Diamondback Energy Inc
NASDAQ:FANG
Earnings Call Analysis
Q3-2023 Analysis
Diamondback Energy Inc
The company maintained a conservative stance in planning with a budget for the upcoming year just slightly above $2.5 billion. This budget strategy aims to mitigate risks associated with market fluctuations, particularly with service costs that are beginning to stabilize. The company acknowledged service costs have neither increased nor decreased significantly, which indicates a flattening in cost trends moving into the new year. This conservative budgeting, paired with the assumption of service costs remaining stable, presents a picture of financial prudence going into 2024.
The company voiced a clear intention to continue its role as a consolidator within its industry, leveraging cost advantages to enhance shareholder value. Despite a moderate oil budgeting scenario at $60, which is lower than current price levels, the company has no current plans to shift gears from consolidation to divestiture. The focus remains on delivering the business plan and confidence in the business model is strong, indicating a forward-looking confidence in strategic growth and operational execution.
A significant portion of operations, approximately 90% to 95% of current production operations, are already electrified, which carries the dual benefit of cost savings and reduced environmental impact. Efforts to further electrify, particularly compression fleets and completion operations, are ongoing with notable progress—a substantial 70% of the compression fleet is electrified. The company is also working on electrifying drilling rigs, with the aim of almost fully electrifying field operations within the next four to five years. This transition is seen as both an economic and environmental win, signaling the company's commitment to sustainable operational practices.
The CEO concluded the call with gratitude for thoughtful questions that provided an opportunity to elaborate on the company's business strategies and operational insights. The company took a moment to express appreciation for the service of veterans, both within the company and on the call, aligning the company's values with community and national service. This acknowledgment served to humanize the company and its leadership, providing a touching end to a business-focused discussion.
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Good day, and thank you for standing by. Welcome to the Diamondback Energy Third 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, VP of Investor Relations. Please go ahead.
Thank you, Stephen. Good morning, and welcome to Diamondback Energy's Third Quarter 2023 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 good morning to everyone. As Adam mentioned, we released a shareholder letter last night that contains much of the narrative we hope to cover again this morning. So with that, we'll just open the lines up for question. Operator?
[Operator Instructions] Our first question comes from the line of Neal Dingmann of Truist Securities.
Travis, my first question is on capital allocation, specifically, several quarters ago, you suggested all would return to more production growth type model, I'd call it. And I think you mentioned when the macro fundamentals supported, I'm just wondering, do you believe we're close to that scenario and wondering why do you believe the continued high free cash flow payout is warranted?
Yes, Neal, that's a good question. Look, the world is certainly in the mass right now across any number of fronts, all of which could potentially move the markets, both positively and negatively, both with a supply disruption or even a demand destruction as well, too. So obviously, we can't control any of those items. Again, we simply respond to our shareholders that own our company that right now, return shareholder model versus a growth model, as we've intimated, our plans as we look forward into next year, again, look for real efficient capital allocation. And as an output of that capital allocation, we expect low single-digit type volume growth, again, not as an input, but what results from an efficient capital allocation program.
Got it. That makes sense in this environment. And then secondly, on your development, I couldn't help but notice the new slides on Slides 10 and 11, highlighting the efficient execution and differentiated development. My question is, does most of your remaining Midland inventory went to the 24 average wells per project size that you mentioned? And then I'm just wondering, could you speak to where the largest cost of agencies continue to come from on these projects?
Sure. On the development strategy over time slide, which is Slide 11, for those of you that are looking at it online, we tried to demonstrate our evolution from 2015 to today. And we said average wells per project is about 24 wells. I think generally, that applies across our Midland Basin. However, not all deposits are equal in terms of the way the shales were laid down across the Midland Basin. So there will be areas where we can do slightly more than 24 wells and then areas also where we'll do slightly less than 24 wells, which usually translates to 1 or 2 wells less per shale interval.
So again, it's a general representation showing the development over time but that's a good summary. And then what was your second question?
Just on the cost, I know Kaes and I've talked about, I mean, is it just on I know you have lower casing and just different sort of raw material costs, but is there other areas in that larger projects that are causing these when you see that well productivity chart on the right, sort of what's driving the lower cost efficiencies there?
Yes. Certainly, again, referencing back to Slide 10, we've laid out the biggest elements of cost savings, cost components and the reductions over time. And again, as you pointed out, it's casing which is down 20% or so. It's really -- as you look into next year, we feel more of a kind of a steady-state run rate on our costs. There'll be some puts and takes on both sides of the equation. Kaes, do you want to add anything?
Yes. I think the biggest benefit to the large-scale development, Neal, is the consistency of running the rigs in the same spot for a long period of time. But on the frac sides where we save the most money from a capital efficiency perspective, because we're doing, in some cases, 2 simul-frac crews on the same site at the same time. So you're saving essentially $250,000, $300,000 a well from simul-frac and now we have 2 of those fleets or e-fleets that run off lean gas that save kind of another $200,000, $250,000 a well.
So this large-scale development kind of ties to the longer cycle nature of our business, and that also means we don't want to change the plan. Every move in oil price. And so we've had a consistent plan here for a few years now. And the output of that is consistent results on the well productivity per foot.
Our next question comes from the line of Neil Mehta of Goldman Sachs & Company.
Yes. And I appreciate the helpful letter and the time today. Travis, why don't we start on return of capital as a topic? You talk about this in the letter you wanting to err on the side of caution as it relates to buying back stock to avoid repurchasing procyclically and as a result, lead it to the variable dividend in the last quarter. Can you talk about the way that you're approaching this and how that should inform the way we think about the split between buybacks and dividends going forward?
Neil, our main focus remains a sustainable and growing base dividend that we think represents the most efficient way for our shareholders to understand what our shareholder return program looks like. Following that is the share repurchase program, which we laid out what we've done in the third quarter and so far in the fourth quarter. And then we honor our commitment to return at least 75% of our free cash flow by making our shareholders hold in the form of variable, which we seen we did this year. I think the most important thing is when you talk about share repurchases, is that you need to have some discipline around that because in my experience, lack of discipline leads to chasing stock repurchases all the way to the top of the cycle.
So we, like most of our capital allocation decisions, actually, like all of our capital allocation decisions, we hold ourselves accountable to some form of rigorous analytics. And in this case, we continue to run NAV value at mid-cycle oil prices, which is $60 oil and calculate oil price or calculated stock price and depending on where our stock is trading relative to that calculation, we either buy more of and the further dislocation we get from that, we buy -- we increase or if not, then we pivot to share -- to a variable dividend like we did this time around.
So again, it just -- it's base dividend, it's share repurchases with a degree of caution in a procyclical environment. And then honoring our commitment to the form of a variable dividend.
Okay. That's really helpful. And the follow-up is just on noncore asset sales. You've done a good job of exceeding your target. Can you talk a little bit about the Deep Blue Midland Basin JV? And then not only in terms of the proceeds, but what does it mean for your go-forward cost structure as we think about modeling the impacts through 2024?
Yes. Good question, Neil. The Deep Blue JV was a very big deal for us. It took a long time to pull together. We had built a significant amount of midstream infrastructure over the years and spent a lot of capital doing it. And we felt it was an opportune time to monetize that in the hands of who we see as operational experts in Deep Blue in the Five Point team. I think they have already proven to have commercial success with third parties where maybe if you have a Diamondback business card, you weren't going to have the same type of commercial success. I think that sector is certainly ripe for consolidation as well. And I think they're the experts that can get that done. So that's kind of why we retained the 30% equity interest in the business. We're very confident that they're going to be able to grow the business and generate a good return for our shareholders.
Outside of the $500 million of proceeds we got in, which is the big winner. There will be some impacts to our cost structure. I would say, generally, LOE is going to be up about 8% to 10% versus prior as a company. And then we'll have a lot less midstream CapEx is going to have very many operated midstream assets, and that will be kind of canceled out by slightly higher well costs, $10 to $20 a foot depending on the area as we buy water from the JV. So all in all, we sold the business for a much higher multiple than we trade and we're excited to see what they can do in terms of creating value for the 30% that we're retaining.
Next question comes from the line of David Deckelbaum of TD Cowen.
Travis, I was curious if you could talk a little bit more about the remarks and the shareholder letter on being an acquirer and exploiter. And just maybe putting in context sort of how robust do you think the opportunity set is right now, just given the cycles in the business and some of the PE cycles that have gone through the Permian right now?
Yes, David, and I appreciate you referencing the shareholder letter, I tried to address that head-on. I think just in a more macro sense, we'll always do what's right for our shareholders. I mean, we've got now over a decade of what I think is demonstrated in doing the right thing for our shareholders. But we remain laser-focused on delivering on our business plan. And you're right, we have built this company through an acquired export strategy. But I think as investors are really starting to understand, we have such a high-quality inventory right now that the bar is pretty high for additional opportunities to add to our inventory that meets those -- the criteria that we laid out in our shareholder letter with sound industrial logic, and being able or -- logic and being able to compete for capital right away and then being accretive on those financial measures that are so important to all of us.
So there has been a lot of private equity roll through. And I think based on lack of our name on those, it just tells you where we view those assets relative to our inventory. Like I said, I'm really pleased with the quality of our inventory, and I think we're executing on that in a flawless manner.
Appreciate that. And maybe just for Kaes, and just the DUC backlog is built, I guess, up to 150 by the end of the year. I think you guys talked about low single-digit organic oil growth for next year. One, I just wanted to confirm if that oil growth is reflecting the benefit of the increased royalty interest through the Venom acquisition or Viper acquisition rather or if that's how we should be thinking about that growth rate. And then just in concert with the DUC backlog, is it -- should we think about that flexibility, especially in this pricing environment just based on frac crew availability or is that really just like a capital allocation decision?
Yes. I'll hit the organic growth comment first. Certainly, we -- excluding the Viper deal, we expect it to grow organically and we expect to grow organically in 2024. I think the Viper deal provides a little bit of a jump start here in Q4. But I think the team is expecting to grow off that number to steady state throughout the next year just due to the quality of what we've got in front of us. On the DUC side, we were kind of operating pretty close to the rigs on the completion crews and really needed some flexibility here and that the drilling team has done a really good job this year getting ahead of plan, drilling more wells than expected sooner. With these large pads and large projects, you really want to have the flexibility to be able to go somewhere if something bad happens and that DUC backlog allows that.
So I think 150 plus or minus 10 or 20 wells either way is a pretty good number for our run rate. And we kind of set the stage for a world where we run 4 of these simul-frac crews consistently throughout the year, they each do about 80 wells a year. And in our mind, that's kind of the most capital efficient development plan we can imagine here. So that DUC backlog just let Danny sleep a little better at night and allows for some flexibility heading into next year.
Next question comes from the line of Scott Hanold of RBC Capital Markets.
If I could go back to the M&A topic a little bit differently. When Kaes, Travis, when you step back and think about like where Diamondback's inventory depth is and to be a long-term successful large-scale play in the Midland, like do you think that more large-scale M&A is necessary over time? And just remind us like where you think your inventory life is and where ideally would you like it to be?
Yes. I mean I don't think it's necessary, Scott. I think we've positioned the business through both large scale and small scale M&A. It's just kind of been in our DNA for the last 10 years. I kind of go back to thinking about what positions in North American shale or in the Midland Basin would be Envy, and there are very few, particularly with where we sit today and the amount of deals we've done over the years. So I think it's a fortunate spot to be in with the inventory duration and depth that we have relative to what's out there. I just think Travis' comment is really about knowing who you are, and this company has been an acquirer and exploit company that's been able to execute on acquiring and exploiting assets through our low-cost structure. And generally, we haven't had a philosophy that the low-cost operator in a commodity-based business wins. And our cost structure is what has created this business to be as big as it is today. Travis, you want to add anything to that?
I think that makes sense. We've talked about the high bar for entry into the Diamondback portfolio. And it's just -- that's just how we view it, and we're very proud of the inventory we have. And I think what goes along with that durable inventory is how we convert that inventory into cash flow. And again, you see this quarter, flawless execution from our teams and converting rock into cash flow. And that's our cost structure is enviable. Our execution prowess is unmatched, and that makes a big difference when you talk about a profitable oil and gas company like Diamondback.
Yes. And then just as part of that was the inventory life kind of conversation more of like where you think you're at now? And what do you think is ideal?
Yes. I mean, I think I kind of said this that we put out our next 5 years up with anybody in North America, and I still stand by that. I think we have another solid 5 or 10 years beyond that. It's very logical that at some point, you're going to have to move down the quality of your inventory. We don't see that in the forward plan today. But if we retain our cost structure and our ability to drill wells $1 million or $1.5 million or $2 million cheaper, well as the shale cost curve goes up, we continue to stay at the low end of that cost curve. It's kind of been our mantra for 10 years now, and we started with 50,000 acres and now we're at 550. And that culture and mantra has not changed. And I think that sets us up well for a world where assets are getting more and more spars.
Got it. Understood. And if I could follow up on our conversation we had last night, just on the shareholder returns. And stock buybacks. And I thought it was an interesting conversation we had on just where FANG's intrinsic value is now and the opportunity to grow that over time. And so like when you step back and think about the current oil market, obviously, we're in a little bit more heightened oil price versus your intrinsic point. But like as you see yourself progressing over the next years, I mean, does it seem to make sense that buying back stock at higher prices in this heightened market relative to what you did in the past still make sense from a value return standpoint?
Yes. It's really all about value. And like we talked about last night, if you run your business conservatively from an oil price perspective and accrete value quarterly at $75 to $80, $85 crude, you're actually building equity value on a conservative basis, right? I kind of said last night to you that I think generally, if you run a quarter like last quarter, versus the $60 base case, you're basically building $3, $4 a share of extra intrinsic value. And I think that's what we've done here over the last couple of years in this up-cycle.
And as Travis mentioned, we want to be conservative when buying back stock. We think capital is precious and capital discipline, not just applies in the field, but it applies to returning capital to shareholders. And that's why we've had this flexible return of capital program since we put it in place 2.5 years ago.
Our next question comes from the line of Roger Read of Wells Fargo Securities.
I think I'll skip the obligatory share repo versus a variable dividend question for a moment and just go back to the operational aspect. So can you give us an idea, as you mentioned, the sort of accreting value into the shares through operations, what we should be looking at over the next, say, 24 to 36 months for what else you can do operationally that will accrete value and thinking that we're not going to have some of the asset sales that have been going on that have certainly helped on the sort of cash flow generation assets?
Yes. That's a good question, Roger. I think it's interesting. We put a slide in Slide 10 about operational track record and process. And I think we sat in this room 2 or 3 years ago saying, "Hey, the drilling guys there, they're near the asentotic curve of drilling these wells." Well, if you look at the top left over that chart, they're still taking days out of the average well on a much bigger program, right? Because they are drilling 280 wells in the Midland Basin, 2, 3, 4 days faster than they were even 2 years ago. And the culture that we built creates that value to our shareholders. It's not something we model, but it certainly comes our way.
So in the field, I think that's part of what is coming our way. I also think generally, we've tested some other zones in the Midland Basin that look very, very good. We've got a couple of Upper Spraberry tests in the Northern Midland Basin that looked very good relative to our Middle Spraberry, Jo Mill development. So we're excited about that. I think the Wolfcamp D in the Midland Basin is starting to become a primary development zone in some of the basins. And certainly, there's a lot of excitement about deeper zones in the Midland Basin as well, the Barnett, the Woodford that we're on to testing. So I think the Midland Basin, the stacked pay and the amount of oil in place just provides a lot of opportunity for future value to accrete to our shareholders that they don't know about today. Travis, do you want to add anything to that?
Yes. Roger, if you backcast 10 years ago when we first started this, we're still drilling a few vertical wells. And I put in the letter that we released last night, just a couple of data points on a 7,500-foot lateral well, which has a total depth, total measure depth of about what we were drilling vertically when we started. But drilling -- we drilled those 75-foot lateral wells in under 4 days. And when we started, we were drilling it. Sometimes it takes us over 24, 25 days to get down to that same measured depth vertically. And so probably the most repeated question that we get is what is the secret sauce? What is the magic that Diamondback does that allows execution quarter-over-quarter to just far exceed the competition? It's essentially the same rock and the same tools, but the culture that we built here at this company with that laser focus on the conversion process of rock into cash flow is felt by every employee in the company.
And when you have everyone leaning in the same direction on cost and efficiency, as long as we can continue to give them good rock, they're going to generate the outstanding results that we're known for. So I know that's a little bit of motherhood and apple pie, but it's -- I'm really proud of the organization for through all the cycles we've been through over the last 10 years, what hasn't changed is an unrelenting focus on delivering best-in-class execution, highest-margin barrels at the lowest cost.
I appreciate that. I'm not going to get in between motherhood and apple pie here in the U.S. So I'll turn it back.
Our next question comes from the line of Derrick Whitfield of Stifel.
Thanks for all the incremental disclosures this quarter. Building on an earlier question, how should we think about '24 maintenance capital run rate, assuming the benefit of deflation and your current operational efficiencies?
That's a good question, Derrick. And I'd probably say that the maintenance CapEx would be $100 million to $200 million cheaper, 30 wells, maybe, Danny?
Yes, I think we're kind of looking at it like our maintenance -- our case for 2024 is kind of a maintenance activity case. So flat activity outputs a little bit of a growth. But if we were to try and maintain a flat production profile, you'd probably be in the line of 20 to 30 less wells in the year.
Derrick, while you're on that topic of maintenance CapEx, I might just point you to Slide 7. We've had that slide in there a couple of times, but it shows maintenance CapEx, which, Danny just defined, is kind of holding the fourth quarter production flat for next year. And I just want to show you what our breakeven prices are on that slide, $32 a barrel to cover maintenance CapEx, $40 barrel to cover our base dividend. So that kind of goes back to my cost and execution comments that ultimately translate into a very protected business model even at low commodity prices.
That's great. And as my follow-up, with respect to noncore asset sales, how should we think about the market value of what's being retained by Diamondback and how that will be realized over time now that you've exceeded your disposal target?
Yes. Good question, Derrick. We did lay out some of our remaining JVs that we have on Slide 26. I think some of those logically are monetized at some point in the coming years. I don't think we're in a huge rush to do so. But in most cases, we're kind of a non-op partner to these JVs that do have a ton of value, just not something that we can commit to monetizing today.
Our next question comes from the line of Kevin MacCurdy of Pickering Energy Partners.
I appreciate the commentary on industry consolidation. Digging into your cost structure comments a little bit, now that you've had FireBird and Lario and [ House ] for almost a year. Can you comment on the level of cost synergies you've created in those transactions? Or maybe just share with us your analysis of Diamondback's cost versus peers. I'm just trying to get a sense of what kind of uplift assets get when they're incorporating to Diamondback in your cost structure.
Yes. I mean that's a good question, Kevin. I hate to say it, but we didn't win those deals because we were buddies and bid less than other people. So I think we did the most. But we did the most because we could underwrite it with the lowest cost, right? At the time I think some of the area well costs were near $8.5 million, $9.5 million for a 10,000-foot lateral, and we're drilling them at $6.5 million to $7 million. And so that's kind of our mantra for a long time. I would just say, generally, if you split the 2 deals out, Lario was an execution deal because we knew we could drill those units cheaper and execute on large-scale development. I would say FireBird is more of a technical deal. And we had a technical view of that particular area that the basin could move further west, particularly in the Northern Park portion. There'd be some multi-zone development that looks really good. I think we're conservative on the multi-zone potential of the central block and now feel a little more confident about the Wolfcamp A and the Lower Spraberry maybe being wine-racked in that area. And also with the benefit of that block being so contiguous, we're able to bring a 15,000-foot lateral manufacturing process to that area.
So we underwrite these deals at our cost structure which if you look at our cost structure versus others, that means we should get more of those properties at the same rate of return because of our ability to execute.
Next question comes from the line of Jeoffrey Lambujon of TPH & Company.
My first one is on the ops and capital allocation side. If you can just speak to any more detail on next year's plan in terms of where you might focus within the Midland Basin, both in terms of geography but also maybe just less active zones in terms of industry activity that you may be testing more. And if you could speak maybe a bit more on to some of that lateral in the commentary in terms of how that might evolve over the near-term program, that would be helpful as well.
Yes. Jeff, with these longer-cycle projects, we have a pretty good view of what the projects look like coming up here in 2024. I'd say, generally, we're going to be in the range of 11,000 feet average lateral length, probably maybe even a little bit more than that. I would say it's also a very heavy Martin County development year for us, which is great, large-scale, multi-zone development and some of the best developed resource remaining in the Midland Basin.
I'd say from a testing perspective, some more Wolfcamp B probably making it into the plan and a lot more Upper Spraberry making it into the plan. We kind of have a couple of really good tests and part of our culture is when something works, we implement it very, very quickly. And that's how we kind of see the shallower development picking up the pace in the Northern Midland Basin, particularly that Northwest Martin County area that we feel really good about for adding a new zone.
Okay. Great. And then maybe just a housekeeping type question on the noncore asset sales side, particularly on the upstream. I think a few people noted now, just how you're exceeding or you've already exceeded the target before year-end here and it makes sense, there's no need to go out and do more right away, but just wondering if you could speak to potential opportunities maybe in terms of longer-dated inventory that someone else might find more valuable today however you think about the opportunities in there?
Yes, good question. That ties to something I didn't answer your last question. The number of wells in the Midland Basin will be kind of 85%, 90% of total capital. So the Delaware Basin still be a small percentage of total capital. I think if I'm getting what your question is, where does the Delaware Basin sit in the portfolio? I think for us, certainly, we've started that area of capital a little bit here in the last few years. I think it provides a lot of cash flow and a lot of production, which is beneficial to us today. But as you've seen, over the course of the year, it certainly seems like inventory is coming at a premium. And there may come a time where someone really, really wants that Delaware position of ours or portions of it, but we're not going to sell it for a song in PV-15, right, PDP. So I think we're going to hold it for now. And if someone wants to pay for upside and a reasonable number versus where we trade, we'll take a look at it.
Our next question comes from the line of Nitin Kumar of Mizuho.
Kaes, I want to start on Slide 11. You've been espousing the codevelopment approach for some time, and you show pretty solid results and consistent results since 2020. Just curious, one of your, I guess, peers in the basin talked about increasing recoveries by 20% through the use of technology. You guys are at the cutting edge yourself. So I'm curious, are you seeing anything out there that can improve recovery factors by that kind of magnitude?
We keep our figure on the pulse of a lot of emerging technologies. We focus our internal expertise on improving recovery. That's not something that's on our radar screen that we're aware of today. But that's not to say that the potential is not there as you look forward in the future. There's a lot of smart guys in our industry. We have a ton of smart guys inside Diamondback and whether that technology is developed internally or externally, it's widely communicated and quickly followed as particularly that kind of result. So we're focused on improving recovery, and I know our peers are doing the same. That's not a today number for sure, though.
And I guess my follow-up would be if you are a fast follower, you've talked about how volume is an output of your program, your capital allocation framework. In an event that you could improve recoveries that way, would you allow -- would you keep activity flat? Or do you expect to reduce CapEx and just maintain that volume growth to be in the low single digits?
Yes. I think generally, that would be a great problem to have. It really ties to this can you run a final frac program consistently on that position in those projects and those paths. Kind of all those back to this longer cycle nature of the shale business model and I think we feel really good about for simul-frac crews running consistently right now, and it have the infrastructure to do that. And if growth exceeded expectations, that will be a good problem to have.
One moment for our next question. Next question comes from the line of Charles Meade with Johnson Rice.
I want to ask one more question, but maybe from a different angle on the A&D outlook. Kaes, I think it was -- I think I wrote down what you said that in your prepared comments or maybe earlier Q&A, that there's very few positions out there that you envy. And so that makes sense that you guys -- your bar is high. But from my seat, it also looks like, if you look at the other side of the question, it looks like there's not a lot of positions you want to buy, but there's also fewer possible -- fewer potential buyers out there, particularly for some of these large private position. So how does the -- I guess do you agree that there's fewer credible buyers for some of these big packages that may still be out there? And more broadly, how is the kind of the lineup shifting as you're active in data rooms and in processes, buyers versus sellers?
Yes. That's an interesting observation, Charles. It's certainly not lost on us. You've got a couple of very large buyers do a couple of deals in the basin and out of the basin. Make it kind of do whatever they want, it seems like. But I would just say, generally, industry consolidation has happened. It's continuing to happen. I think a lot of the privates are gone, as you mentioned, to logical acquirers. I would just say that the -- there may be less buyers of assets, but they're all very well-funded, good operators, big balance sheets, and competitive. So I think we just have to stick to our guns in our underwriting philosophy, which is our cost structure, our rates of return internally, our hurdles for commodity price. And usually, that has resulted in more assets coming to Diamondback because we can underwrite wells drilled at $1 million or $2 million cheaper. We can run LOE above cheaper that's the kind of stuff that accretes to our shareholders.
One moment for our next question. Our next question comes from the line of Arun Jayaram of JPMorgan Securities.
I wanted to keep on the A&D theme. When we are assessing the potential of a large private or one of these unicorns to potentially consolidate. Does it just come back to price? Or is there something -- do you think that they think about in terms of the independent versus major oil business model that could be advantageous to a company with like Diamondback, who's in Midland and again, both of those cost structures in the industry.
Yes. Arun, we don't spend a lot of time thinking about what sellers think. We just think about what is the best opportunity available for our shareholders and creating shareholder value for our shareholders. And at the end of the day, I think Diamondback hand on heart as one of the best positions remaining in North America and the best cost structure. And that should be a very winning combination for our shareholders for a long time here.
Understood. I want to maybe switch gears and just talk about the D&C efficiency gains, really surprised to see this year, the drilling efficiency gains -- seems like the drilling efficiency gains are outpacing maybe what we're seeing on the completion side. Are you guys recalibrating the -- call it, the rig-to-frac-crew ratio, but give us a sense of maybe what your what you're doing on the drilling side for these efficiency gains? And maybe help us recalibrate what that drilling to simul-frac crew ratio looks like today.
Yes. It's interesting. We really haven't thought about the rig-to-crew ratio in a long time because it's just changed so much. I think we've moved to a world where we know how many wells we need to drill and how many wells we need to complete in a year to hit numbers. And the drilling side, maybe a year ago, that was 15 or 16 rigs for a full year. And now this year, and upcoming, it looks more like 14% to 15%. So the amount of work that our planning team does on the plan and how we're doing relative to plan is pretty astounding and how far ahead they are on these pads and then we need to pick up a rig and when we need to drop it. We're really kind of just targeting can we keep those simul-frac crews busy consistently. And I would guess, I guess the number is kind of in that high 3s, almost 4 rigs to one simul-fracs crew today.
Yes. Arun, I think. Like Kaes said, our goal is to keep the drilling program ahead of the simul-frac fleet and just keep the simul-frac fleets moving inefficient just like we want to keep rigs moving from pad to pad without waiting on pack instruction or whatever. So we kind of see them as 2 different programs altogether knowing that they're very dependent on each other. But I think the drilling and completion teams both this year have really done an excellent job of leaning in and pushing the machine to the limits and finding the little pieces of efficiency gains that can pick up and we continue, as we've always been to tinker and find better ways to execute our development strategy and build a better mousetrap. And we find different ways to design wells and execute that, we'll lean into it and continue to chase that efficiency line.
The next question comes from the line of Scott Gruber of Citigroup.
Congrats on another good quarter. I want to follow up on the -- I want to follow up on Arun's question just on the activity set into next year. I get some more clarity on the plan for the DUCs. So it sounds like you can be running the 14 or 15 rigs. Will you end up drilling 330 or so wells by running 14 or 15 rigs? Or will the base plan for next year contemplate a drawdown of some of those excess DUCs?
I don't think we're planning on drawing any down absent any in-the-field issues. I think generally, we feel a lot better at this level of DUCs for the size of projects that we have ahead of us. Earlier this year, we were getting pretty close the rig or the frac crews were getting pretty close to the rig getting off location. And a 20-well pad or 24-well pad or however you want to break it up, you have to have all 24 wells done before you can bring on the drilling side, where you can bring the frac crew in or at least that's how we do it. And that's why that kind of 150 number we mentioned feels like a much more balanced number going forward.
I got you. So the inventory count is under normal conditions is just going up. I got it.
Yes. This feels like a good inventory number. Again, going back, we're not -- these aren't the days of 2-well pads where if something that happens, you can pull out the pad and go somewhere else. These are long-cycle mini, Danny likes to call them mini offshore projects given the amount of dollars that go into a project before first oil comes online.
That makes sense. And then good detail on the cost trends across the various buckets on Slide 10. As you think about going through RFP season for various services? I know you have some longer-term contracts in place, but do you think you'll see any continued deflation across any of the major buckets as you go into '24? Or are those starting to stabilize now?
Yes. I think we think it's kind of stabilizing right now. And for us, there really is no RFP season, right? RFP seasons every day coming back. If something cheaper and we can do something cheaper or replace something with something cheaper. It's going to happen right away. It's not going to wait for next season or for the summer, it's going to happen now. So it's a constant RFP season here. And these are all real time costs that the team has to present to Travis on a line-by-line basis every quarter. And this is a real-time look at where we are and where things are headed. You noticed we put a Q4 2023 number in there, just to show where even we've moved from Q3 to Q4.
Our next question comes from the line of Leo Mariani of ROTH MKM.
I just wanted to follow a little bit on 2024. If I'm kind of reading this right, it looks like you guys are talking about a rough budget next year of just a hair over $2.5 billion, sounds like that's kind of flat activity. Just wanted to get a sense of kind of what's assumed in there for inflation or deflation? Are you just kind of assuming sort of current well costs in that number?
Yes. I mean we're always kind of a little conservative here, Leo. So I would say we're kind of in the range of where we think we are today. Again, we think generally, service costs have kind of bottomed or flattened out. And absent a major change in rig count, this feels like a pretty good range for next year.
Okay. And then just to follow up quickly on the M&A topic here. I think you guys have made it pretty clear that you want to continue to be a consolidator over time with your cost advantage. I guess at the same time, just kind of you guys talk about kind of a $60 type of budgeting case for oil, obviously, we've been above there. Is there any scenario where FANG thinks about potentially going the other way and actually selling at the end of the day?
Leo, I've tried to address that a little bit in my opening comments is one of the first questions and also in my letter. Look, we'll always do the right thing for our shareholders. We've been -- I feel like we've done that for 12 years now. But again, what our focus is, is on delivering our business plan. And we believe in our business model, we believe that there's a meaningful spot in our investment community for a company like Diamondback, and we continue to execute flawlessly. And I think I'm really confident about what our forward plan looks like.
Next question comes from the line of Paul Cheng of Scotiabank.
Two questions. One, one of the ways that you reduce cost, I think the industry is moving for electrification. I sharp of that -- wondering if you can give us some idea that how far along on your process in doing so? And secondly, that with the Deep Blue -- I think in the past that you guys are very proud of your water infrastructure and all that. So is that signaling that now you have a change of view of what kind of infrastructure need to be owned by or need to be controlled by Diamondback going forward? So should we just assume that this means that you really don't think that's necessary for you to have control or to own those infrastructures?
Yes. Good question, Paul. I'll take the second one first on the Midstream infrastructure. We spent a lot of money building those systems to the specs that we needed. And so I think we're not turning over a blank canvas, right? This is a painting that's already been finishing touches. And so we feel confident, particularly with a lot of our field team members going over to Deep Blue to run the asset that will be well served as its largest customer and also a large equity holder.
So I think if we are early in our development plan might be a different story. But in this case, it's a very well built out system that is kind of ready-made to turn over to them to, in our minds, do some more things commercially that we couldn't do as a stand-alone water enterprise. And then your other question on electrification. It's certainly a hot topic in the Permian. I think generally, electrification means both lower cost and lower environmental footprint. And that's a great thing for us in this basin. We've done a lot of work ourselves. I think the state of Texas and the utilities need to kind of do their part to get more power out to the Permian to connect to all of us so that we can run off of line power versus different forms of generation in the field.
So I think that's going to be a constant battle that we're intently focused on. And again, it saves us money and improves environmental performance that feels like we're in.
Just curious that, I mean, what percentage of your operation now has already been genetic buy-in, that where you think is the biggest opportunity over the next 1 or 2 years?
Yes. We've got about 90% to 95% of our current production operations electrified. We've been -- the biggest opportunities we've been working on to date in the production operations world or been electrification of our compression fleet. And I think we're probably 70-ish percent electrified there. So we'll continue to work on getting rid of our gas reset compressors and putting electric packages in their place.
And then on the D&C side, we've got 2 simul-frac fleets that are Halliburton, what they call their zoos fleets, which are their electric fleets and we've really enjoyed the benefits of those and look forward to continuing to try and electrify the completion world. And then on the drilling side, we've got, I think, 5 or 6 rigs running right now on line power, and we're continuing to put in the infrastructure that we need to, to run those rigs off-line power as the supply chain kind of frees up on the back of COVID, and we can get the electrical equipment we need to convert those rigs.
So it's kind of all over, but we're working on it as fast as we can. And I anticipate that over the next 4 or 5 years, there won't be much of the field that's not electrified.
All right. This does conclude the question-and-answer session. I would now like to turn it back to Travis Stice, Chairman and CEO, for closing remarks.
I appreciate all the good questions this morning. I hope you find our shareholder letter constructive in the way that we can help communicate details about our business plan. The last comment I want to make before we sign off is that we have an opportunity this Saturday to recognize all of our veterans across this country on Veteran's Day, certainly, for all of the veterans that are employed by Diamondback, thank you for your service and then anyone that's on the phone that also dedicated a portion of their lives to our country, I want to tell you thank you for your service as well.
And then particularly for the Diamondback employees, hopefully, we'll see you at breakfast or lunch ceremonies that we have planned for this Friday. So thank you. You all have a great day. God bless.
All right. Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.