loss. So again, it's nothing that's a marquee item, but it's just an intense focus on doing what it is that we do, which is really, really execute well when we convert rock into cash flow.
Yes. Listen, I mean all these things certainly have occurred to us since we announced the Endeavor merger in February. I think as Travis mentioned earlier in the call, these are permanent items that aren't going to go away from service cost inflation or deflation. So as we work through the pro forma model, these -- we're probably thinking that we're going to run closer to 18 to 20 rigs next year versus 22 to 24 a while back and closer to 4 to 5 SimulFRAC crews versus 5-plus. So I think we're certainly modeling these things occurring for the good guys and it only gives us a head start on the promises we made on 2025 numbers.
Great. My follow-up is just on the raise production guide. You raised your oil guide at the high end by close to 1.5% just under that, and then you took up CapEx. Kaes, one thing that wasn't quite intuitive is that you're completing 7% more feet on a net basis. And so one of the questions that's come in is would have thought maybe the oil increase would have been a little bit higher based on that level of completed footage, but maybe you could help reconcile that for us this morning.
Yes. I mean I think -- I don't think wells are completed like they look to be completed in the spreadsheet, right? I mean in 2022 well pads, you move 1 pad from 2023 into 2024, and you got 22 extra wells. So we kind of moved almost, I think, 30 wells from 2023 into 2024. So our well count is a little bit higher than maybe a true level loaded run rate would be.
But I think we're also just preparing a room for a major acquisition to close. And I think we're doing everything we can on our side to be prepared to hit the ground running and hit numbers right away and do exactly what you would expect us to do.
So I think more importantly, it's the more drill lateral footage for less CapEx, that gives us a lot of flexibility in the second half of the year and carry that momentum into 2025.
Our next question comes from the line of David Deckelbaum of TD Cowen.
I wanted to follow up on some of the earlier questions. You've obviously seen a lot of field efficiencies, particularly on the drilling side. You've lowered the Midland footage cost down, I guess, putting some dollars at the midpoint. But curious, like as you approach the 3Q -- potentially 3Q or 4Q Endeavor closing. Are there any parts of the efficiencies that you're seeing that you don't think that you could accomplish with -- as a synergy here? Because it would seem like that $300 million or so of synergies that you -- a portion to just CapEx savings is increasing by the day?
Well, that's why I highlighted, David, that where we are today is much better in performance and execution than where we were in February when we talked to you about this deal. These are cultural elements. This attention to detail this focus is laser-like attention to execution. And we look forward to bringing on our new friends from Endeavor. And look, the -- from what we hear from them anecdotally, they're seeing similar efficiency gains as well, too. So when we put the 2 cultures together, I expect it to be an ad or not a detractor when we actually put the 2 companies together here before too much longer.
Appreciate that. And then just a follow-up to that. You've also seen the benefits of longer lateral progression, I guess, relative to your original plan this year. I know one of the things you highlighted with the Endeavor deal was the potential increase of lateral lengths to 15,000 furthers and beyond on given 100,000 plus number of acres. How do you see the progression, I guess, into next year and then '26 in terms of lateral lengths relative to where we're at today? Or is this something that's a longer-term Endeavor?
Well, first, we're going to have to get the 2 assets put together, which we obviously can't do that currently. I'll let Kaes answer the synergy question specifically, but I wanted to highlight something that we talked about in our earnings release and our stockholder letter was that we drilled a 20,000-foot lateral well with -- in under 8 days, under 9 days -- yes, 7, 8 days. And longer is not going to be a problem, it's just we need to make sure we have the least geometry to be able to drill even longer wells.
Yes. I mean I think, David, on the plan, we can't put anything together until post close. But I think the priority for the teams right now is what does the plan look like end of '24, into '25 post close. And then what were the projects look like starting the back half of '25 and into '26 that start to extend laterals. I mean I think holding the level that we have this year, almost 12,000 feet on average for 300 wells is a pretty stellar number that we should probably look to maintain. I think going much further than that for a full program of 500-plus wells a year is going to be tough to do. But I don't think the guys are scared of drilling to 20,000 feet. We have those opportunities, we'll take advantage of them.
Our next question comes from the line of John Freeman from Raymond James.
First topic I just wanted to follow up on is on the return of capital framework. And when you look at Slide 6 and just sort of think about, again, the efficiency gains that have -- are really impressive. And as over time, does that sort of drive that maintenance CapEx on a reinvestment rate lower. Should we think of maybe the first kind of evolution of that return of capital framework just being that creates like a bigger, I guess, for lack of a better word, wedge that can go to that base dividend. Is that more likely kind of the way it would evolve as opposed to maybe increasing that 50% plus that's going to shareholders overall?
Yes, John, I mean, I think those are 2 separate decisions. But I think you hit the nail on the head on as efficiencies accrue and the -- our decline rate shallows over time and your balance sheet shrinks over time, that should create room there between your breakeven and your $40 dividend breakeven. So I think that's how we're still going to look at it. I think we see $40 on the E&P side as a very well-protected number. We're still going to buy puts at -- right now, we're buying them at $55, $60 crude but eventually probably reduce the value of our foot buying down to closer to $50 just to protect the extreme downside scenario.
And I think the rest of the free cash we did move back from 75% of free cash going to equity down to 50%. But that doesn't mean that number is not going to be higher in the future in times of stress.
I think in times of stress or significant stress, the number should be a lot higher than 50% of free cash going to equity. And when things are going well, the number should be closer to 50% and we'll continue to build a fortress balance sheet.
I've been very pleased with the response from our large shareholders on cutting back to 50% of free cash going to equity because they want us to have more fortress balance sheet than we even going into the deal. So I think that's been a pleasant relief and allows us to build a lot more cash and be ready for the inevitable down cycle in this sector.
And John, I think a good way to demonstrate or a good way to visualize the Board's commitment to this sustainable and growing dividend is on Slide 7, go the way back to 2018 when we initiated the dividend. And you can see on that slide, the growth rate. And on the bottom half of that slide, you can see that our commitment has translated into almost $8 billion of capital return to our shareholders. So it's a meaningful lever that we have as a company and the Board's commitment to continue that sustainable and growing dividend.
That's great. And then just my follow-up when we take these efficiency gains that have allowed you all to basically [ pump ] the brakes on rigs and frac crews in the second half of the year without missing a beat on the original production plan. Is there any environment where you all would choose to basically just sort of plow ahead at the run rate you were on in the first half of the year and just sort of allow production growth to accelerate? Is there any sort of an environment where you would foresee that ever kind of occurring?
Yes. Just where we sit right now, John, that's not a logical scenario that we see playing out in the next 6 months -- 3, 4 quarters.
Yes. I mean historically, I mean, we've tried to post-COVID favor free cash flow generation over growth. And I think you're seeing that trend continue here with what we're doing in 2024.
Our next question comes from the line of Scott Hanold of RBC Capital Markets.
There's been a lot of talk of good operational efficiencies. Could you maybe pivot and talk about what you're seeing in terms of well performance and productivity over the last year, is it pretty much status quo on an apples-to-apples basis? Or are you seeing some gains there as well?
I would say, generally, on a yearly average basis, we see this year as kind of going to be flat to last year. But I think what's unique is that we're adding a lot of Wolfcamp B, Upper Spraberry, more Jo Mill. We're adding more zones to our Midland development plan and getting the same output in terms of productivity.
And so the resource expansion story probably goes sometimes unnoticed in the Permian, but talking about a zone like the Upper Spraberry, where we haven't -- hadn't drilled a well until 2 years ago outside of one Energen well in 2018, now becoming part of the stack of co-development without a degradation in well performance is truly what makes the Midland Basin unique.
So I think we've had a few really, really good years of well performance. We're always trying to keep pushing the performance side. But I think this year has been a year of cost gains versus well performance gains, but that doesn't mean there's not significant inventory expansion going on across our portfolio.
And then my follow-up question is you kind of highlighted, obviously, all the drilling efficiencies again.
And I think you made a comment that from what you understand, the Endeavor folks are seeing some similar stuff. But can you give us some context like based on your -- what you can see from your understanding at this point? Where is Endeavor relative to where Diamondback is?
So just trying to get a sense of should we expect once the merger is complete, comes together, there's still some work to do to get it back -- to get it all toward where Diamondback is right now? Or is it going to be pretty much just hitting the ground running?
Well, it's going to be hard work for sure. It's our job to do that hard work and make it look easy for you guys. There's some decisions that will make pretty soon after we combine the 2 companies. One would be the use of clear drilling fluids and the second would be to put more of the frac operations on to SimulFRAC.
So those are the 2 biggest levers that have the quickest change. But look, we're also going to -- like we've always done, check our egos at the door and make sure we seek to understand what the Endeavor team is already doing. And historically, that's generated better results when we seek first to understand and then pick the best path forward with the combined inputs from legacy Diamondback in the new asset -- new management from Endeavor.
So we're going to make it look easy, but it's -- there's going to be -- it's always -- it's hard work behind the scenes. But I'm really confident that both of the 2 leadership teams are going to be able to pull this off and make it look good.
Yes. I mean I think from a number's perspective, the way we're thinking about it is the pro forma business will be running basically kind of 21, 22 rigs off the start. And then by 2025, we'll probably be averaging closer to 18 to 19 combined.
Our next question comes from the line of Bob Brackett of Bernstein Research.
Following up on those intriguing operational efficiencies. You mentioned the average of 26 wells per rig year, 100 wells per crew. What's the pace setting rig or crew look like? Is it significantly ahead? Or is there a big opportunity to grab?
Bob, it's Danny. Yes. I mean I think there's the crews and the rigs they're pretty well all within a margin of error of each other and their performance. We've been really pretty active on fleet management over the past few years and continue to optimize our fleet where we see dwindling performance.
And the best thing about our operation is the collaboration we have between the teams on sharing best practices on best-in-class rigs. So when we look at the rigs across the board, there's always one pace-setting rig. But that tends to move around as we share best practices and the other rigs catch up than another one will pass that rig. So not one unique standout that's driving that number, it's pretty well across the board at that same level of efficiency.
We do have a pretty healthy competition between internally and then we also every quarter, we look externally, and there's a pretty healthy competition. And that's why in our stockholder's letter, I talked about in this quarter in the Midland Basin, the drilling team got over 20,000 feet with a single bit run and that represents a record in the Midland Basin. So I'm sure that record will fall, but it's just part of the culture of evaluate internally and externally and compete to win, and that's what our organization does.
Very clear. A quick follow-up along that line. How do we think about the relative price between pulling on that ROP lever versus reducing nonproductive time or even reducing [ mob, demob ] time? Are they equal size prices? Or is one the more obvious in the 3.
I think it kind of moves, but you're getting to the point in time where there's -- the little things we're focusing on now are the efficiency drivers. We call -- last call about the guys focusing on pipe makeup speeds because that was where they saw the most NPT time on a well was just how long it takes some of the break and make up pipe.
And we're constantly looking at where that dead space is in these jobs and trying to attack. And we don't just attack one, that space, we will tackle them all at the same time. And I think NPT time has been a focus of coming out of the really aggressive activity levels we saw in '23. And we've really done a good job of reducing NPT time. But there's certainly always things we can focus on there to continue to drive uptime and drive constant performance and not waiting on the sidelines for something to be fixed.
And when we look at those details, we do it every quarter, for sure. And what Danny talking about requires a great deal of collaboration across all the teams. And even I emphasize the competition aspect of what it is that we do, the collaborative aspect is really where this sits home because when one team finds a solution, it's quickly shared with all the other teams internally. And in a similar fashion, if we find something externally, we quickly adopt that as well, too.
Our next question comes from the line of Roger Read of Wells Fargo Securities.
Congrats on another solid quarter, guys. Just a couple of questions kind of operating focused here. One, if we look at the production beat here in the second quarter, you got it on NGL and gas. We were just sort of curious -- we kind of figured maybe you strip more liquids out of the gas, but then you would have lower gas production. So maybe a little bit of insights into kind of what's lifting the NGL side and keeping the gas production up?
Yes. I think on the NGL side, I'm trying to put as much ethane as you can in the NGLs to get them out of the basin. We even probably -- throughout the second quarter, we saw, obviously, a lot of gas price weakness. So we did take a couple of our highest GOR wells down for a month or 2 to ease the pressure.
So I think even in the face of that, the gas curve continues to outperform expectations, but we kind of even curtail a little bit of oil to make sure our gas production was a little bit lower in the quarter, which we kind of have continued in the third. So we just have a lot of gas production out of this basin, and that's kind of why we have such a focus now on trying to generate more value for the gas that we're producing, whether that'd be in basin or out of basin.
Yes. And just to add to that, the focus on around environmental performance has driven a lot of decisions to not earn gas in the field for energy consumption and instead convert that energy demand to electrical demand. And so you're seeing a lot of gas that would have otherwise been burned in the field to run our operation being put down the pipeline. And then on top of that, the focus on reducing flaring, those are all things that send gas to sales and gets reported as a production number that's driving some of that increase you're seeing across the basin.
Okay. That's helpful. And then just coming back to the drilling efficiencies and the completion efficiencies going from 24 to 26 wells, 100 completions. Can you give us an idea of maybe where the, call, it upper 10% or upper quartile is? In other words, I'm trying to think of if 24 went to 26 is the best 30 and that's where you can ultimately go? Or it's a much tighter dispersion? So it's 26, the average best 28, maybe worse is 24. I'm just trying to get a feel for the further improvements kind of the same idea on the completion side.
I think it's a good question. The -- it just depends, but we certainly have some rigs that are drilling at the pace of 30-plus wells a year, just depends on which zones and lateral lengths and all that kind of stuff. But we're really focused on pad cycle times and how to reduce the full pad cycle time. These are large pads and gets driving flexibility in the plan by reducing that cycle time on the pads is really what's important to us.
And so we have one rig that's outperforming the others in one zone. We want to look at that zone and what that rig is doing and kind of share it with the other rigs so that we can accrue that benefit to all the pad development across our portfolio.
Got you. And maybe if I could just clarify on that 3-mile laterals versus something less than that as a percentage of total?
I'm sorry, just to rephrase your question, you're asking what's the percentage of 3-mile laterals to...
Yes, you said it depends on what you're drilling and which zones. So I was just curious, is there -- obviously, it would take not as long to drill a lesser length lateral, but I was just -- is there a percentage that you offer of the much longer lateral wells?
Right. I think our 15,000 footers this year were like at 25-ish percent of our development.
Yes. Listen, the rig per year number is an output of getting 300 wells per year drilled, right? So it's really about net lateral footage or gross lateral footage drilled per year per rig. I think Danny is talking about 30 wells per rig. Well, I think if we're drilling more Wolfcamp D with a particular rig, that rig is going to be a little slower. But I think the general standard Wolfberry development is pushing that upper echelon, but we really see the rig count as the output of what we need to do from a drilling perspective on hitting production guidance.
Our next question comes from the line of Geoff Jay of Daniel Energy Partners.
Just one quick one for me. I'm just kind of curious how you think about the potential for Trimulfrac in your portfolio kind of especially after Endeavor closes?
Yes. I mean we've looked a lot at Trimulfrac. And the struggle for us is the infrastructure spend we'd have to do to implement to get to Trimulfrac across our portfolio. And does that additional infrastructure spend, do we recognize the return on that from the efficiency gains from moving from SimulFRAC to Trimulfrac.
We think the cost benefit somewhere in the $10 to $15 a foot to move from SimulFRAC to Trimulfrac, certainly something we would pursue in areas where we have the infrastructure in place to do so. And if we have available enough development in that area -- in those areas to dedicate a Trimulfrac crew, we would -- you would see us move in that direction very quickly.
Our next question comes from the line of Charles Meade of Johnson Rice.
I want to -- I think you really penalized a lot of people with that metric. I really appreciated that -- with that 24 wells a year, 26 wells a year. But I thought Kaes' comment was really, really interesting in that. I have been focused on that. I think other callers have been. But really, that's the output rather than the -- it's kind of -- it's a manifestation or an indicator rather than a driver if I understand Kaes correctly.
And so to if that's the right way of looking at it, when I look at the other pieces of your guidance, you've actually increased the lateral length a little bit, and you've increased the well count a little bit. And so is the delta on the drilling side actually a little bit bigger, the delta -- the improvement you've seen since the -- since your initial plan than that 24 or -- 26 over 24 would indicate?
Yes. I think -- I mean, I think so, Charles, I think the point I was trying to make is that as a public company that has public guidance and quarterly guidance, we really work from guidance backwards, and we make what looks like an easy output on the surface is very difficult below the surface. There's a lot going on in terms of the teams being able to move things around and add rigs here and drop rigs there. And the plan isn't always the plan. We've got to be nimble and work together as a group. And I think that harmony we have across all of our functions is what makes us pretty unique, particularly also given that we're in one basin.
So I would say the drilling improvements this year have been more surprising than the completion improvements because we always kind of thought that drilling was already near the asymptotic curve of what they're -- they've been able to do. So not to knock the frac guys, but the drilling improvements probably supersede the frac improvements year-to-date. That's well test for the frac guys to step it up next quarter.
Our next question comes from the line of Paul Cheng of Scotiabank.
Travis and Kaes that -- we appreciate that about the great improvement in your results. But just curious that, I mean, over the next 2 or 3 years, if we're looking at the productivity improvement in drilling and completion, is that 1 or 2 areas you see as the biggest potential for you? And will you be able to also quantify on that?
And the second question is that if we look at for pro forma over the next couple of years, I mean, in order to maintain a flat production post Endeavor, I mean, how many wells that we need? Is it 500, 520, 550, any kind of rough idea? And also that do you have what Endeavor get pricing right now? Are they all in the Waha basin or that they also spread?
Well, I'll talk specifically about you look ahead for 2 to 3 years. And I think if you put it in one bucket, it would be in the downhole sensing technology that allows the bit to stay in the best rock, the highest percentage of time. And then on the completion side, understanding using downhole sensing where you can place the most frac energy in the most efficient way that creates the greatest stimulated rock volume. And these sensing technologies are -- they're evolving very, very rapidly. We're -- I think before too long, we'll be able to actually sense in front of the drill bit and drill towards a target rather than drilling past it and making adjustments. And that sounds like a small change, but I think the sensing technology that's -- we're right on the cusp of having some of those problems solved is going to be a real game changer for our industry.
And then Paul, on your well count question, I think kind of low 500 is a good place to start, as low 500 wells per year. But as the land efficiencies accrue to us and laterals extend and the decline rate shallows a bit, you probably start to get below that 500 number, should production stay flat. Now things are -- if the things are a market that's conducive to growth, that probably changes. But on a flat basis, it's more capital efficiency, less CapEx, less wells to hit the same numbers longer term.
Great. And Kaes, do you have an idea that what Endeavor gets exposure to Waha?
Yes. So listen, we've seen what exposure and Endeavor has. I do think there's going to be a lot of opportunities for both of us combined to get gas out of the basin. We've got to close the deal first and then we can start making decisions. But I think we're both -- both companies are aligned that more gas needs to get out of the basin and less exposure to Waha.
Our next question comes from the line of Leo Mariani of ROTH.
I wanted to follow up on some of the comments you made around the share buyback. Obviously, you guys had leaned more on the variable dividend in the past quarter, but you certainly kind of indicated from some of your comments here on the call that given the recent pullback in the stock and the sector, the buyback was looking more palatable. Just trying to get a sense if you guys are able to start executing on the buyback here post quarter? Are there some restrictions in place with respect to the Endeavor deal that would prevent some of that over the next couple of months until the deal closes?
Yes. Leo, I don't think there's any more Endeavor specific restrictions. Obviously, we're now -- we're reporting earnings today, so we're in a blackout day. But I think these periods of weakness allow us to step in and we prewire the buyback for every blackout period. And I think if we continue to see weakness here, we'll get opportunities. We just have a little more flexibility as the window is open versus closed.
Okay. Appreciate that. And then just in your comments here and your guidance for the rest of the year, it looks like third quarter CapEx is coming down some versus 2Q. It certainly sounds like activity is falling a little bit in the second half of the year and some of the OFS cost reductions that are kind of rolling through as well. I mean do you see stand-alone without Endeavor, CapEx continuing to kind of drop a little bit and activity kind of dropping a little bit in 4Q as well? Just trying to get a sense if that's kind of the low point for spend and activity on a stand-alone basis here?
Yes. I think it will be the low point for spend because we're a cash CapEx reporter. I think the low point for activity will be this quarter. So I think we'll probably bring back our fourth SimulFRAC crew end of this quarter into the beginning of next quarter. That's all on a stand-alone basis and probably bring back a rig or 2, but not much more than that. So I would say Q3 is the low for activity. Q4 is the low for CapEx.
Our next question comes from the line of Kalei Akamine of Bank of America.
A lot of focus on field efficiency, let's all leave that alone. I want to ask you guys about Deep Blue. The team over there continues to be very acquisitive. It looks like that business has run about maybe 20% plus or minus over the past year in terms of capacity. Can you talk a little bit about the growth outlook for that business potential Endeavor drop-down included? And maybe help us understand what the scale of the business could be, once it matures?
Yes. Listen, I think we're very pleased with what the Deep Blue team has done in a short period of time. It's kind of exactly why we did the deal, right? They've got a lot of third-party wins that Diamondback wouldn't get if Diamondback was trying to gather someone else's water. And on top of that, a little bit of M&A to boost capacity and reduce costs there.
So we're really excited with what they're doing. Endeavor has a very impressive water system. That could be a candidate to merge with Deep Blue. But I think that the price is going to be right for Diamondback shareholders, and that's what we're focused on first.
But yes, listen, they're doing a really good job building a sizable business on the water side. And with the amount of water that it takes to run multiple SimulFRAC crews at the same time, you're moving hundreds of thousands of barrels of water a day and at low cost. So very, very impressed with what they're doing. I don't think they're ready to monetize yet. It's a longer-term investment for us, and we look forward to continuing to support that business.
Kaes, on numbers, given the size of Endeavor, does it potentially double the size of that business?
It's probably a little less than double, probably about 2/3 of the size of the business today, but it has a lot of capacity and it really moves into that western -- or eastern Martin County area and connect the system nicely.
And then maybe following up on your comments on Wolf B and the Upper Spraberry. Can you talk a little bit about that program for this year? Talk about how you're laying those zones into your development plans, whether they're co-developed with other zones, for example? And if there's any learning to take away from this 24 program?
Yes. I think -- so we added the Upper Spraberry as a test well kind of in the North Martin area, like Kaes mentioned, a couple of years ago, really pleased with the performance of that well. This year, we tested it in a codeveloped fashion. And like Kaes said, we're not seeing any real degradation there. And so what we plan to do going forward is to add that to the development zones for the North Martin area.
I think some -- we have some tests that are codeveloped and some tests that are stand-alone. There are certain areas where the Wolfcamp D is significantly deeper than the Wolfcamp B, and we're not seeing communication. And there are some areas where it probably just makes sense to develop it with the stack because of aboveground efficiencies.
Yes, I think that's right. We tested the Wolfcamp D kind of in that same North Martin area and really not seeing any communication with Wolfcamp B. So we think it's a zone that we can come back and get or where it competes for capital, we'll add it to the stack.
I am showing no further questions at this time. I would now like to turn it back to Travis Stice, CEO, for closing remarks.
Thank you again for everyone participating in today's call. If you've got any questions, please reach out to us using the contact information we've previously provided. Thank you, and have a great day.
Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.