Operator:

Good day, and thank you for standing by. Welcome to the Diamondback Energy First 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 Adam Lawlis, VP of Investor Relations. Please go ahead.

Travis Stice:

Thank you, Adam, and I appreciate everyone joining again this morning. I hope you continue to find the stockholders' letter that we issued last night in an efficient way to communicate. We spend a lot of time putting that letter together, and there's a lot of material in that. So operator, with that as a brief introduction, would you please open the line for questions?

Neil Mehta:

A lot of good stuff in the letter. Two quick follow-ups. First, just on natural gas. You spent a lot of time talking about some of the steps you've taken to mitigate some of the softness that we're seeing in Waha pricing. Can you spend more time on that? And as it relates to that, how do you think about the timing of debottlenecking Permian gas?

Kaes Van't Hof:

Yes, Neil, I mean, this will be long term, we want to be able to contribute to more pipes. We've done that in the last couple of years with commitments on Whistler and Matterhorn. We've relinquished taking kind rights in other areas to commit to other pipes that were built. As Travis said, we just need to do more. And I think with our size and scale and balance sheet, we should be taking a leadership position on these new pipes. We've talked to a lot of people that are working on them today, and it seems that there are projects in the works that will help the bottleneck past the end of this year. But as we control or have the ability to control more gas flows on our side, as contracts roll off, et cetera, we're going to keep pushing on more pipes and more markets out of this basin.

Travis Stice:

Well, I think the deflationary pressures we continue to see in the Permian are being driven by the decline in the rig count and the decline in the completion crew count. Those will be tailwinds for us as we look through the rest of this year. But also without regards to those deflationary impacts, we continue to push the envelope on our D&C operations where we're getting -- I think we averaged almost 13,000 feet for the quarter this year, and we continue to get these wells drilled faster and then our completion crews continue to push the envelope on the number of lateral feet that are completed in a 24-hour period. So we're working on the numerator and the denominator of capital efficiency and really like the way the rest of the year sets up for us.

Arun Jayaram:

Travis, you and the team had highlighted up to $550 million of annualized synergy capture in the transaction in the Midland Basin, including a 150-foot decline. And do you see any cost in the Midland Basin to that $600 million to $650 million range? Maybe a follow-up to Neil's question, but where are you seeing kind of leading-edge cost today in the Midland Basin as you continue to push those lateral links a bit longer?

Arun Jayaram:

Great. Kaes, looking at the quarter, you didn't really -- how many activity in terms of [ TILs ] in the Delaware Basin. Can you give us some thoughts on the Delaware program? I know it's 10% of the program, but what's your thoughts on the Delaware as we think about moving on into the back half of this year and into next year?

Operator:

Our next question comes from the line of David Deckelbaum of TD Cowen.

Kaes Van't Hof:

Yes. I think what's changed is just timing, right? I think the projects we see as noncore asset sales or the asset sales to subsidiaries we have is still the same. Endeavor has a really good midstream business that would fit well with our midstream JV. They have a significant mineral business that I think is going to be a game changer for Viper if those 2 businesses are combined. And our strategy to execute on those trades has not changed. It's just been pushed out to the right. So on top of that, there's an $8 billion cash consideration, that continues to be worked down with free cash flow between sign and close.

David Deckelbaum:

Maybe just to follow up a little bit more on just the gas pipeline side. Just for my own edification, just some clarity. Just you highlighted you didn't have any issues with egress. You have Matterhorn coming online in the third quarter. Is there a point as you look forward, where you anticipate egress issues? Or is this more appearing to be just more proactive to get involved with taking on firm capacity in future pipelines? Do you need to take a more active role beyond that?

Operator:

Our next question comes from the line of Scott Hanold of RBC Capital Markets.

Kaes Van't Hof:

Yes, Scott, we're 100% confident in our plan. I think we have a lot of visibility. We have more and more physical space coming our way. Every molecule is moved to date. I don't like the speculation blame game in the Permian about who's going to be able to move or not. I'm focused on Diamondback, and we're going to be in really good shape.

Kaes Van't Hof:

Yes. I think philosophically, part of the move back to 50% of free cash flow returned every quarter allows us to build more cash, pay down debt faster, but also make the bigger bets on buybacks, right? In a single quarter, if you're having to distribute 75% of your free cash flow, you don't get to really make the big bet on the buyback at the right time. And so this flexibility will allow us to do that. Clearly, we've been a little limited on buybacks since announcing the deal. I would expect that to stay about the same here in the second and third quarters depending upon the market.

Scott Hanold:

Yes. Just to clarify a couple of points. Just broadly speaking, how much accretion do you all feel Endeavor added? And can you give us a sense of like when you think about cost of capital, like what were you kind of thinking before when you did intrinsic value. Was it like a 10% kind of flat? Or do you get a little bit more scientific with that?

Operator:

Our next question comes from the line of Roger Read of Wells Fargo Securities.

Daniel Wesson:

Yes. Good question. We are continuing to drive costs out of the business through our operational plan and execution. On the completion side, A lot of that's going to come in the way of getting any fleets off of generated power and on to some form of grid power where we can recognize a lower energy source cost. We're continuing to try to drive days out of our execution, and we're kind of on the asymptotic slope of that efficiency gains that we are getting to a point where the fixed cost of the wells are a significant -- significantly larger portion of the cost of the well than the variable cost. So we're getting to a point where the variable costs that we're going to impact our pennies and nickels and not as much the dollars anymore and to get those large chunks, we're going to have to think about doing things differently as far as the physical plan for the wells and what we are going to consume as part of the fixed cost of the wells.

Roger Read:

Got you. So we just need somebody to come up with the next better mousetrap out there for the step functions. I appreciate that.

Operator:

Our next question comes from the line of John Freeman of Raymond James.

Daniel Wesson:

Yes, John. I think in the first quarter, those longer laterals were really just a function of where we were completing the wells that average lateral length of 11,500 is what we expect to see for the rest of the year.

Travis Stice:

Yes, John, we got to operate as separate companies until the deal closes, and those things will come to the benefits of the combined company, but certainly can't influence any outcomes until deals were closed.

Neal Dingmann:

Travis, my question for you, okay, is just on the marketing side. You are looking not only from a capital efficiency, but it seems like from a takeaway, you all continue to get better and better sort of realized margin. I'm just wondering, now with the larger size, or I guess when that closes, what type of benefits will you continue to see the benefits on the back end that you've been seeing on the company? Because it seems like noticeable that a lot of your margins and all just on the marketing side continue to improve.

Kaes Van't Hof:

Yes. I think our philosophy is to get our barrels to the most liquid bigger market and very clearly, selling within Midland or in the Midland market has not always been the most beneficial to our shareholders. There are pockets of time when the Midland market is very loose, but there are also periods where it gets very, very tight. So the way we see this physical marketing protection is a long-term insurance policy to make sure our barrels move to the right market.

Kaes Van't Hof:

Yes. I mean you can go on for hours about that. I mean, that ties the culture, right? And our biggest benefit at Diamondback is that we have a small company dynamic culture with a large asset base that's now growing larger. So we are going to have to make sure we maintain that gritty quick, fast-moving adaptive culture to a larger asset base. I'm fully confident that we have the exec team and employee base to both at Diamondback and Endeavor to do that. And I think these big projects, there's a lot of capital being put in the ground before first oil sometimes upwards of $250 million, $300 million, but as long as you have the ability to move crews and rigs within a quarter, within a year, keep hitting numbers, we're going to keep doing that at a larger scale.

Neal Dingmann:

Look forward to the new assets, guys.

Derrick Whitfield:

Congrats on another solid brand. With my first question, I wanted to focus on the second request from the FTC at a high level. Art Research indicates that most of the larger transactions have received that. Is that consistent with how you're thinking about it?

Derrick Whitfield:

All right. Terrific. And then shifting over to ops. So during the quarter, you completed 3 additional Upper Spraberry wells. Based on those results and some from last year, could you speak to how the interval competes in your portfolio and if it's likely to get added to your inventory charts on Page 21?

Kaes Van't Hof:

I think to fill this up to the top of that, Derrick. If you start to add in zones like Upper Spraberry, Wolfcamp D, we've got some really good Wolfcamp D tests in some of those same pads. If you start to add those in and you don't see degradation on a corporate basis in terms of the cume curves that everyone looks at so closely every year. That's inventory extension in our existing asset base. And with the combination of us and Endeavor, adding in zones like the Upper Spraberry, Wolfcamp D into full-scale development, only extends the duration of what we can do here in the Midland Basin.

Paul Cheng:

Travis, is that in your presentation, you have an interesting statement on the ESG, you intend to eventually invest in income-generating projects that are expect to more directly offset remaining Scope 1 emissions. Can you elaborate a little bit more in terms of how big is the kind of investment? Are you expecting that to become a new division or that a new business for you? Or that is -- when it is going to be pretty small scale and result pay over the too much attention on that. That's the first question.

Travis Stice:

Well, the first emphasis on AI has been not degenerative AI, but using AI to process data information a lot quicker. And so, look, we're really excited about the long-term implications of AI on our industry, whether that translates to improvements in AUR or improvements in efficiencies or hopefully both, I think, is yet to be determined. But it's one of those things that we're trying to be fast followers on. This is arena of our industry that's moving incredibly fast. These electric frac fleets that we're using right now actually are accumulating more information than we can process. So we're storing some of that information and hoping to use smart algorithms or AI to help us process that information in a more usable and more real-time fashion. Kaes, this first question was the income-generating tech to offset that.

Operator:

Our next question comes from the line of Leo Mariani of ROTH MKM.

Kaes Van't Hof:

Yes, Leo, a couple of things. I think we're having a pretty good end of the year last year into Q4, and so we pushed completions into Q1. So Q1 looks a little high relative I think generally you can think about that 70 to 80 overall completion a quarter as the base case. Q2 might be a little towards the high end there. But because we're a little bit ahead of plan in terms of efficiencies and timing we're probably going to reduce our frac crew count by 1 for a period of time over the summer as well as kind of get down into that 12, 13 rigs on the drilling side to complete -- to drill the same number of wells. So we look at the plan almost weekly with the planning team. And I think, generally, the efficiencies have led to less overall activity, more capital efficiency and setting us up well for this potential close here in Q4 with Endeavor.

Kaes Van't Hof:

Yes. Not many. We sold a piece of our Viper ownership in the first quarter, and that plugged another $450 million of cash on the balance sheet. And I think I'll go back to when we structured this deal. We certainly do not want to put so much cash into the deal with Endeavor that we had to be a seller of assets, and that's exactly what we've done. Now I think we've had some price help here in the last couple of months that has boosted free cash flow and reduced the cash portion of the transaction. And listen, I think the price has got to be right for any asset sale, whether it's the Deep Blue, Viper or otherwise. And we're going to be patient post-close. I do think those assets make sense in other hands, but it's got to be the right value.

Kaes Van't Hof:

Yes. It was just higher than that before then, a couple of quarters before that, and we had to work off the accruals. That number has been 7% for 10 years. We had a consultant that told us it was going to be higher last year, and that consultant is no longer working for us, but it's going to be 7% on an annual basis on average.

Travis Stice:

Thank you again to everyone participating in today's call. If you've got any questions, please reach out to us using the contact information provided. Thank you, and have a great day.

Operator:

Good day and thank you for standing by. Welcome to the Diamondback Energy Fourth Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions]. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Adam Lawlis, VP of Investor Relations. Please go ahead.

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. So obviously a lot of the material is in that stockholders letter. So with that operator, would you please open the line for questions?

Neal Dingmann:

Well, good morning, Travis and team. Thanks for the time. Guys, my first question is on Endeavor specifically, just want to go back to this. You all highlighted about 344,000 acres with about 2,300 locations, that compares to 494,000, 3,800 for you all. And I'm just wondering, does this slightly smaller current core footprint provide a material amount of immediate incremental locations, Travis. And I'm just wondering or potential upside and I'm wondering how you would thinking about I know it's still a while until this thing likely closes but how you will attack these assets.

Kaes Van't Hof:

Neal, just to add to that point if you think about a company's future two things are really important for the oil and gas sector. One is kind of this durable inventory in case just walked you through some numbers there. But it's also the conversion efficiency of that inventory and I think now with the announcement of this Endeavor merger, we're in control of both the numerator and denominator of that ratio. So our durable inventory greatly extends and then our conversion efficiency that we've been known for a long time actually gets to come to bear on a larger asset base. And I think to give you a little bit more color and comfort; we didn't put our thumb on the scale as we looked across the barbed wire fence. And what I mean by that is we simply applied what Diamondback is doing today on drilling and completion and operating wells and then physically adjacent. This case was just explaining, made the assumption that that can be applied across the barbed wire fence. So I wanted to give you a little bit more color there, Neal. Thanks for your question.

Travis Stice:

Yes. Well, I mean I think generally Neal; the project size is up, I mean 25 is not an exact number. It's going to be different, different counties where you have different spacing within different zones. We're not -- we don't use a cookie cutter strategy to develop the asset. We use a unique development strategy for each area. I think we've had a lot of experience with practice over the years. I think we've learned and our planning group has gotten significantly better at looking around the corner and seeing what issues might arise. And certainly, there's a benefit of size and scale, right? If we have one of these 24 projects coming on every quarter, well, there's a lot of risk in that one particular project. But here we have four, five, six of these coming on every quarter. And that allows us operational flexibility to move around and plan our business. And that's just one of the other benefits of size and scale that will only be magnified with the potential with the Endeavor merger.

Neal Dingmann:

Agreed times, and seems even better next year. Thank you all.

Operator:

Thank you. And one moment for our next question. Our next question comes from David Deckelbaum with TD Cowen. Your line is now open.

Travis Stice:

Thank you, David.

Kaes Van't Hof:

Yes, Dave, I mean, some are -- some are able to be harvested today. Some are probably further down the line. I mean, we've done a pretty good job selling some of these non-core, we call them non-core, but equity method investments over the last 12 months. We sold the Gray Oak Pipeline interest. We sold our interest in the OMOG oil gathering JV. I think it's logical that some of our assets that we can control the sale of will likely pursue a sale, but there's others that we're probably someone who would tag along with a bigger sale, and I can't control when those happen. But it's certainly an asset that we are assets that we have on our side of the ledger that will be used to reduce debt quickly on a scale basis, or through the indefinite merger. So I think that's certainly on the table. I think Travis' point on not having to sell significant assets is important, right? When we structured the cash stock mix of the deal, we didn't want to be a forced seller of assets to pay down debt. And I think we've done that with the mix we presented last week.

David Deckelbaum:

Appreciate that. And just maybe a little bit in the weeds on this one, but the 2024 plan, when you lay out the Midland Basin development, this year maybe coincidentally or not, there's a more -- a little bit more on the margin going to Wolfcamp D and some of the other zones. Is that just more coincidence of geography where you're developing this year and presumably years beyond? Or are there some things that you saw in 2023 that are sort of increasing your confidence of wanting to allocate more capital there and if there's any color you could provide?

Operator:

Thank you. One moment for our next question. Our next question comes from Neil Mehta with Goldman Sachs. Your line is now open.

Travis Stice:

Neil, I mean I think we need to protect our side of the ledger through the period between signing and closing, so we can generate free cash that reduces the cash portion of the purchase price. I think we've done that. We've historically bought funds in the kind of $55 WTI range. We now kind of stepped it up to kind of that $60 range. And we'll probably be a little more hedged on our side between sign and close than we have been in the past, closer to -- I don't know, two-thirds, three quarters hedge, so that we can make sure that, that, that cash is there to reduce the cash portion of purchase price. I think longer-term, it all depends on the strength of the balance sheet and the break-even that we have with our base dividends. We've always kind of tried to buy hedges at kind of 50 to 55. And that protects free cash flow, balance sheet doesn't blow out and the dividends well protected in that extreme downside scenario. So I don't expect us to move to a non-hedging company because we just believe that it's prudent to protect the balance sheet and our base dividend which we see like debt.

Travis Stice:

I think generally, regardless of oil discipline the gas curves in the Permian Basin always exceed expectations. I think we're always pretty conservative on the gas side. And that almost universally beats expectations, which is why you're seeing on a basin level more growth than we all expect almost on an annual basis. So I think that's going to continue, Neil. We don't -- we could run the gas price at zero in the Permian and still make great returns on oil wells. For us personally, we try to protect our gas price by through hedging as well as through some pipeline commitments to get our gas to bigger markets as well as protecting our basis exposure. But generally I think the Permian, even if you stay disciplined on oil, eventually you're going to have to move to gassier zones and there's a lot of gas and associated gas left to be produced in the Permian.

Travis Stice:

Thanks, Neil.

Arun Jayaram:

Good morning, gentlemen. Travis, Kaes, I'd like to know if maybe you could walk us through kind of the path to get to the $10 billion net debt target in terms of timing and how do asset sales, would that influence timing of reaching that target?

Arun Jayaram:

Got it. And just maybe a follow-up. If you do plan to do something in the Delaware Basin, would you wait until kind of reaching close on the transaction or talk us through maybe the timing when you would contemplate doing asset sales?

Arun Jayaram:

Great. Thanks a lot.

Kaes Van't Hof:

Thanks, Arun.

Derrick Whitfield:

Yes. Good morning, all. Wanted to --

Derrick Whitfield:

Wanted to start by really commending you guys for the leadership you're demonstrating on capital discipline, as many of your peers are treating the environment as if it were naturally balanced today.

Derrick Whitfield:

With my first question, I wanted to focus on the service environment. In light of the collapse in gas directed activity that is underway now and the preexisting lower utilization rates the service industry experienced last year, is there an opportunity to revisit service prices on some of the higher spec equipment?

Derrick Whitfield:

Terrific. And as my follow-up, wanted to touch on Endeavor, since you guys have been out meeting with investors since the deal was announced, are there any aspects of the transaction that are underappreciated in your view?

Derrick Whitfield:

Terrific. Thanks. Great quarter and update.

Kaes Van't Hof:

Thanks, Derrick.

Roger Read:

Yes. Thank you. Good morning.

Roger Read:

I just wanted to come back, you talked earlier about some of these other benches that might work, and it's a question of whether they'll be as productive and efficient or the productivity and efficiency in those benches. Give us an idea of maybe some of the, let's call it science or just applied efforts that you're seeing that can open up some of these other benches. And I'm thinking within your footprint, as well as what will be an expanded footprint here before you're in.

Travis Stice:

Roger, I'll just add a comment from a high-level on what Kaes just mentioned. In my experience, as companies get bigger, the more inwardly focused they become. So they focus more on their own results and less on what others are doing around them. And it's been a hallmark of Diamondback since the very beginning. One, you could say, out of necessity when we first started, but it's been a hallmark of ours to really pay attention to what goes on around us. And so right now, it's culturally ingrained not only to rigorously examine our own internal results, but also spend intellectual capital on looking across the barbed wire fence at what others are doing. And as we move into a much larger position post close, I promise you that culture will stay intact. We will continue to look and find what others are doing potentially better than we are and adopt accordingly.

Travis Stice:

Thanks, Roger.

Operator:

Thank you. One moment for our next question. Our next question comes from Jeoffrey Lambujon with TPH & Co. Your line is now open.

Travis Stice:

Hey, Jeoff.

Kaes Van't Hof:

Yes, Jeoff, I think generally there's two big buckets on the DMC side that we see across fence Endeavor that we'll probably look to put in place with the team there as we start to integrate on the completion side, it's really the SimulFRAC development plan, as well as probably half of that plan being a SimulFRAC e-fleet, which only reduces the cost of the completion side of the business. I don't even think we've modeled the benefits of a much larger supply chain to these numbers. This is just us getting their cost down to our costs on the capital side. So there's probably some upside there at some point. And then on the drilling side, we've been a big proponent of clear fluids not using oil based mud to drill these wells. It saves time and money. That was something we put in place and learned from the QEP team three or four years ago. And so I think that's just a decision to make. That saves significant dollars. And what I'm excited about is to get under the tent with the Endeavor team and learn what they're doing that we can do better, right? I think that's not modeled in this pro forma business. And we've learned something from both energy and QEP are two large mergers that we've done to-date. So I think there's some upside there. But really, all we're doing is looking to put in place what we're doing today on a larger asset base.

Jeoffrey Lambujon:

Perfect. And then for my follow-up, I wonder if you could just speak to how the philosophy around the balance sheet longer-term will evolve, if at all, once the deal closes. We appreciate the commentary on the path to get to the $10 billion net debt level, but we're just thinking about how the pro forma math continues to push Diamondback to new levels in terms of weight class within the space.

Jeoffrey Lambujon:

Great. Appreciate the time. I have to turn it back.

Kaes Van't Hof:

Thanks, Jeoff.

Paul Cheng:

All right. Thank you. Good morning, guys.

Paul Cheng:

Last week when you announced the deal, you gave the 2024 and 2025 CapEx pro forma and also the [indiscernible]. It was 2005 the pro forma compared to 2004 with the above say call you wrong number $700 million lower. Can you breakdown that how much relation because you think the antipathy will be lower or that asset because you're not going to grow as fast and how just truly is just --

Operator:

Thank you. One moment for our next question. Our next question comes from Leo Mariani with ROTH MKM. Your line is now open.

Kaes Van't Hof:

I mean there obviously be some benefit with the cash portion of the transaction and the associated interest expense, but we're continuing to do our combination work. I mean we're a full cash taxpayer, essentially. I mean they're pretty close as well. So I don't think there's going to be too much to do there, Leo, but certainly, the cash piece is going to shield a little bit of taxes on our side.

Kaes Van't Hof:

Yes. Listen, Leo, we're on the sidelines here. We're fully focused on getting this deal closed as soon as possible and we can assess the landscape when that happens. I mean I am confident that the landscape will look different whenever that time does come.

Travis Stice:

Thanks, Leo.

John Abbott:

My question is, does that have any impact on integration, planning, or does that go ahead anyway.

John Abbott:

This is John Abbott on for Doug Leggate. Apologies I was on mute. Just one more, just one question going back to Paul's question on the difference in CapEx between 2024 and 2025. That's about $725 million. And then you talk about the $550 million in synergies. So when we think about that $725 million is there an addition on top of that, as were we sort of thinking to 2025? Just sort of trying to reconcile the two numbers?

John Abbott:

Appreciate it. And that's really it at this point in time, but thank you very much for taking our questions.

Operator:

Thank you. I'm showing no further questions at this time. I would now like to turn it back to Travis Stice, CEO for closing remarks.

Operator:

This concludes today's conference call. Thank you for participating. You may now disconnect.

Operator:

Good day, and thank you for standing by. Welcome to the Diamondback Energy Third Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker’s presentation, there will be a question-and-answer session. [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.

Travis D. 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?

Neal Dingmann:

Morning, Travis and team. Thanks for the time and another nice quarter. Travis, my first question is on capital allocation specifically. Several quarters ago, you suggested you all would return to more of a production growth type model, I'd call it. And I think you've mentioned when the macro fundamental 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?

Neal Dingmann:

Got it. That makes sense in this environment. And then secondly on your development, couldn't help but notice the new slides on slides 10 and 11 highlighted the efficient execution and then, differentiated development. My question is, does most of your remaining Midland inventory lend 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 efficiencies continue to come from on these projects?

Neal Dingmann:

Just on the cost, on the cost, I know, Kaes and I've talked about, I mean, is it just on, I know you have lower casing just different, sort of raw material costs, but is there, is there other, areas in that that larger projects that are causing these, when you see that, that well productivity chart on the right, sort of what's driving the lower cost efficiencies there?

Kaes Van't Hof:

Yes. I mean, 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 side is where we save the most money from a capital perspective, because we're doing -- in some cases, two SimulFRAC crews on the same site at the same time. So, you're saving essentially, $250,000 - $300,000 a well from SimulFRAC. And now we have two of those fleets or e-fleets that run-off lean gas that save kind of another $200,000 - $250,000 of well. So, now 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.

Travis D. Stice:

Thanks, Neal.

Neil Mehta:

Yes. Thanks, guys, and appreciate the helpful letter and the time today. Travis, why don't we start on return of capital as a topic talked about this in the letter of, you wanting to air on the side of caution as it relates to, buying back stock to avoid repurchasing pro-cyclically and as a result, leaned into 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 Mehta:

Okay. That, that's really helpful. And the follow-up is just on non-core asset sales. You've done a good job of exceeding your target. Can you talk a little bit about the Deep Blue Midland Basin and 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?

Neil Mehta:

Thanks, team.

Operator:

Alright. Thank you. One moment for our next question. Our next question comes from the line of David Deckelbaum of TD Cowen. Your line is now open.

Travis D. Stice:

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 demonstrating 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 acquirer and exposure 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 would sound industrial logics 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 this. 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.

Daniel N. Wesson:

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 think the team's 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. And, 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's 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've kind of set the stage for a world where we run for the SimulFRAC 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's our backlog, just let Danny sleep a little better at night. And, allows for some flexibility heading into next year.

Travis D. Stice:

Thanks, David.

Scott Hanold:

Yes, thanks. 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?

Travis D. Stice:

I think that makes sense. We've talked about the high bar for entry into the Diamondback portfolio. And, there'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 in converting rock into cash flow. And that's, our cost structure is enviable. Our execution prowess is unmatched. And that makes that makes a big difference when you talk about a profitable oil and gas company like that.

Kaes Van't Hof:

Yes. I mean, I think I kind of said this that we put our next five years up with anybody in North America, and I still stand by that. I think we have another solid, five or ten 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 an hour at [55000] (ph). And, as 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 sparse.

Kaes Van't Hof:

Yes, it's really all about value, 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, if 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 two and a half years ago.

Travis D. Stice:

Thanks, Scott.

Roger Read:

Yes. Thanks. Good morning. I think I'll skip the obligatory share repo versus a variable dividend question for a moment, and just go back to the operational aspects. 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'll 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?

Travis D. Stice:

Yes. Roger, if you back cast 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 7500 foot lateral well, which has a total depth, total major depth of about what we were drilling vertically when we started. But drilling, we drill those 7500 foot lateral wells in under four days. And when we started, we were drilling it, sometimes it'd take 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.

Travis D. Stice:

Thanks, Roger.

Derrick Whitfield:

Good morning, all and thanks for all the incremental disclosures this quarter.

Kaes Van't Hof:

Thanks, Derrick.

Kaes Van't Hof:

That's a good question, Derrick. And I'd probably say that maintenance CapEx would be $100 million to $200 million cheaper, 30 wells maybe, Danny.

Travis D. Stice:

You know, Derrick, while you're on that topic of maintenance CapEx, I might just point you to slide seven, 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 cap, 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.

Daniel N. Wesson:

Yes. Good question, Derrick. We do lay out some of our remaining JVs that we have on slide 26. Yes, 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.

Kaes Van't Hof:

Thanks, Derrick.

Operator:

Alright. Thank you. One moment for our next question. Next question comes from the line of Kevin MacCurdy of Pickering Energy Partners. Your line is now open.

Kaes Van't Hof:

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 been left and other people. So, I think we bid the most, but we bid the most because we could underwrite it with the lowest cost, right. At the time, I think some Lario well costs were near $8.5 million, $9.5 million for 10,000 foot lateral, and we were drilling them at [$6.5 million to $7 million] (ph). And so that's kind of been our mantra for a long time. I would just say generally if you split the two 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 top 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 Lower Spraberry and maybe being wind wrapped 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, now 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.

Travis D. Stice:

Good question, Kevin.

Jeoffrey Lambujon:

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

Jeoffrey Lambujon:

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 onto some of that laterally in the commentary in terms of how that might evolve over the near-term program? That would be helpful as well.

Jeoffrey Lambujon:

Okay, great. And then maybe just a housekeeping type question on the non-core 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 that 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 than theirs, how do you think about opportunities that can near?

Jeoffrey Lambujon:

Perfect. Thank you.

Operator:

Thank you. One moment for our next question. Our next question comes from the line of Nitin Kumar of Mizuho. Your line is now open.

Travis D. Stice:

Nitin, 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 particular 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.

Daniel N. Wesson:

Yes. I mean, I think generally that would be a great problem to have. It really ties to this can you run a SimulFRAC program consistently on that position and those projects and those paths kind of goes all those back to this longer cycle nature of the shale business model. And, I think, we feel really good about four SimulFRAC crews running consistently right now, Nitin, and have the infrastructure to do that. And, if growth exceeded expectations there'll be a good problem to have.

Operator:

Alright. Thank you. One moment for our next question. Next question comes from the line of Charles Meade of Johnson Rice. Your line is now open.

Kaes Van't Hof:

Yes. That's an interesting observation Charles, and it's certainly not lost on us. You've had a couple very large buyers do a couple of deals in the basin and out of the basin. They could kind of do whatever they want, it seems like, but, I would just say generally industry consolidation has happened is continuing to happen. I think a lot of the privates are gone, as you mentioned, to logical acquirers. I would just say that 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 zones and our underwriting philosophy, which is our cost structure, our rates return internally, lot of hurdles for commodity price and usually that has resulted in more assets coming to Diamondback because you can underwrite wells drills at $1 million or $2 million cheaper. We can run LOE above cheaper, that's the kind of stuff that accretes to our shareholders.

Kaes Van't Hof:

Thanks, Charles.

Operator:

Thank you. One moment for our next question. Our next question comes from the line of Arun Jayaram of JPMorgan Securities. Your line is now open.

Travis D. Stice:

Yeah. 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 you know 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, a very winning combination for our shareholders for a long time here.

Travis D. Stice:

Yeah. It's interesting. We really haven't thought about the rig to crew ratio in a long time because 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 to 16 rigs for a full year. And now this year, in 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 paths. And when we need to pick up a rig and when we need to drop it, you're really kind of just targeting, can we keep those silent track crews busy consistently? And I would guess, I guess the number is kind of in that high threes, almost four rigs to one SimulFRAC through today.

Arun Jayaram:

Great. Thanks a lot.

Scott Gruber:

Yes. Good morning and congrats on another good quarter. I want to follow-up on Arun’s question, just on the activity set in the next year. And get some more clarity on the plan for the DUCs. And so it sounds like you could 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?

Scott Gruber:

I got you. So the inventory count is under normal conditions is just going up. I got it.

Scott Gruber:

That makes sense. And in good detail on, all the cost trends across the various, buckets on slide 10. If 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 2024? Are those starting to stabilize now?

Scott Gruber:

Got it. Appreciate the color. Thank you.

Operator:

Thank you. One moment for our next question. Our next question comes from the line of Leo Mariani of ROTH MKM. Your line is now open.

Travis D. Stice:

Yeah. 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 modelled or flattened out. And, I've seen a major change in rig count. This feels like a pretty good range for next year.

Travis D. Stice:

You know, Leo, I tried to address that a little bit in my opening comments as 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 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.

Travis D. Stice:

Thanks, Leo.

Paul Cheng:

Thank you. Good morning. Two questions. One, one of the way that to reduce costs, I think the industry is moving for the electrification. And shot at 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 on 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 infrastructure. Thank you.

Paul Cheng:

Just curious that, I mean, what percent of your operation now here has already been electric buy in, that way you think is the biggest opportunity over the next one or two years.

Paul Cheng:

Thank you.

Travis D. Stice:

I appreciate all the good questions this morning. I hope you find our shareholder letter constructive in 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 Veterans Day, certainly for all of the veterans that are important 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 and God bless.

Operator:

Good day, and thank you for standing by. Welcome to the Diamondback Energy Second 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 the VP of Investor Relations, Adam Lawlis. Please go ahead.

Travis Stice :

Good morning, and thank you, Adam. As Adam mentioned, last night we released a shareholder letter in conjunction with our press release, and this is our second quarter in a row we've tried this. I hope you find it useful. We believe that it not only increases the transparency directly to our shareholders but also improves efficiency, and those of you who have followed our story for a long time know how important improving efficiency is to us. So with that, operator, let's move right into questions, if you'll open the line.

Neal Dingmann :

Morning, Travis. Guys. Nice quarter. Travis, my first question, maybe get right to it, is on service cost, and we've heard a lot of chatter about. Specifically, could you speak to maybe the current rig and frac rate environment today versus a couple of months ago? And maybe more importantly, what are you all assuming the change in cost for the remainder of the year, and how this could impact the '24 levels?

Neal Dingmann :

So Travis, is it too early to call any deflation for next year at this point?

Neal Dingmann :

Great. Great point, guys. And then my second question on capital spend. Specifically, it looked like you slightly increased the midstream and upstream CapEx guidance very, very slightly. But I'm just wondering, are you able to give a little color on maybe how this will be allocated both for the upstream and midstream? And then potential benefits with this slight push in cost, especially noticeable around the midstream, but I'm curious around both, maybe any benefits that we could see from this upturn?

Operator:

Thank you. [Operator instructions] Our next question comes from the line of Neil Mehta of Goldman Sachs. Your line is now open.

Travis Stice :

I'll take those in reverse order. If you're talking about the deals that we did earlier in the year, they've been seamlessly integrated with absolutely no issue. I will say that both of those companies we acquired were running more rigs than we're currently running now, which again continues to be the trend as you see acquisitions occur, operators that are acquiring or dropping rigs as they focus on increased profitability. The landscape, Neil, certainly relative to what we've seen in the last couple of quarters, there's just really a few opportunities out there, I mean there was a rush primarily on the private equity side to get deals into the market. And relative to what we see right now, it's very, very limited. As to Fang's roll in M&A, we have created a lot of shareholder value through M&A but our discipline has also been noteworthy as well, too. It's not important to win every deal. It's important to win deals that make us not bigger, but better, and so we'll continue to always hold ourselves accountable to that. But I'll go back to my earlier comment that relative to what we've seen in the first half of the year, it's pretty parsed on a go-forward basis.

Travis Stice :

Sure. The leverage obviously moves around with the oil price, but I think having a leverage ratio of less than one is appropriate for the size and scale of a company of Diamondback size. I do think also with building a little bit of cash on the balance sheet continues to make sense in order to be opportunistic for share repurchases in a countercyclical way. But those are kind of the two inputs that we build our capital structure and return model around.

Arun Jayaram :

Good morning, Travis and team. Both of my questions relate to CapEx. My first question is on your updated guide, you're guiding to an $80 million decline in sequential CapEx in 4Q versus 3Q, which you're pegging as the new baseline. I was wondering if you could help us understand the drivers of the lower CapEx in 4Q versus 3Q?

Arun Jayaram :

Great. And kind of stole my thunder here on the second question, but your 2024 outlook is to drive low single digits oil growth. I know the Street is now modeling around $650 million per quarter in CapEx, but it sounds like you're comfortable, case as we stand here today, at something in the low 600s.

Travis Stice :

Arun, just as a reminder, we've been guiding for kind of lower CapEx all year long in the back half, and we're seeing it play out now. And as we laid out on Slide 6 of our investor deck, sort of a forecast by quarter of what that looks like.

Derrick Whitfield :

Good morning all and congrats on a strong quarter.

Derrick Whitfield :

Staying on 2024, now that you've fully integrated FireBird and Lario, what is the right base level of activity that would support the 2024 outlook from a rig and frac spread perspective?

Travis Stice :

And Derrick, just to add to that, this profitability model that we've been demonstrating now for multiple quarters in a row and the industry has pivoted to, I hope we have been able to demonstrate that volume growth is an output of efficient capital allocation that's laser-like focused on profitability. So as here on August 1, as we're entertaining questions on 2024, the volume growth will be an output of efficient capital allocation that maximizes the value for our capital allocation decisions.

Kaes Van't Hof:

Yes, Derrick. I think generally, we feel very confident in the forward outlook for productivity. I think that's going to be a unique position in North American shale. We've been -- we timed deals very, very well, and we've made the shift to co-development four or five years ago now, and that's resulting in very steady productivity. As you can see within 1% of 2022 levels already in '23. And I would just say flat feels like the baseline, and if it's better than that, that's one for the good guys.

Operator:

Our next question comes from the line of Charles Meade of Johnson Rice. Your line is now open.

Travis Stice :

Charles, I wish I could say it was one individual piece of technology that's transferable across our entire rig fleet, but it's much more subtle than that. And I'm going to let Danny give you some specific examples. But we get this question a lot, and it's always phrased in different ways about why does Diamondback do what they do, but the answer remains unchanged. It's the culture that we have that has an extreme focus on cost control and efficiencies. And the reason that that's important to our culture is because when we make those gains in efficiencies, those gains become permanent in part to our future capital allocation decisions, which makes us more competitive for the same dollar that's that we're competing with relative to our peers. And it's not -- again, it's not one or two items. It's thousands of items that are decided upon every one of these rigs. And look, we have a healthy competition among our rigs and completion crews that we incentivized monetarily for efficiency and cost control measures. And Dan, do you want to add some specifics on that?

Travis Stice :

Charles, just one add to that. We just completed our quarterly reviews several weeks ago, and the teams present to us levels of details of measurement that Daniel was talking about, which is almost stunning to me, but we do it almost every quarter. And that is, they measure how long it takes to physically screw pipe together for 300 times for every trip they have to make. And in that measurement of just simply screwing pipe together in five minutes versus the next rig over that was 6 minutes, you think doesn't matter. But you do that several bit trips, bit runs per well, it adds up, and that's the level that our organization focuses on efficiency. And we have a lot of Diamondback employees listening into this call this morning, and I want them to hear that I'm proud of that work that they continue to do and deliver those results of four days, 7,500-foot wells that Danny just alluded to.

Travis Stice :

Let me talk to you about how we discussed it at the Board level. The primary form of shareholder return is in our base dividend. And we put that in place to be not only a sustainable, but a growing base dividend. And as I talked about earlier this quarter, we increased our base dividend another 5%. And so as you look into the future, that base dividend will remain of paramount importance to us, and we believe that we have that base dividend covered down to $40 a barrel of oil. So I'll just give you some confidence as to that base dividend. The second piece of the equation is share buybacks, and share buybacks are determined based on our future expectation of future cash flows and turned into a stock price so that we can measure where we want to repurchase shares back. And so you can tell from the last several quarters, the fact that we've leaned in all of our discretionary free cash flow after our base dividend to repurchase shares. And in a general sense and not specific, because everybody wants to know what stock price we're using, which we won't say until the quarter is behind us. But the lower the stock price, the more you get share repurchases. The higher the stock price, you tend to purchase less. So I hope that makes sense. And then anything left over from that calculus, Charles, is going to be distributed in the form of a variable dividend because we made a commitment to our owners that we would return 75% of our free cash flow. So I hope that makes sense.

Operator:

Our next question comes from the line of Subash Chandra from Benchmark Company. The line is now open.

Kaes Van't Hof:

Yes. Good question. Listen, we're allocating a lot of capital to the Northern Midland Basin where it's very oily particularly early time. I think we kind of guide people to 59%, 60% oil. I think that's probably a fairly good baseline for the next few years. In a world where we're not growing as much, that oil cut stays flat and comes down slightly because the oil declined a little faster than the gas piece. But generally, we had a couple of higher gas cut wells in the Delaware Basin in the beginning of this year that boosted the gas production as a company. But overall, kind of high 50s, 60% in a good quarter would be a good range for oil cut.

Kaes Van't Hof:

Yes. I'll take that two ways. Generally, on the purchase side, we've been doing a little bit of leasing as well as a little bit of netting up. We try to make our asset teams involved in BD. They're making offers on undeveloped interests and those non-op pieces that we don't own in our development. So they're doing work there. We've been looking at leasing some of the deeper rights in the Midland Basin across some of our positions, so that's tied to some of those purchases in the cash flow statement. And then on the divestiture side, we've divested a good amount of what we deem noncore acreage and acreage that doesn't compete for capital in the next kind of 10 years of development, and have received some good prices there. I'd say we're on the sidelines more on the divestiture side today outside of what would be a very unique offer. Instead, we're more focused on the noncore midstream type divested like the OMOG divestiture we announced this earnings. We didn't increase our noncore asset sale target. We certainly have some more assets that make sense to sell, we'll just most likely be tagging along and not controlling the process.

Leo Mariani :

Hi guys.Want to talk a little bit about production here, so second quarter, a very nice beat versus the guidance. I think you guys said that you kind of drilled a record number of wells in the quarter. Looking at third quarter production guide, it does indicate that on a total basis, production should be down a little bit this quarter. Can you just help us kind of think through that dynamic a little bit with kind of record drilling last quarter, but production is coming down? Maybe you guys are kind of holding some wells off in terms of turning them in line until later in the year? What's kind of happening there?

Leo Mariani :

Okay. That's helpful. And then just on capital here. So kind of looking at kind of where you guys were in the second quarter. I mean, it looks like that's going to be the peak. So we should be expecting CapEx to come down, I guess, both in 3Q and in 4Q. How much of that is kind of related to service cost? You just talked about fewer completions in the second half, but is it really fourth quarter where you start to see maybe more service cost benefit? You talked about going from low 700s per foot start the year at a kind of low 6s by the end of the year. So are you starting to get some of that benefit here in 4Q? A similar number of completions, 80, should be down kind of a fair bit on capital here in 4Q? Just help us think of that a little bit.

Operator:

Our next question comes from the line of Paul Cheng of Scotiabank. Your line is now open.

Kaes Van't Hof:

Why don't we answer the first one first. I think Diamondback is really a technology company that produces oil, and we spend a lot of time looking at improving EURs, we spend a lot of time looking across the bench-line of what competitors and peers are doing. There's not a ton of secrets in the Permian Basin, so if there is a better mousetrap, we're going to find a way to do it. I think our advantage is that we can do it at a lower cost. So generally, we're constantly pursuing, improving EURs, improving recoveries, improving technologies. You'd expect us to be on our front foot there. I don't think we're going to spend a ton of dollars testing that, but would instead be a fast follower on anything that looks to be working.

Kaes Van't Hof:

I don't think it's possible today. I certainly think there's some people spending money to look at it. But for us, we really want to allocate capital to the best returning projects that we have today. And that for us is high-return, multi-zone development in the Midland Basin.

Kaes Van't Hof:

Yes. I think it's a risk-reward decision, Paul. There are certainly some areas where we can drill longer. I think -- but I think generally, the way our land position is laid out and the way our acreage sits today, that 10,000 to 11,000 range feels about right on average. We'd rather drill a 15,000 footer than 2 7,500 footers. But I think today, we'd rather drill 2 10,000 footers versus 1 20,000 footer. So I think the drilling guys can do it on the drilling side. There's no doubt about that. But it's it's a risk-reward decision because if something bad happens at 18,000 feet, that's expensive mistake. So we'd rather continue to get wells down at 10,000 feet in 8, 9 days consistently versus risking a 30, 40-day well when something goes wrong.

Travis Stice :

Appreciate everyone listening in this morning. Good set of questions. I hope you have a fantastic day. If you've got any questions, just reach out to us at the number provided.

Operator:

Good day, and thank you for standing by. Welcome to the Diamondback Energy First Quarter 2023 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Adam Lawlis, Vice President of Investor Relations. Please go ahead.

Travis Stice:

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

Neal Dingmann:

First, thanks, Travis, for the new format. Appreciate it. Travis, my first questions for you or Danny, on one of the top [indiscernible] that service costs. Specifically, are you able to quantify how your continued operational efficiencies have recently mitigated the cost? And just wondering how you all think about spot versus long-term contracts in the current environment?

Danny Wesson:

No, I think Travis covered everything that we're -- we've kind of seen on the drilling services side and consumable side, on the drilling side, that’s leading us to see leading edge costs coming down. And then on the completion side, just with the additional efficiencies from the additional e-fleet as well as the replacement simulfrac fleet replacing the two traditional zipper fleets that we took over as far as the two acquisitions at the end of the year.

Kaes Van't Hof:

Yes, Neal, we always -- when we upped the shareholder return program to 75% of free cash going back to shareholders, we bought the mix of 75% equity and 25% to the balance sheet was a good mix. We still believe that's a good mix. I think when things are going well, like they have in the last couple of years, 75% feels like a max number to go back to equity while continuing to improve the balance sheet. Really the test of this new business model and returns -- return of capital-based business models when things go south in a potential downturn, that's, I think, the time when we should be allocating more capital to buying back shares, reducing the share count a lot more efficiently than it is even when things are going well at today. So we've kept a flexible return of capital program since the beginning. I think we like that. We want to keep that. And Q1 is an exact reason why we maintain that flexibility. We don't want to blow out the balance sheet to buy back stocks, but we also recognize that when your stock is down significantly in the quarter, variable dividend doesn't matter. And that's what we did in Q1 and allocated a lot more cash to the buyback.

Travis Stice:

Thanks, Neal.

Neil Mehta:

Yes. Good morning, team. And again, thanks for the new format. The first question was around gas price realizations. Obviously, they were soft in the quarter. There's some one-time dynamics it felt like. But just curious on your views on how local gas pricing is going to play out here? And what protections you guys have built in place in order to mitigate pricing negativity?

Neil Mehta:

Okay. Thanks for that, Kaes. And then just a follow-up on some of the recent acquisitions that you've done here that you've had them in your portfolio now for a couple of months. Just any update on how they're executing early thoughts on productivity and efficiencies that you're able to realize out of the new assets?

Neil Mehta:

Awesome. Thanks, guys.

Operator:

Thank you. One moment for our next question. Our next question comes from the line of Arun Jayaram of JPMorgan Securities LLC. Your line is now open.

Kaes Van't Hof:

Yes.

Kaes Van't Hof:

Yes. Good question, Arun. On the cash CapEx thing, the prime example was Q2 of 2020, while I don't want to relive that particular quarter, we reduced our rig count from 15 -- or 23 rigs down to 6, and we had to pay for that in the second quarter. So there's a big disconnect between accrued and cash CapEx. Now that's not the issue we faced here, right? We are talking about things at the margin like a $50 million or so reduction in run rate CapEx, which is, in my mind, very achievable based on three things

Arun Jayaram:

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?

Arun Jayaram:

Great. Thanks a lot.

Operator:

Thank you. One moment for our next question. Our next question comes from the line of Scott Gruber of Citigroup. Your line is now open.

Kaes Van't Hof:

Scott, I think that's partially true. Certainly, on the frac side, the higher quality equipment, the superspec e-fleet those have real contracts associated with them with less global room on pricing. So that's why we think generally, we make more money or save more money there on the efficiency side. On the rig side, I think generally, the 10% of your market is going away in a quarter or 2, it's going to have an impact on pricing. There's just no doubt about that. So leading edge rates certainly are lower. I think we've also proven in the past to do more with less when it comes to equipment on the rig side, particularly in the Midland Basin, where it's a lot easier to drill in general than other places around the country.

Kaes Van't Hof:

Yes. Look, I think obviously, we had a very good start to the year on LOE. We still feel good about the midpoint of that range mainly because not because of power, but because of some of our activity is moving to areas where we have water dedicated to third parties, not ourselves. And so that has a little higher rate. And so we expect LOE to trend up a little bit in Q2, Q3 as some of those big pads on third-party areas are developed. But generally, we received a benefit in terms of gas prices on the power side to lock in a lot of power. And I would say generally, we've locked in about 75% of our expected power needs for the foreseeable future that should keep LOE generally lower for longer and less exposed to the price spikes that we saw last summer.

Kaes Van't Hof:

Thank you, Scott.

David Deckelbaum:

Good morning, Travis, Kaes, Danny and team. Thanks for taking my questions today.

David Deckelbaum:

Morning. Just longer term from an efficiency gains perspective, you all made some headway and you highlighted the benefits of using e-fleets and moving that second e-fleet this year. How do you think about as we progress into '24 and '25, the mix between simulfrac fleet and e-fleets, if we assume sort of this flattish rig count towards the two to two mix, the expectation for longer-term development?

David Deckelbaum:

Got it. And then my second question just around asset sales. You already did around $773 million or so the date you point out that you've exceeded your target. You guys also highlight the remaining five or so outstanding investments that you're articulating on slide back in the back, mostly on the midstream side might be a source of funds going forward. Could you place like -- is there a high probability that we'll see another asset sale this year?

David Deckelbaum:

Appreciate it. Thanks for the time guys.

Operator:

Thank you. One moment for our next question. Our next question comes from the line of Roger Read of Wells Fargo Securities. Your line is now open.

Travis Stice:

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

Kevin MacCurdy:

Hey, good morning. With the 1Q release, you've kind of given the pictures to figure out what the 4Q '22 or '23 CapEx and activity is. As we look into potential 2024 maintenance CapEx program, is the 4Q activity kind of a good activity and CapEx is a good starting point? Or would you need to add any activity to keep production flat next year?

Kevin MacCurdy:

Great. That’s the only question for me. Thanks guys.

Travis Stice:

Thanks, Kevin.

Derrick Whitfield:

Good morning all and congrats on a strong start to the year.

Travis Stice:

Thank you, Derrick.

Kaes Van't Hof:

Yes, Derrick, good question. I think generally, we are going to see very -- a lot of volatility and some pockets of extreme weakness. Obviously, there's a few expansions coming on, three expansions in the back half of this year and the beginning of next year, ahead of a large flat coming on at the end of 2024. I just think there -- the issue to date had been masked in the field as processing capacity in the field was short. Now that that processing capacity is coming on, the tune of bcf a day or more that's going to push the problem downstream to the downstream residue pipes. So I think it's coming, it's going to be pretty weak for periods and then pressure will be relieved a little bit when these expansions come on. But generally, our take is, let's remove our risk to that pricing weakness by hedging everything through 2024 and getting more physical molecules for the Gulf Coast. Ideally, we'd like to have control of all of our molecules to the Gulf Coast, but most of our contracts we inherited from deals that we bought have not come with taking kind rights, and we've worked to improve that over time and control more of our molecules further downstream.

Kaes Van't Hof:

Yes. Good question. I think we said multiple times to investors, flat to 2022 is probably the base case, and we do a little better. That's one for the good guys. I think we are on pace for that, particularly in the Midland Basin where we've had a really strong start to the year. And I would just say FireBird and Lario only enhance that ability to do that for longer. At the end of the day, as we've said before, the shale cost curve is going up. It's our job to make sure we have the inventory duration and the cost structure to be at the low end of that shale cost curve, which we've done well for the last 10 years, and we expect to do well for the next 10 years.

Travis Stice:

Yes, Derrick, I think just to reiterate that point that I've made a couple of times now about Diamondback's commitment to our shareholders about maintaining the lead and efficiency and cost execution. It's exactly what Kaes just said.

Operator:

Thank you. One moment for our next question. Our next question comes from the line of Scott Hanold of RBC Capital Markets. Your line is now open.

Kaes Van't Hof:

Yes. Good question, Scott. I would say internally, it certainly does. This business is not easy to grow consistently and hit numbers consistently. But externally, we think we are going to grow fairly smoothly organically through the back half of the year. In general, our target is to turn about 85 wells to sales a quarter, some quarters are going to be a little higher, some are a little lower based on timing. But in general, that's our job, right. It's -- there's a lot going on beneath the surface, and that's what makes the Diamondback operations team the best in the business.

Travis Stice:

Yes, we've commented a couple of times about the increase in activity through 2022 was largely driven by independents and the challenge there is depth of inventory, right? And the secondary challenge is how much can increase further beyond their max cadence that they achieved last year. And I think both of those are playing out now. The max cadence may be softening, as you see by rigs getting laid down. And certainly, the inventory depth is getting accelerated with this rapid pace of bringing wells to production. So I think from an M&A perspective, it's going to be an interesting time over the next couple of years as these entities, the small ones, private, just try to figure out a way to monetize. And I think you've also got while their catalyst is unclear, you've also got some small cap public companies that are going to need to figure out some form of exit strategy to be -- continue to be relevant in the future. And then there's always the large private unicorns that's still flowing around out there as well, too. So I really think the next couple of years are going to be interesting in the M&A landscape.

Travis Stice:

Well, Scott, when you do M&A, and if you do it correctly, you want to extend inventory life, you want to make sure that your free cash flow or cash flow accretive and you don't want to impact your balance sheet. So just doing PDP type acquisitions doesn't necessarily fit into that calculus, but it's -- I think that's what you're going to end up seeing with some of these exit strategies or just kind of straight PDP divestitures.

Travis Stice:

Thank you, Scott.

Jeoffrey Lambujon:

Good morning, everyone and thanks for taking my questions.

Jeoffrey Lambujon:

The first one is just on commentary and the supplemental release that talked about the trend continuing this year in terms of the large high NRI pads coming on in the Northern Midland Basin. Is there any additional color you can give there in terms of how the mix of the total program going to that type of acreage where you might have much less surrounding development compares to that same mix or waiting to that type of acreage last year and just how to think about that mix over the near-term?

Jeoffrey Lambujon:

Great. I appreciate that. And then on the services side, I certainly appreciate the detail just around where you see potential improvements and the timing around that throughout the year. I was just hoping you could speak maybe high-level to how your contracts are set up, I guess, across the services spectrum just to give a sense for how some of these improvements will layer in from Diamondback specifically over the course of the next couple of quarters?

Travis Stice:

Jeff, in addition to that, we talked earlier about purchasing steel multiple quarters in advance. So we are seeing the steel that we are purchasing for our 3Q, 4Q, 1Q costs already coming down. And so while it's not necessarily a service cost deflation, it is a cost deflation that could be as much as $20 or $25 a foot additionally.

Travis Stice:

Thanks, Jeff.

John Freeman:

Good morning, guys.

John Freeman:

You all had -- in fourth quarter, when you all are running ahead of schedule and you moved some of those POPs from the fourth quarter into the first quarter, and just given all the commentary on the big efficiency gains on the final fracs as you now go to towards four with funnel fracability, if we end up in a similar spot where you have efficiency gains later this year, is it likely that you all -- and again, it's a first class problem, but would you similarly make a decision like last year where you would sort of, I don't know, pump the brakes is the right word, but maybe slowdown in touch so that the budget is intact? Or do you just sort of plow ahead with the efficiency gains and just bring more wells online?

John Freeman:

That's great. And then I really appreciate all the detail and color you've given on the service cost front. So does it sound like -- obviously, things are coming down from the peak levels of 1Q, but is it -- are you all basically indicating that you are on track to potentially have lower total completed well costs by year-end '23 versus year-end '22. Like when you factor in what you're seeing on the cost side, but maybe more importantly the efficiency gains from the simulfracs?

John Freeman:

That’s great. I appreciate it guys.

John Freeman:

Thanks, Travis.

Tim Rezvan:

Good morning, folks. Thank you for taking my question. I wanted to circle back Dave's questions previously on asset sales. I'm sure you won't give a good answer on the Bloomberg story about Pecos County. But I think it highlights the number of levers that you can pull to get to $1 billion or more on asset sales. So trying to understand, Kaes, what do you think a good kind of target debt level is? Do you think about it in terms of leverage or an absolute debt metric as you compare yourselves to the large cap peers? And I guess why wouldn't you go bigger than that $1 billion given you're not allocating a lot of capital to the Delaware right now?

Tim Rezvan:

Okay. And then just getting back to that number in an ideal world, how do you think about what the right debt number is, whether either in debt or in leverage terms for [multiple speakers]?

Tim Rezvan:

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

Operator:

One moment for our next question. Our next question comes from the line of Charles Meade of Johnson Rice. Your line is now open.

Kaes Van't Hof:

Hey, Charles.

Charles Meade:

Travis, this may be for you. I like the new format as well, but the -- I was also thinking about the shareholder letter. And Travis, in your prepared comments, I think you said you were hoping this format would be more efficient to pick up on a big thing for you this morning. But I was wondering also, does this -- the iteration on your communication style, I mean, does this also reflect an element of maybe dissatisfaction with how either your story is being understood or the traction that you're getting or that you maybe feel like [technical difficulty] that you're not? And if that is true or if that's the case that there's some element of it, what do you think the market might be missing?

Kaes Van't Hof:

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

Kaes Van't Hof:

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

Charles Meade:

Thank you gentlemen. Appreciate the color.

Operator:

Thank you. One moment for our next question. Our next question comes from the line of Roger Read of Wells Fargo Securities. Your line is now open.

Travis Stice:

Good morning, Roger.

Roger Read:

Let's dig into the service cost in deflation, I guess, we could call it at this point. We haven't so used to using inflation. Can you talk to us a little bit as you think about well costs being lower in the fourth quarter, how much of that is efficiencies and how much of that is just a decline in the cost of doing something being drilling rigs or whatever? 50-50, 60-40, 80-20, something like that as well. I was curious.

Roger Read:

Okay. Yes, that's helpful. And then the other follow-up question I had was, is there any sort of rule of thumb approach you use as you switch to fleets? Or as you went from the zipper frac to the simulfrac in terms of how do you want to think about it, stages per day, cost per stage, something like that? Again, just trying to understand some of these changes as they get applied all across the entire complex.

Danny Wesson:

Yes. I mean an e-fleet towards utilizing our simulfrac fleets, they're just powered with electric power that we generate on location or that we pull off the grid. So really, the savings on the e-fleet comes from the fuel consumption piece and just being more efficient on location. We do think we see a little bit of disparity between the kind of lateral footage completed per day by the e-fleet versus the diesel simulfrac fleets, but we don't have a just a ton of data yet to quantify that, but we are hopeful that over time, the e-fleets will kind of widen the gap of execution efficiency just because of the lower maintenance and R&M stuff that's required on location.

Danny Wesson:

Yes, I mean -- so we kind of say simulfrac fleet depending on the jobs can do about twice as much lateral footage per day as a traditional zipper fleet.

Danny Wesson:

No. It's just a hedge in the market. So it's just a financial hedge, not a physical trade.

Operator:

Thank you. One moment for our next question. Our next question comes from the line of Leo Mariani of ROTH MKM. Your line is now open.

Kaes Van't Hof:

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.

Kaes Van't Hof:

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

Kaes Van't Hof:

Yes. I think the only real added benefit that Q1 had versus Q2, even if commodity prices were flat is that we closed Lario in the quarter and got to write-off some of that, the hard assets that came with that right away.

Kaes Van't Hof:

That's fair.

Operator:

Thank you. One moment for our next question. Our final question comes from Paul Cheng of Scotiabank. Your line is now open.

Travis Stice:

Good morning, Paul.

Kaes Van't Hof:

I think over the next few years, the 85%, 15% is a very fair yearly estimate. Obviously, some quarters will be higher than others. We want to continue to complete multi-well pads in the Delaware. So you have a quarter like Q1 of 2023, which was higher Delaware when Q4 was 0 wells in the Delaware. But on an annual basis, 85%, 15% feels like the right lateral footage mix.

Kaes Van't Hof:

I don't know if I'm ready to commit to that today, Paul. We certainly have some work to do, but we have very good line of sight from an activity and a cost perspective that we've seen the peak in well costs and a little bit of a tailwind from the activity of 2 rigs coming down. Now I think that will happen a little bit in Q3 and more in Q4, but it's still early.

Kaes Van't Hof:

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

Kaes Van't Hof:

[Indiscernible] not raw materials.

Kaes Van't Hof:

Thank you, Paul.

Travis Stice:

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

Operator:

Good day, and thank you for standing by. Welcome to the Diamondback Energy Fourth Quarter 2022 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 speaker today, Adam Lawlis, VP of Investor Relations. Adam, go ahead.

Travis Stice:

Thank you, Adam, and welcome to Diamondback's fourth quarter earnings call. 2022 was another great year for Diamondback. We successfully executed on our capital program, accelerated our return of capital plan and generated record cash flow. I'm very proud of all that we were able to accomplish and look forward to what I believe will be another strong year for the company. Looking back at last year, we produced over 223,000 barrels of oil per day, exceeding our production expectations. This is primarily the result of our well performance, which continues to trend in the right direction as our normalized oil production in the Midland Basin improved by 6% year-over-year and nearly 20% when compared to 2020. We continue to optimize our multi-zone co-development strategy, which we pivoted to prior to the pandemic by tweaking our frac designs, spacing assumptions and landing zones to maximize our returns. On the operations side, we've also built out substantial water infrastructure, which allows us to implement simul-frac completions across our position. This type of completion is consistently more efficient than a traditional zipper frac design because we can complete approximately 80 wells per year with just one crew. When you add in the additional efficiencies we're seeing from our Halliburton e-fleet, our completion savings are approximately $50 a foot. Last year was not without its challenges from significant inflationary pressures, particularly with casing, equipment availability and weather-related downtime. However, our operational team did what it always does, deliver best-in-class execution. Our ability to hold our capital budget flat and stay within our original guidance range while also exceeding our production target is something you should expect from Diamondback as we push to deliver differentiated results quarter after quarter. Financially, we generated over $7 billion in EBITDA and $4.6 billion in free cash flow or nearly $26 per share, both records for the company. We made significant progress on our return of capital plan, increasing our cash return commitment in the middle of the year to return at least 75% of free cash flow to stockholders. In total, we returned 68% of our free cash flow in 2022, which equates to $3.1 billion through a combination of our base and variable dividend and share repurchase program, buying back nearly 8.7 million shares at an average price of $126 per share for a total of $1.1 billion. This represents 5% of our shares outstanding when we announced our program in September of 2021. An additional $2 billion was returned through our base and variable dividend with the total dividend growth of nearly 5x when compared to 2021. In total, we returned $11.31 per share in dividends. In the fourth quarter alone, we returned over $860 million or $5.65 per share with a total dividend yield of nearly 9%. This included an increase to our annual base dividend of $0.20, now $3.20 per share annually or $0.80 per quarter, representing 54% year-over-year growth. We also announced multiple strategic transactions in the fourth quarter that better position us for the long term. We made two Midland Basin acquisitions, Lario and FireBird, both of which are now closed and seamlessly integrated that added over 500 high-quality opportunities and 83,000 net acres to our portfolio. This additional inventory, along with the associated production and cash flow, has solidified our size and scale in the Midland Basin, giving us a strategic advantage as we execute on our capital programs for the decades to come. Last summer, we bought in all the outstanding units of Rattler, which gives us additional flexibility to think strategically about our existing midstream portfolio. We now have the ability to monetize assets that trade at a higher multiple than our upstream business and use the proceeds to strengthen our balance sheet or acquire additional upstream assets. The first example of this was the sale of our 10% interest in the Gray Oak crude oil pipeline to Enbridge. We achieved a 1.75 multiple on our invested capital and used the proceeds to partially fund the cash portion of the Lario acquisition. As we evaluated both our Rattler operated assets and equity method investments, we've also monetized multiple noncore upstream positions. We have now divested nearly $600 million in upstream assets since the third quarter of last year, which includes two recent deals in Southeast Glasscock and Ward and Winkler counties. These assets simply did not compete for immediate capital within our portfolio. We have now increased our noncore asset target sales from $500 million to at least $1 billion by the end of this year. Last year, we improved our leverage ratio, now below 1x, and also pushed the tenor of nearly 90% of our debt past 5 years, with over $2 billion due in the 2050 at an average coupon of below 5%. We will continue to use free cash flow and proceeds from our noncore asset sales to lower our overall debt profile, continually improving our financial position. As we move into 2023, we expect to deliver relatively flat pro forma production year-over-year. When you account for the 11 months of Lario and a full year of FireBird production contribution, our guidance reflects 260,000 barrels of oil a day and $2.6 billion in CapEx, while running 15 rigs and 4 simul-frac crews. In closing, 2022 was an outstanding year for the company. We generated record free cash flow and distributed nearly 70% of it to our shareholders, strengthened our balance sheet, extended our inventory runway and continue to produce one of the highest margin barrels in the industry. Looking ahead, our business model is working, and we are confident in our 2023 outlook and our ongoing ability to continue generating peer-leading returns for our stockholders. With these comments now complete, operator, please open the line for questions.

Neal Dingmann :

Thanks for all the details, Travis. My first question is just on shareholder return topic. More than -- it's now been maybe even two years ago, certainly, more than a year ago, you mentioned way back that you thought once the macro supply demand was more in balance, you'd consider potentially more growth. I'm just wondering, has the thinking changed based on what we know of continued investor shareholder return or other factors that continue to drive sort of the environment in today?

Kaes Van't Hof :

Yes. I think also on top of that, Neal, we're going to be growing oil production per share significantly in 2023 through two well-timed acquisitions and a significant amount of buybacks in 2022. So per share metrics continue to improve. We continue to invest in high-return projects while not having to change our activity plan on a monthly basis trying to follow the crude price. The plan is the plan, and this steady state of activity has produced good results to date and no need to change that while it's working right now.

Travis Stice :

Yes. It's certainly not just one thing, Neal. It's really a combination of all the things that we focus on really multiple times a day when it comes to executing our program. Certainly, well productivity enhancements add to that, but that's really an output of a very difficult decision we made in 2019 to pivot away from kind of the best two zone development strategy and embrace the multi-zone full section development strategy, which we're seeing benefits of today. You also hear us talk frequently about our cost structure and that cost structure is made up not only on the expense side where -- whether it's G&A or LOE, but also on the capital efficiency side where we continue to push the envelope, particularly on the variable cost side of things, simply doing more with less. And all of those things combined, I think, put us consistently towards the top of the most margin efficient producer in the basin.

Neil Mehta :

The first question I had was around noncore asset sales and you did bump your target from $0.5 billion to $1 billion by year-end 2023. Can you give us a little bit more color around what are the natural strategic assets? And what the market looks like for asset sales right now?

Neil Mehta :

Yes, that's great perspective. And then the follow-up is the oil volume guide for the full year was solid. Q1 a little bit softer. So maybe you could just talk about the cadence of production over the course of the year and just how we should be thinking about the path for oil production in particular in 2023?

Operator:

And our next question comes from Arun Jayaram from JPMorgan Securities.

Travis Stice :

Yes. Good question, Arun. In 2018 and early 2019, we were really studying this co-development strategy intently, and the significant observation that we made from our analysis was that essentially, all of these zones talk to each other. And if they talk to each other, which means you actually have pressure communication during the fracking operations, which subsequently also means that you're kind of sharing the reserves as an individual well is produced that if you don't get them upon initial -- the initial development that when you go back in later, you'll find those zones have experienced some depletion and that depletion degrades the efficiency of your stimulated rock volume, which ultimately changes the production profile. And so in order to address that, we examined our spacing assumptions, both side to side and top to bottom, and made adjustments to try to minimize those frac pressure interferences. Spread some zones out further, spread some zones above and below further, but essentially went into a section -- half of section this time was our development strategy and completed all the wells at one time and then brought them all on at one time. And that was a painful decision because it's a lot easier. In fact, I've been -- I've said it before that I'll take criticism from drilling the very best zone, but we found out that, that actually wasn't the right development strategy, and we took some things for that in 2019. But as you can see, we put some details in our -- on Slide 16, as you alluded to. We're -- in the Midland Basin, our well results are equivalent to what we were seeing in 2017. So very proud of the technical team and their diligence to try to crack a very difficult problem and then the courage to stay with that decision through periods when we were questioned about that development strategy. So I hope that answers your question, Arun.

Kaes Van't Hof :

Yes, great question, Arun. I think FireBird, at the end of the day, is the quintessential Diamondback deal, where we know the space and like the back of our hand and have been communicating with the FireBird team as they tested their position further West in the basin than others have in the past. And we follow the results closely and posted a couple of recent results that I think confirm a couple of things, but also give us some hope on upside in the central prospect. And there's a couple of wells sand the future may vary on the Far West side. This was probably the farthest West test to date and not an area we underwrote, and you have a very good Wolfcamp A result Far West. And then in the Southern portion of the position, you have this -- sorry, you have the four corners two-wells Wolfcamp A and Lower Spraberry. And we underwrote Lower Spraberry with Wolfcamp A upside across the central prospect, and it's looking more like you can have Lower Spraberry with Wolfcamp A co-development across that position. So early days yet, but definitely a positive sign from the FireBird deal, and our technical team's work in getting that deal across the finish line.

David Deckelbaum :

The first question is really just a follow-up on Arun's question. [indiscernible] you've seen a thematic of your peers testing additional zones this year. Maybe can you give us a sense of the 330 to 350 wells you're doing this year? [indiscernible] current inventory?

David Deckelbaum :

That's correct. Sorry about that.

David Deckelbaum :

And then [indiscernible] third year now of being in relatively a maintenance mode or low-growth mode, have you seen noticeable differences year-over-year in benefits from perhaps improved base declines? And how does decline [indiscernible] on '22 or '21?

Operator:

Our next question comes from the line of Jeanine Wai from Barclays.

Kaes Van't Hof :

Yes, Jeanine, I think a couple of things, right? Q4 was going to be a great quarter going into December. We had -- obviously, we all had a winter storm here. Diamondback did not announce the winter storm impact, but certainly, the winter storm did impact our production. So going into the last 10 days of the quarter, we felt very good about where we sat and still hit guidance. And therefore, from a POP perspective, we kind of moved some wells from Q4 into Q1 to get a head start on POPs. It's not a huge capital impact, but it is a number where we guide to first production. So there's a good amount of POPS in Q1 2023 because we were ahead of schedule in Q4 and feeling good about where we started Q1 this year.

Kaes Van't Hof :

Yes, no change, Jeanine. Really, the variable is the output of how many shares we didn't buy back in a particular quarter, and the buyback is still going to be very opportunistic. And I think now that we've kind of gone through this for four or five quarters, you can see that we step in and buy back when things are weaker. There's still been a lot of volatility in the space. We're going through a period of that volatility right now. And so you look back at a quarter like Q4, bought back less shares in October and November, but hit the buyback very hard in December. And I think you can expect us to keep doing that and then having the variable be the output of what base dividend plus buyback doesn't get through in a particular quarter.

Derrick Whitfield:

Good morning, all. Congrats on a strong year-end.

Kaes Van't Hof :

Thanks, Derrick.

Kaes Van't Hof :

I think the biggest benefit, Derrick, is not only the assets we acquired from QEP and guide on, I think that deal while done at a tough time hit exactly what you're looking for in a transaction, right? We allocate more capital to those assets that we would have allocated to the business prior to the deals. So we're seeing a little benefit there. Those assets are also in areas where you have three or four or even five zone development, and so we're having massive pads come on in high-return areas with a little bit of a benefit on the Viper side with high mineral interest across that position. So space -- as Travis mentioned earlier in the call, taking a close look at spacing, learning from other operators in the basin, what to do and what not to do and implementing that very quickly into our plan is paying dividends.

Kaes Van't Hof:

The biggest headwind over the last six quarters has been casing costs. Now we can certainly see around the corner that maybe we're seeing some softening there. I'm not going to count on it until we see it, but casing has moved up from, let's call it, $40 or $50 a foot to $110 a foot. It's 20% of our Midland Basin well cost now, and that's a significant headwind over the last 6 quarters. I think the headwind is going to ease. If not, it's a little bit out of our control. But the things that we can control are the efficiencies gained from simul-frac operations. We'll probably have four simul-frac crews running by Q2 of this year, which is highly efficient, saves about $30 a foot versus conventional crews. And on top of that, two of those crews are going to be the Halliburton e-fleet Zeus crews, and those use less fuel, but also run on cheap Waha gas right now. So that saves another $15 or $20 a foot. So we're doing what we can to cut costs and keep costs as low as possible in an inflationary environment.

Roger Read :

I'd just like to maybe dive into the gas takeaway question and how you're -- I understand how you're positioned not to have Waha basis risk for the most part, but what are you looking at in terms of flow assurance this year and to the extent you can say next year?

Roger Read :

Appreciate that. And the other question I wanted to follow up on -- I am just looking for the right page, yes, Page 23 on the hedge summary. Any thoughts on -- if we look at where Q1 has hedged, Q2 really kind of similar, is that what you'd want to do ultimately for the back half of the year as we draw in closer and it becomes more financially reasonable to do that? Or are you, at this point, more comfortable going a little less hedged just given the overall structure of the balance sheet, presumably with these dispositions coming, a little more cash coming in?

Operator:

Our next question comes from [Jeoffrey Lambujon] from [Perella Weinberg Partners.]

Kaes Van't Hof :

Good question, Jeoff. I think, generally, we guided to this year being around 15% year-over-year well costs, sub-10% from what we highlighted in November. And I would say, generally, those numbers still fit today. I would say, we're probably in the upper half of our well cost guidance for both Midland and Delaware today. But generally, there are some things coming our way outside of service cost deflation and that's another Halliburton Zeus e-fleet moving to four simul-fracs versus last year, we ran three in a spot crew. So that last simul-frac adds some efficiency. And I kind of put the budget two ways this year. I think if we see deflation, we're going to be closer to the lower half of our guide. And if we stay flat, we'll be to midpoint to the higher end. But I think generally, the anecdotes are coming in that some things are heading our way from a service cost perspective. And unlike last year, not everything -- not every line item will go up in the AFE.

Scott Gruber :

I want to circle back on the completion efficiency comments. E-frac obviously brings a pretty good fuel savings given the gas diesel spread here and obviously, associated ESG benefits. But do you think e-frac additions will be additive to the improvement in cycle times above and beyond what you're seeing from simul-frac?

Danny Wesson :

Yes. I think we've only been running the first crew for about six months, and we've been really impressed with the performance thus far. It's outperformed our other fleets kind of on the margin, but not too measurable. We do believe that over time, you'll see that gap widen in performance, just really believe that the maintenance required around the e-fleet equipment will be substantially less. So we're excited to learn through that with Halliburton and recognize some added efficiencies on top of just fuel savings as we go forward.

Danny Wesson :

Yes. I mean we don't really have any long-term contracts in place. We kind of have shorter cycle pricing agreements I think generally, we're exposed to market pricing across the board, and we certainly have some protections in place on some of our consumables, but if we start seeing the market soften, which we feel like is a pretty good likelihood with where we see gas prices today, that should trickle down into the oil basins, particularly on the drilling services side of things first. And we've certainly not seen a lot of upward pressure on pricing in the first part of this year. It's been pretty quiet, and hopefully, we'll start seeing some help on the inflation front here through the second and third quarter.

Kevin MacCurdy:

Congratulations on the great free cash flow quarter. It looks like cash taxes came in well under expectations and the guidance for 2023 cash taxes was below our model. I wonder if you can talk about what is driving the cash taxes lower, and any benefits you may be receiving from acquisitions?

Operator:

Our next question comes from Leo Mariani from ROTH MKM.

Travis Stice :

Yes. I think you've got just a couple things that are impacting LOE. First, we're fairly exposed to the power market, and we rode through the back half of last year fairly unhedged through the -- we're up in gas prices and that really impacted our real-time power pricing, and you've seen kind of real-time power pricing kind of stay a little elevated through the first part of 2023 here. And so trying to guess where we're going to land with respect to power and have an opportunity to get hedged to protect ourselves, but -- so that's adding about a dime. And then you've got another impact from the FireBird acquisition with about 900 vertical wells, which had another dime or two to our consolidated LOE. So between those two things, you're looking at about a quarter, and we think we're probably running in the lower end of the guide today. And if we see some things come our way, we think we could potentially be under the guide, but we're not baking that into our guidance.

Kaes Van't Hof :

Yes. I don't know if sellers are ever reasonable, Leo. But generally, I do think the two larger transactions did happen because Diamondback's cost structure was differential in the second half of the year and going into 2023, right? We're drilling wells $2 million, $3 million, $4 million cheaper in the Midland Basin than peers, and that is when you underwrite PUDs, that drives value to the good guys even if you're not running strip oil pricing. So I think generally, that's what's happened. There's less and less large opportunities like the two that we announced last fall. So it's relatively quiet at the moment. But some of the smaller things that tend to trend with the large deals like the blocking and tackling, a couple of other deals that Firebird and Lario we're working on when they sold. That's the kind of stuff that we're focused on right now.

Paul Cheng :

In your presentation, you show a number of the energy ownership that in the pipeline and gas processing. Just curious that if any of those that you will consider strategically important for you to own their equity ownership? Or that -- I mean just trying to see that I mean, whether any of them have that strategic importance to you? Second question is that when we're looking at your inventory backlog, for those you consider over 10,000 feet, lateral length, you roughly say, call it, 5,500. Just want to see if we can drill a little bit more into that, and what percentage of those wells you can actually do maybe 3-miles? And whether there's an opportunity for trade and swap that you think you may be able to improve on that?

Operator:

[Operator Instructions] Our next question comes from Doug Leggate from Bank of America.

Kaes Van't Hof :

Yes. Good question, Doug. I would say, generally, we were surprised at the amount of E&P assets we sold relative to initial expectations of $500 million of noncore asset sales because we raised that to $1 billion. We're at $750 million to date. It's logical that most of those -- most of the rest of the $250 million or more come from noncore asset comes from midstream assets. I will say if they're -- it's going to be harder for us to sell operated midstream assets versus non-op midstream assets like the JVs that we highlighted in the back of our deck like you inferred, operated midstream assets do have an impact on LOE and financials. Whereas non-operated assets, you do have a cash flow impact from less distributions from those assets, but not as meaningful to the parent co. So I think it's logical that more non-op stuff is top of mind, but for the right value, some operated stuff would be on the table. Just we'd be cognizant of what that would do to our operating metrics.

Kaes Van't Hof :

Yes. I mean, I guess the answer would be, we're going to get through all of our NOL in 2023. So that will be exhausted, and we'll be a full cash taxpayer, although as you mentioned, we will be able to defer some with respect to intangible drilling costs and the CapEx we spend on the business. So I guess it will be dependent upon where -- obviously, where commodity prices are in 2024. And second to that, where CapEx is, I think we're obviously in a world where we're going to be spending -- continue to spend less than we make. So it's logical that there will be a tax burden. There's just too many variables right now to predict 2024.

Travis Stice:

Thank you, again, to everyone for participating in today's call. If you have any questions, please contact us using the information provided. Thank you.

Operator:

Hello, and thank you for standing by. Welcome to the Diamondback Energy Third Quarter 2022 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there’ll be a question-and-answer session. [Operator Instructions] It is now my pleasure to introduce Vice President of Investor Relations, Adam Lawlis.

Travis Stice:

Thank you, Adam. And before we start with my prepared remarks this morning, I want to encourage each of you to please take advantage of one of our greatest privileges we have as Americans, our freedom to elect our representatives. Please take the time off your busy schedules today to go vote, if you've not already done so. Welcome to Diamondback's third quarter earnings call. A Diamondback, we pride ourselves on our execution. Our commitment to being the lowest cost operator in the Permian Basin has and will continue to position us for success through the cycle. The third quarter was no exception. In the quarter, we produced over 224,000 barrels of oil per day and generated approximately $1.7 billion in operating cash flow. Our CapEx was once again within our guidance range, leading to free cash flow of nearly $1.2 billion. As we previously announced, we increased our return of capital commitment and stated that beginning this quarter, we would return at least 75% of free cash flow back to our shareholders, up from at least 50% previously. At 75%, total capital return was nearly $875 million, with dividends totaling $403 million or $2.26 per share. The remaining $472 million went towards our opportunistic share repurchase program, where we bought back nearly 4 million shares at an average price of approximately $120 a share. To date, we've spent approximately $1.2 billion of our $4 billion buyback authorization, repurchasing nearly 6% of our shares outstanding since September of last year when we initiated our program. In October, we announced the pending acquisition of the assets of FireBird Energy, a company with a large, contiguous position in the Midland Basin. We feel FireBird has right balance of cash flow and inventory and the acquisition is immediately accretive on all relevant per share financial metrics while providing a long runway of high-quality drilling opportunities. With over 350 locations, we expect to have well over a decade of run room at our projected one-rig development phase. In conjunction with the acquisition, we announced that we would sell at least $500 million of non-core assets by the year-end 2023, with net proceeds primarily used to pay down debt. Since then, we closed on a $155 million sale of non-core assets in the Delaware Basin, jump-starting our program and ensuring continuous improvement to our investment-grade balance sheet. We will continue to pursue strategic divestitures, including the sale of certain assets within our Rattler portfolio, generating unrealized value for our shareholders. In closing, we know our business. We know we have some of the best inventory in the United States with our low-cost operational machine in place. We have the unique ability to generate significant repeatable returns through the drill bit for decades to come. In 2019, we began co-developing our primary targets. Since then, we've learned how to optimize our development patterns and spacing, and as a result, are seeing material improvement in well productivity over the past 36 months. In fact, our well performance this year is back at 2019 levels, when we were primarily targeting one-off wells in our -- zones, which while having great performance and economics and the potential to withstand significant components of our inventory, leading to material parent-child concerns down the line. Fortunately, we are well positioned for the future. We expect to close on the FireBird transaction at the end of November and slow the development pace on that asset from three rigs to one. We are working with our service providers to ensure that we have the most efficient and cost-effective personnel and equipment in place for next year, including the two e-fleet simul-frac crews we've secured from Halliburton, the first of which is already in the field and performing well. All of this will provide operational momentum as we move into 2023 we expect to deliver the same operational results you've come to expect from Diamondback. While we won't be giving detailed for the 2023 guidance today, we believe that we'll be able to generate low single-digit pro forma oil production growth next year by maintaining our current standalone activity levels plus the one additional FireBird rig. It's not easy to operate in this environment, but our size, scale and quality of the inventory uniquely position us to deliver differentiated results and create meaningful value for our shareholders. Before I open up for questions, I want to address all the Diamondback employees that are on the phone. At Diamondback, we've just celebrated our 10 years as a public company, growing from a $500 million market cap to almost $30 billion today. The people around me this morning and sometimes me individual get too much credit for the success. It's you, the men and women of Diamondback that deserve the credit. It's your pursuit of excellence, your desire to be the very best version of yourself, your dedication to integrity that is responsible for our success. It remains my privilege to represent you. Thank you for all that you do. Operator, please open the line for questions.

Neal Dingmann:

Thanks. Good morning Travis and team. Travis, my first question is on your developmental strategy, specifically, could you all discuss if you have or will continue to develop, you mentioned, I think it's Slide 7, you've gone to the co-development, you all went there really, I think, before a lot of others did. And I'm just wondering, are you going to do that is that pretty much on all the assets included when you take over FireBird, and I'm just wondering the second part of that, are there parts of this process that you believe you still have an advantage over peers. It just seems to me when I'm looking at sort of margins in the perm, you all still are leading. So I'm just wondering, if there are some things you're doing when looking at that Slide 7 that you still think are leading as sort of the pack.

Neal Dingmann:

Yeah, it really sounds encouraging. Then turn to my second question, well, I guess, I'd call it the topic your and that's on shareholder return and capital allocation. Travis, for you or Kaes, I mean, do you see any scenario where you all would back off that 75% payout and maybe turn to more growth or something else? And then on the capital allocation, obviously, you all had a nice stock move. How do you feel about the buybacks versus it is?

Kaes Van't Hof:

Yeah. And then no change to the 35% of free cash flow, while it's certainly a restrictive amount of cash to be giving back to the equity holders, we feel that our balance sheet is in a position to be able to do that. And we're still going to reduce debt through non-core asset sales or free cash flow generation and our debt structure is significantly better than it has probably ever been in our company history. So generally, we feel that, it's time for our equity holders to get their cash back after this company has matured from a high-growth company to a high-returning company.

Kaes Van't Hof:

Thanks, Neal.

Neil Mehta:

Yeah. Good morning, team, and congrats on 10 years that pass by very fast. So, well done here, my first question is on 2023 capital spending and any early thoughts here as we bridge from your 2022 levels to next year? And talk about all the moving parts ranging from inflation activity?

Neil Mehta:

Okay. And then we'll look for a little more clarity, but that's a helpful starting point. And then Travis, a question for you is just on your outlook for US shale growth. I think a number of industry participants have been surprised by how flat the US production profile has looked here over the last several months. And so curious on your thoughts on shale maturity? And is the lack of growth that we're seeing relative to expectations a function of service bottlenecks, or is it a function of also asset maturity?

Neil Mehta:

Thanks, guys.

Arun Jayaram:

Good morning, gentlemen. Kaes or Travis, I was wondering if you could talk a little bit about the evolution of your co-development strategy, which you shifted in 2019. You highlighted how your well productivity now has returned to 2017 levels. I wondered to see if maybe you could also maybe compare and contrast how Diamondback's development looks like relative to many of your peers, because you highlighted how you believe you're completing the most number of zones per pad in the Midland Basin?

Arun Jayaram:

Great, great. And then maybe just my quick follow-up. As you guys have now started to develop some of the assets you bought from Guidon and QEP in Central Martin County, can you give us a sense of how the early wells have been trending? And what type of mix should we expect in Martin County on a go-forward basis over the next couple of years?

Arun Jayaram:

Great. Thanks a lot.

Derrick Whitfield:

Good morning all.

Derrick Whitfield:

Travis, with the understanding that you guys have limited exposure to Waha in 2023 and the recent weakness was really driven by maintenance. Could you speak to your macro views on gas ingress over the next few years? And how you plan to mitigate your exposure over time?

Kaes Van’t Hof:

Yeah. I mean, basically, next year, two-third of our gas goes to Waha, and that's all been hedged today, actually hedged a while back. And the other third gets Gulf Coast exposure on the Whistler pipeline. And then as you think about 2024, we think there's going to be pockets of weakness in 2024, certainly easing in the back half of the year when the big pipe Matterhorn comes on, but it's going to be tight from now until then, because some of these expansions, yeah, there are 500 million a day expansion, but I think they're going to be full right away.

Kaes Van’t Hof:

Yeah, a good question. I think the biggest thing that's going to help us next year from a cost perspective are the two Halliburton e-fleets that one has just started and one is picking up. I think generally, on the horsepower side, we get charged a little bit less. They make more margin on that particular piece of business. On top of that, we're not spending money on diesel, right? So we're fueling that fleet with cheap Waha gas for the next couple of years, and that could be anywhere from $10 to $15 a foot of savings depending on what the price of Waha is. And we just opened our first mobile mine or mini mine that's going to be right offset some of our Martin County position. So I think generally, while we're not drilling wells to TD faster than we were last year, we're still best in class in that area. Now, it's time to work on the other pieces of the cost equation as inflation heats up here.

Derrick Whitfield:

Great, update. Thanks for your time.

Operator:

Thank you. And our next question comes from the line of David Deckelbaum with Cowen.

Travis Stice:

You’re welcome, David. Good morning.

Kaes Van’t Hof:

Yeah. I mean really, David, it's all value, right? But generally, internally, we see that an E&P business trades at 4, 5 times and a pipeline or a gathering system trades at 8 to 10 times. So it's logical for us, with us not getting any credit for it in our valuation to look at some of the JVs that we invested in alongside contributing volumes to those businesses over the last five years. And now, I think they're in kind of a harvest mode where it might make sense to sell, particularly given our buying of Rattler and renewed focus on the upstream business, which is what we're so good at. So, I won't commit to certain projects, but there are certainly some of our JVs were sitting on big wins, and you could expect us to try to monetize those appropriately over time.

Kaes Van't Hof:

Yes. I mean I think it's going to be around for a while, certainly longer than the market can see today, which I think is important, right? We have two well-timed deals in 2020 that that we're benefiting from today. I think generally, our job is to allocate capital to the best returning zones and projects first. So, we won't be able to keep this up forever. But I think as the shale cost curve goes up, which is likely to happen over the next decade, our job is to maintain a cost structure and an inventory that keeps us at the low end of that cost curve. And that's what we've built this business on. And I think we have both the inventory and definitely the cost structure to be able to keep ourselves at the low end of that cost curve longer.

Kaes Van't Hof:

Thanks, David.

Jeoffrey Lambujon:

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

Jeoffrey Lambujon:

Just a couple for me on the FireBird acreage, in particular, a little bit on productivity, but also a bit on inventory. I saw in the deck that you highlighted some small results on that acreage. I just wanted to get your thoughts on if there are any potential implications there from an inventory standpoint? If you could maybe speak to how the locations you've spoken to, to this point that asset are distributed across the position? And secondly, what sort of upside you might contemplate in terms of inventory based on some of these results?

Jeoffrey Lambujon:

Got it. Thanks, guys.

Operator:

Thank you. And our next question comes from the line of Jeanine Wai with Barclays.

Kaes Van't Hof:

Good morning, Jeanine.

Kaes Van't Hof:

Yes. Jeanine, I won't say it interrupts operational momentum into next year because it's our job to not have those issues. We are running a couple of extra intermediate rigs today to get ahead of these large pads where the big rig follows. So I think the message is nothing to see here from operational momentum. That's what you expect us to do, and that's what we do best. Just -- I would just say, we probably completed a couple of more wells in the Delaware than we originally expected this year, and we ran probably one less rig than we thought for the year. So -- on the other side of the equation, we're completing probably 15 less wells than we went into the year expected to complete. So your capital efficiency is certainly looking good and momentum feels very good going into 2023.

Kaes Van't Hof:

Yes. Good question. I think we did release 19,000 barrels of oil a day net for FireBird in 2023 and that is not changing. The base business FANG, we went into 2022 saying we're going to keep 220,000 barrels of oil a day flat. We've kind of outperformed that a little bit this year. But basically, you can take that 220, complete the same number of wells as we expected at the pre FireBird Diamondback level, and that should spit out a couple of percentage points of low single-digit growth. And then add that FireBird 19 on top of that, and nothing's changed here from our perspective. You think that what you expect us to do, be transparent and hit these numbers.