Diamondback Energy Q1 2024 Earnings Call Transcript

Quartr
Provided by Quartr
May 1, 2024

There are 15 speakers on the call.

Operator

Good day, and thank you for standing by. Welcome to the Diamondback Energy First Quarter 2024 Earnings Conference Call. At this time, all participants are in listen only mode. After the speakers' presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 11 on your telephone.

Operator

Please be advised that today's conference is being recorded. I would now like to hand the conference over to Evan Lawlis, VP of Investor Relations. Please go ahead.

Speaker 1

Thank you, Jules. Good morning, and welcome to Diamondback Energy's Q1 2024 Conference Call. During our call today, we will reference an updated investor presentation letter to stockholders, which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, Chairman and CEO Case Van Toff, President and CFO and Danny Wesson, COO. During this conference call, the participants may make certain forward looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses.

Speaker 1

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

Speaker 2

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 an efficient way to communicate. We spent 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?

Operator

Thank you. At this time, we will conduct a question and answer session.

Speaker 3

Our first question comes

Operator

from the line of Neil Mehta of Goldman Sachs. Your line is now open.

Speaker 4

Yes. Good morning, Travis, Case and team. 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.

Speaker 4

Can you spend more time on that? And as it relates to that, how do you think about the timing of debottlenecking Permian gas?

Speaker 2

Well, from a macro perspective,

Speaker 1

I think we've been pretty clear that we're going

Speaker 2

to continue to need pipes being built about every 12 to 18 months out of the Permian to accommodate the associated gas that goes along with the 6,000,000 barrels a day that we produce out here. Natural gas is right now being almost treated like a waste product and we've got this when Matterhorn comes on this fall, we'll see some of that reverse. But, Kees, you want to give them some description of what we're doing the rest of the gas?

Speaker 1

Yes, Neil. I mean, listen, we 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 contracts on other areas to commit to other pipes that were built. As Travis said, we just need to do more.

Speaker 1

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 demod 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, etcetera, we're going to keep pushing on more pipes and more markets out of this basin.

Speaker 4

Yes. Thanks both. And then the second is capital efficiency. You talked about the 10% improvement that you're expecting per lateral foot. So just talk about what you're seeing real time in terms of deflation?

Speaker 4

And then also what are the next steps in terms of driving your cost structure lower as we think about efficiency of fleet?

Speaker 2

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 and C operations where we're getting I think we average almost 13,000 feet for the quarter this year, and we're continuing 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.

Speaker 4

Okay. Thanks, Travis.

Speaker 2

Thanks, Neil.

Operator

Thank you. Please standby for our next question.

Speaker 3

Our next question comes from

Operator

the line of Arun Jayaram of JPMorgan Securities LLC. Your line is now open.

Speaker 5

Yes, good morning. Travis, you and the team had highlighted up to $550,000,000 of annualized synergy capture in the transaction in the Midland Basin, including 150 foot decline in D and E cost in the Midland Basin to that $600,000,000 to $650,000,000 range. Maybe a follow-up to Neil's question, but where are you seeing kind of leading edge kind of cost today in the Midland Basin as you continue to push those lateral lengths a bit longer?

Speaker 1

Yes. In this case, I think the combination of those longer laterals, 12,000 plus with some efficiencies on the completion side that we probably weren't expecting going into the year as well as some softening on the service side makes us feel pretty good that we're in the lower half of that $600,000,000 to $650,000,000 a foot in the Midland Basin. As you know, 90% of our capital is being allocated to that basin. So with those costs trending in the right direction, I think on a real time basis closer to 600 a foot, we feel really, really good about our plan this year as well as carrying that momentum into a Q4 close, the Endeavor deal and into 2025. Very clearly, we laid out some strong synergy targets and a very strong capital efficient 2025 plan, and we still feel very, very confident in that plan.

Speaker 5

Great. Kees, looking at the quarter, you didn't really have any 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?

Speaker 1

Yes. Listen, there's still a place for the Delaware program. There's still some really good projects coming up in Q2. I think we have a project in that Rameo area, Northern Reeves County that's going to be very good. I think generally with large pad development, you're going to see pockets of development in the Delaware rather than consistent development because we want to go over there and complete multiple wells, multiple pads in a row and keep that capital efficiency high versus the Midland Basin where 3 or 4 simulfrac crews are going to be running at all times.

Speaker 6

Great. Thanks a lot.

Speaker 2

Thanks,

Operator

Our next question comes from the line of David Deckelbaum of TD Cowen. Your line is now open.

Speaker 7

Good morning, Travis, Case and team. Thanks for your time today.

Speaker 2

You're welcome, David. Good morning.

Speaker 7

Case, maybe this question is for both of you guys, but considering the positioning a bit early with the debt that you raised earlier this month, now the expectation that the deal closed at the end of the year with Endeavor. You talked about kind of the synergy expectations in the last series of questions. Can you give us an update on how you're thinking about that initial sort of non core sale asset target and maybe some of the updated timing around those thoughts considering the markets changed a bit, especially around the cash consideration portion? Yes.

Speaker 1

I mean, I think what's changed is just timing, right? I think the projects we see as non core 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 two businesses are combined. And our strategy to execute on those trades has not changed.

Speaker 1

It's just been pushed out to the right. So on top of that, there's an $8,000,000,000 cash consideration that continues to be worked down with free cash flow between sign and close. I think that just means we have to pony up less cash at close in Q4. And we raised the money a couple of weeks ago because we were preparing to potentially close the deal as early as today. Unfortunately, the deal has been pushed out due to regulatory review, but we had to be ready to fund the deal and that's where we were.

Speaker 1

Fortunately, the bond deal was pretty well timed. We're actually earning very minimal negative carry on the cash that we have sitting at the banks today and we'll be ready to use it when we close in a couple of quarters.

Speaker 7

Thanks for the thoughts there. Maybe just to follow-up a little bit more on just the gas pipeline side, just for my own that verification, just some clarity, just you highlighted you didn't have any issues with egress, you have Matterhorn coming online in the Q3. 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?

Speaker 1

Yes. Well, I mean, we're facing them right now, egress issues, right? Not on the physical side, but certainly on the price side. So I think if we can remove the pricing aspect of pricing molecules at Waha versus pricing them further downstream and just paying a fixed fee on the pipe, that to us is a risk mitigation strategy that makes sense for Diamondback shareholders. So I think we see the gas forecast continuing to increase.

Speaker 1

If you do look back on the big public's, the big public third party services and what they thought gas production was going to be in 2024, they've all been wrong. So it's always been more gas sooner. And so for us, we need to handle that physically where we can and with our balance sheet and size and scale, we can sign those 10 year deals because we know we're going to be around to produce for a very, very long time.

Speaker 7

Thanks for the thoughts guys.

Speaker 2

Thanks, Steve.

Operator

Please standby for our next question. Our next question comes from the line of Scott Hanold of RBC Capital Markets. Your line is now open.

Speaker 8

Yes. Hey, guys. Thanks. I'm just going to stick on the gas team as well because it is very

Speaker 1

topical, but it sounds like and just correct me if I'm wrong, you

Speaker 8

guys feel good Diamondback standalone basis as well as with Endeavor with gas capacity at least for the foreseeable future and just confirm that's correct. And if you could also maybe opine on just broader Permian in general, do you expect other operators to see some physical

Speaker 1

plan. I think we have a lot of visibility. We have more and more physical space coming our way. Every molecule has 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.

Speaker 1

I'm focused on Diamondback and we're going to be in really good shape.

Speaker 8

Okay, fair enough. And then my next question is on stock buybacks. Obviously, it sounds like it's going to be a little bit more tempered until the deal closes with Endeavor. But can you give us your thought process on buybacks post merger and how you think about the intrinsic value of the combined company and what mid cycle price makes sense to underpin that?

Speaker 1

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.

Speaker 1

I would expect that to stay about the same here in the second and third quarters depending upon the market. If we see some weakness, we're going to step in and support the stock. But longer term, we want to make the 9 figure, 10 figure bets on buybacks at the right time and that's the flexibility we want on capital return. I think we still see kind of mid cycle in the $60 to $70 range. I think we were firmly $60 for a long time.

Speaker 1

We're probably closer to $70 $20 $2 or $3 gas. And on the combined business, you look at what we have with Endeavor, there's a significant amount of inventory and a lot of NAV accretion. So and then probably a lower combined cost of capital. So I think we feel like we can raise that buyback top a little bit, but we're probably going to be cautious until we close. Yes.

Speaker 1

Just to clarify a

Speaker 8

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

Speaker 1

Yes. We've always been a little higher than 10%. I think an after tax PV-twelve felt like a mid cycle price felt like a very conservative price to buy back shares. And that also makes sure we don't get trapped into a positive feedback loop of buying back shares all the way to the top. So I think an after tax 12% rate of return in this business is a really good rate of return at a mid cycle price and that keeps you in a good spot through the cycle.

Operator

Thanks for that. Our next question comes from the line of Roger Read of Wells Fargo Securities. Your line is now open.

Speaker 9

Yes. Thank you. Good morning. I'd like to come back on the, let's call it efficiencies and lower costs. Obviously, some part of that as you mentioned was service competition rig on rig, crew on crew lowering costs.

Speaker 9

But if you looked at the underlying improvements you cite, e fracs over a diesel frac, kind of where do you think we are in terms of running through continued efficiencies there as we, let's say, alter the equipment, maybe alter the methods of doing some of the wells and with the danger of crossing the line here to post Endeavor kind of what you see as maybe a year or 2 out in terms of continued efficiency gains?

Speaker 10

Yes. Good question. We are continuing to drive cost out of the business through our operational plan and execution. On the completion side, a lot of

Speaker 1

that's going to come

Speaker 10

in the way of getting these e 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 gain. But we are getting to a point where the fixed cost of the wells are a significant a significantly larger portion of the cost of the well than the variable cost. So we're getting to a

Speaker 2

point where the variable cost that

Speaker 10

we're going to impact are 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

Speaker 2

the wells. Roger, I give our guys some joke with them a little bit on the drilling side because they're almost to the point where they're spending more time screwing pipe together and unscrewing pipe together than they are actual rotating hours in the lateral, not quite, but they keep certainly pushing the envelope. And really if you go back to what we said during the acquisition announcement with our merger announcement with Endeavour, we talked about $150 a foot. Dollars 100 of that foot was from just simply going to a simul frac and the other $50 a foot was going to clear fluids. And really that's what we're doing today.

Speaker 2

So we emphasized at the time that's not a big stretch. It's just simply doing what we're doing today on a new set of assets. And in Danny's comments, we're spot on as well.

Speaker 1

Got you. So we just need somebody to come up with

Speaker 9

the next better mousetrap out there for the step functions. I appreciate that.

Speaker 1

Yes. I mean, listen, Rob, one other comment on that. I mean, the guys are so good on the drilling side now. They're measuring how thick the threading is between casing and on the drilling side to say, can I screw that pipe together a half a second faster versus what I used to do? I mean, it is down to the absolute second on-site to reduce those variable costs.

Speaker 1

Appreciate that for sure.

Speaker 9

Okay. Well, guys, that's kind of where I wanted to go with the question. So I'll turn it back. Thank you.

Speaker 1

Thanks, Roger.

Operator

Thank you. Please stand by for our next question.

Speaker 3

Our next question comes from

Operator

the line of John Freeman of Raymond James. Your line is now open.

Speaker 11

Good morning, guys.

Speaker 2

Hey, John.

Speaker 11

Just following up on these efficiency drivers. Obviously, in the quarter, the wells that you all completed, the 101 wells, they were right in line on the lateral length of what you all's guidance was for the full year of around that 11,700 feet. But obviously, the you all point out the 69 wells that you all drilled in the Midland Basin that were significantly longer than that over 13,000 a foot and obviously 1st class problem given the capital efficiency you're seeing on these longer laterals. But should we still use that full year guide of 11,500 foot average for the year? Is that still applicable or should we consider that probably moving up relative to the original guide?

Speaker 10

Yes, John. I think in the Q1, those longer laterals were really just a function of where we were completing the wells. That average lateral length of 11.5 is what we expect to see for the rest of the year.

Speaker 11

Okay. And then just shifting gears a little bit on the topic of trying to get a sense of like how much you all are able to do sort of in advance of the Endeavor deal closing. And I know that in those initial efficiencies that you all laid out, things like maybe pricing power, supply chain, things like that weren't even necessarily priced into those initial synergies. So I'm trying to get a sense of like how much can you all do in advance in terms of like negotiating with some of your service providers in anticipation of sort of the larger combined entity buying in bulk, things like that? Like how much of that, if at all, can you do in advance or you just kind of have to sit and kind of wait till the deal closes to kind of get running on that stuff?

Speaker 2

Yes, John, we're going to operate as separate companies until the deal closes and those things will all come to the benefits of the combined company, but certainly can influence any outcomes until we're closed.

Speaker 11

Got it. Thanks guys. Solid quarter.

Speaker 1

Thanks,

Operator

John. Thank you. Please stand by for our next question.

Speaker 3

Our next question comes from

Operator

the line of Neal Dingmann of Truist Securities. Your line is now

Speaker 12

open. Good morning, guys. Travis, my question for you, Kay, is just on the marketing side. I look in 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, I guess, when that closes, what type of benefits or will you continue to see that the benefits on the back end that you've been seeing on the company?

Speaker 12

Because it seems like noticeable that a lot of your as I said, your margins and all just on the marketing side continue to improve.

Speaker 1

Yes, Neil. I mean, I don't think we're going to see much more improvement. I think it's for us, it's more about risk aversion, right? And having our barrels and molecules go to different bigger markets downstream. So we have a lot of oil that goes to the Gulf Coast in Corpus and is exported.

Speaker 1

We now have a good amount of oil going to Houston feed refineries there. So I think we've kind of grown up as a company in terms of marketing and very clearly mistakes were made 5, 6, 7 years ago when the Permian got tight. And we're just not looking to make those mistakes again. So with our size and scale, we're going to be contributing to oil pipes, contributing to new gas pipes. We've made some investments in gathers and processors and many midstream investments throughout the years here that have, 1, made our shareholders money on the investment side, but 2, protected us on the commercial side.

Speaker 1

So I'd expect that trend to continue as we get bigger.

Speaker 12

That, Caj, you're saying you'll continue to contract more of those longer term marketing contracts then?

Speaker 1

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.

Speaker 1

Okay.

Speaker 12

And then just quickly on project size, you all continue to do a fantastic job, not only that you have larger projects, let's call it on average 6, 4 well pads, things on that nature, but you seem to have the flexibility that the larger that a lot time the majors don't on those projects. Will that continue to be sort of the standard for you all going forward on these larger projects where and you'll maintain that flexibility or maybe you could just hit on that briefly?

Speaker 1

Yes. I mean that you can go on for hours about that. I mean that ties to 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're going to have to make sure we maintain that gritty, quick, fast moving, adaptive culture to a larger asset base.

Speaker 1

I'm fully confident that we have the exec team and employee base at both the 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 $250,000,000 $300,000,000 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. And Neil, as we built this company over

Speaker 2

the last 10 years, we've always maintained a couple of constants. One is the fact we keep a real flat organization and we keep a non siloed organization as well too. And the only way that you can grow an organization and maintain that effectively is to have an unreasonable level of trust. And as we encourage our the Endeavor employees to come over, we're going to be demonstrating this high level of trust because it's going to be a very important part of our evolving culture as a much larger company. But those two things will stay the same, flat organization, no silos.

Speaker 12

Look forward to the new assets guys. Thanks so much.

Speaker 2

Thanks, Neil. Thanks, Neil.

Operator

Thank you. Please standby for our next question. Our next question comes from the line of Derrick Whitfield of Stifel. Your line is now open.

Speaker 13

Thanks. Good morning all and congrats on another solid print.

Speaker 2

Thank you, Derrick.

Speaker 13

This is my first question. I wanted to focus on the second request from the FTC at a high level. Our research indicates that most of the larger transactions have received that. Is that consistent with how you're thinking about it?

Speaker 1

Yes, that's consistent.

Speaker 13

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?

Speaker 10

Yes, Derek. We followed up this year with in Q1 with 3 additional Upper Spraberry completions, kind of following up the success that we had in the North Martin area with that first test. And we really liked the initial results from those wells. And I think that from a cost perspective, we're seeing those costs be pretty competitive. And I think we'll probably look at adding that development to subsequent developments in the future.

Speaker 1

I think Phil is up to top of that, Derek. 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 and the full scale development only extends the duration of what we can do here in the Midland Basin.

Speaker 13

Agree. Very helpful. Thanks for your time.

Speaker 2

Thanks, Terry.

Operator

Thank you. Please standby for our next question. Our next question comes from the line of Paul Cheng of Scotiabank. Your line is now open.

Speaker 6

Thank you. Good morning, guys. Good morning, Paul. Sharpless that in your presentation, you have an interesting statement say on the ESG you intend to eventually invest in income generating projects that are expected to more directly offset remaining SCOOP 1 emission. Can you elaborate a little bit more in terms of how big is the kind of investment?

Speaker 6

Are you expecting that become a new division or that a new business for you? Or that is really is going to be pretty small scale and we shouldn't pay overly too much attention on that? That's the first question. The second question is, interestingly that the E and P producer, no one really talking much about AI, but their service provider, NICE number Jay, they start to brag about, say, how AI is going to drive their revenue and is going to allow productivities of the well productivity. So just curious that is Diamondback, you guys have been always do a lot on the technology.

Speaker 6

Have you passed on the AI application? And whether that you see that going to be meaningfully change your EUR or your well productivity?

Speaker 2

Well, the first emphasis on AI has been not the generative 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 it's yet to be determined. But it's one of those things that we're trying to be fast followers on. This is an arena of our industry that's moving incredibly fast.

Speaker 2

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. In case this first question was income generating tech to offset that?

Speaker 1

Yes. I mean, we have a subsidiary snake company called Cottonmouth Ventures that's kind of our new ventures snake, I'll call it. But it's not a huge business today. I think one of the more exciting projects we're working on is with our Verde Clean Fuels partnership where we are in the scoping phase of building a plant, a gasoline plant in the basin that's going to be tapped into one of the pipelines that we are a participant in. That plant will convert 35,000,000 cubic feet a day of gas, natural gas, lean gas into 3,000 barrels a day of gasoline.

Speaker 1

So that I think fits our motto of if we can contribute molecules and expertise to a project, not just capital, but the other things to drive value, we're going to look at it. I would say that project might FID by the end of this year and be up and running in a couple of years and that might be a good little off take for $35,000,000 a day of gas and if it works, going to

Speaker 2

build more of them. Paul, when you look at a capital program, it's going to spend between $4,000,000,000 $5,000,000,000 a year on a pro form a basis. The percent of that that we're going to allocate to income generating projects is probably pretty small. And in an individual sense, it will probably have a larger impact, but I wouldn't expect it to move up to the noticeable level at a company that's spending between $4,000,000,000 $5,000,000,000 a year.

Speaker 6

Thank you.

Speaker 2

Thanks, Paul.

Operator

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

Speaker 14

Hey, just wanted to touch base on sort of activity, cadence this year. It looks like you guys had kind of 89 first quarter completions, all in the Midland, but that's a pretty healthy percentage, about 32% of your full year budget on completions. Is there some anticipation that maybe some slowdown as the year goes and just seem like a quicker pace than I expected here in the Q1?

Speaker 1

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 some completions into Q1. Q1 looks a little high relative. I think generally you can think about that 70 to 80 overall completions 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 or to drill the same number of wells.

Speaker 1

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.

Speaker 14

Okay. That's helpful color. And then just shifting over to asset sales. You obviously talked a little about sort of when the Endeavor deal closes, maybe moving some midstream assets into your Deep Blue JV and also a drop down to Viper. Outside of some of the Endeavor related asset sales, is there anything else that you guys are sort of working on?

Speaker 14

You talked about raising cash for just from free cash flow here over the next handful of months until the deal closes. But just trying to get a sense if you guys are looking at other asset sales in the interim?

Speaker 1

Yes, not many. We sold a piece of our Viper ownership in the Q1 and that put another $450,000,000 of cash on the balance sheet. I think I go back to when we structured this deal, we certainly did 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.

Speaker 1

And we're going to be patient post close. I think I do think those assets make sense in other hands, but it's got to be the right value.

Speaker 14

Okay. That's helpful. And then just wanted to ask about your production kind of severance tax here. You're going to be guiding to kind of 7% of revenue. It's kind of come in below that the last handful of quarters closer to 5% to 6%.

Speaker 14

Just wanted to see what was kind of going on there? Maybe that was kind of anomalous in the last handful of quarters and is 7% the right number going forward?

Speaker 1

Yes. It was just higher than that before that, 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.

Speaker 6

Okay. Thank you.

Speaker 1

Thanks, Leo.

Operator

Thank you. This concludes the question and answer session. I would now like to hand the call back over to Travis Stice.

Speaker 2

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

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.

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Earnings Conference Call
Diamondback Energy Q1 2024
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