Viper Energy, Inc.

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 speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 1-1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1-1 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to Adam Lawless, VP of Investor Relations. Please go ahead.

Thank you, Jules. Good morning, and welcome to Diamondback Energy's first quarter 2024 conference call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, Chairman and CEO, Case Mantoff, President and CFO, and Danny Wesson, COO. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance, and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.

Well, now I'll turn the call over to 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 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?

Thank you. At this time, we will conduct the question and answer session. As a reminder, to ask a question, you will need to press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Neil Mehta of Goldman Sachs. Your line is now open.

Yeah, 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. Can you spend more time on that? And as it relates to that, how do you think about the timing of de-bottlenecking Permian gas?

Well, from a macro perspective, I think we've been pretty clear that we're going 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 six million barrels a day that we produce out here. Natural gas is, right now, being almost treated like a waste product. When Matterhorn comes on this fall, we'll see some of that reversed. Case, you want to give them some description of what we're doing with the rest of the gas? Yeah, Neil.

I mean, 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 on 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 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 pass 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.

Yeah, thanks. Thanks both. And then the second is capital efficiency. You talk 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. And then also what are the next steps in terms of driving your cost structure lower as we think about efficiency of fleet?

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 I think we averaged 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.

Thanks, Travis.

Thanks, Neal.

Thank you. Please stand by for our next question. Our next question comes from the line of Arun Jayaram of JP Morgan Securities LLC. Your line is now open.

Yeah, good morning. 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 in D, C, and E costs in the Midland Basin to that 600 to 650 range. Maybe a follow-up to Neil's question, but where are you seeing kind of leading-edge, you know, kind of costs today in the Midland Basin as you continue to push those lateral links a bit longer?

Yeah, around this case, you know, 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 to 650 a foot in the Midland Basin. As you know, 90% of our capital is being allocated to that basin. With those costs trending in the right direction, I think on a real-time basis, closer to 600 you know, we feel really, really good about our plan this year as well as, you know, carrying that momentum into a Q4 close of the Endeavor deal and into 2025. You know, 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.

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

Yeah, 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 Romeo area, Northern Reese County, that's going to be Very good. You know, I think generally, you know, with large pad development, you're going to see pockets of development in the Delaware rather than, you know, consistent development because we want to go over there and complete multiple wells, multiple pads in a row and keep that capital efficiency high, you know, versus the Midland Basin where, you know, three or four simul-track crews are going to be running at all times.

Great. Thanks a lot. Thanks, Aaron.

Our next question comes from the line of David Dekelbaum of TD Cohen. Your line is now open.

Morning, Travis case and team. Thanks for your time today.

Good morning. Okay.

So maybe, maybe there's questions for both of you guys, but you know, considering the positioning a bit early with the debt that you raised earlier this month now, the expectation that the deal will close 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, you know, considering the market's changed a bit, especially around the cash consideration portion?

Yeah, I mean, I think what's changed is just timing, right? I think the projects we see as non-core asset sales or, you know, the asset sales to, you It's 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. Our strategy to execute on those trades has not changed. It's just been pushed out to the right. 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. I think that just means we have to pony up less cash at close in Q4. We raised the money a couple weeks ago because we were preparing to potentially close the deal as early as today. Unfortunately, the deal's been pushed out due to regulatory review, but we had to be ready to fund the deal, and that's where we were. 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 quarters.

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

Yeah, well, I mean, we're facing them right now, egress issues, right? Not on the physical side, but certainly on the price side. 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. I think we see the gas forecast continuing to increase. If you do look back, on 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.

Thanks for your thoughts, guys.

Thanks, Steve.

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

Yeah. Hey, guys. Thanks. I'm just going to stick on the gas theme as well because it is very topical. But it sounds like, and just correct me if I'm wrong, you guys feel good about your development program. on a 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 constraints not being able to get their gas out and potential shut-ins related to that?

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

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?

Yeah, 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 allow 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, you know, this flexibility will allow us to do that. You know, 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. You know, if we see some weakness, we're going to – step in and support the stock. But the longer term, we want to make the nine-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 mid-cycle in the $60 to $70 range. I think we were firmly $60 for a long time. We're probably closer to $70, $20, and $2 or $3 gas. And the combined business, you look at what we have with Endeavor, there's a significant amount of inventory and a lot of NAV accretion, and 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.

Yeah, just to clarify a couple points, just broadly speaking, how much accretion do you all feel Endeavor added? And can you give us a sense of like, you know, when you think about cost of capital and Like, you know, 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?

Yeah, we've always been a little higher than 10. I think an after-tax PV-12 felt like, at 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.

Thanks for that. We stand by for our next question.

Our next question comes from the line of Roger Reed of Wells Fargo Securities. Your line is now open.

Yeah, 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. But if you looked at the underlying improvements you cite, you know, EFRACs over a diesel FRAC, kind of where do you think we are in terms of running through continued efficiencies there as we, you know, 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, you know, post-endeavor, kind of what you see as a you know, maybe a year or two out in terms of continued efficiency gains?

Yeah, good question. You know, we are continuing to drive costs out of the business through our operational plan and execution. You know, on the completion side, a lot of that's going to come in the way of getting these E-Fleets off of generated power and onto some form of grid power where we can recognize a lower, you know, 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 significantly larger portion of the cost of the well than the variable cost. We're getting to a point where the variable costs that we're going to impact are pennies and nickels and not as much the dollars anymore. 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, I give our 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 or merger announcement with Endeavor, we talked about $150 a foot. $100 of that foot was from just simply going to a simulfrac and the other $50 a foot was going to clear fluids. And really, that's what we're doing today. 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.

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

Yeah, I mean, listen, Roger, 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.

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

Thanks, Roger. Thank you. Please stand by for our next question.

Our next question comes from the line of John Freeman of Raymond James. Your line is now open.

Good morning, guys.

Hey, John.

Just following up on these efficiency drivers, obviously in the quarter, the wells that y'all completed, the 101 wells, they were right in line on the lateral length of what y'all's guidance was for the full year of around that 11,700 feet. But obviously, y'all point out the 69 wells that y'all drilled in the Midland Basin that were significantly longer than that, over 13,000 a foot. Obviously, first class problem given the capital efficiency you're seeing on these longer laterals. But Should we still use that four-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?

Yeah, 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.

Okay, and then just shifting gears a little bit on the topic of trying to get a sense of like how much y'all are able to do sort of in advance of the Endeavor deal closing. And I know that, you know, in y'all's initial efficiencies that y'all laid out, you know, 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, 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, you know, buying in bulk, things like that? Like, how much of that, if at all, can you do in advance? Or do you just kind of have to sit and kind of wait until the deal closes to kind of get running on that stuff?

Yeah, John, we've got to operate as separate companies until the deal closes. And those things will all come to the benefits of the combined company, but certainly the influence any outcomes until we're closed.

Got it. Thanks, guys. Solid quarter.

Thanks, John.

Thank you. Please stand by for our next question. Our next question comes from the line of Neil Dingman of Truist Securities. Your line is now open.

Good morning, guys. Travis, my question for you, okay, 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, you know, now with the larger size, or I guess, you know, when that closes, what type of benefits or will you continue to see the benefits on the back end that you've been seeing on the company? It seems like noticeable changes. that a lot of your margins and all just on the market side continue to improve?

Yeah, Neil, I don't think we're going to see much more improvement. I think for us it's more about risk aversion 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. We now have a good amount of oil you know, going to Houston feed refineries there. So, you know, I think we've kind of, you know, grown up as a company in terms of marketing and, you know, very clearly, you know, mistakes were made five, six, seven years ago when the Permian got tight. And, you know, we're just not looking to make those mistakes again. So, you know, with our size and scale, we're going to be contributing to, you know, oil pipes, contributing to new gas pipes, We've made some investments in, you know, gatherers and processors and many midstream investments throughout the years here that have, you know, one, made our shareholders money on the investment side, but two, protected us on the commercial side. So I'd expect that trend to continue as we get bigger.

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

Yeah, I think our philosophy is to get our barrels to the most liquid – bigger market and very clearly, you know, selling within Midland or in the Midland market, you know, has not always been the most beneficial to our shareholders. You know, 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, is a, you know, a longterm insurance policy to make sure our barrels move to the right market.

Okay. And then just quickly on, um, Project size, you all continue to do a fantastic job, not only that you have larger projects, let's call it on average six four-well pads, things on that nature, but you seem to have the flexibility that the larger, oftentimes 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 and you'll maintain that flexibility or maybe you could just hit on that briefly?

Yeah, I mean, you could 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 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 at both Diamondback and Endeavor to do that. And, uh, you know, I think these, these big projects, there's a lot of capital being put in the ground before first oil, you know, sometimes upwards of 250, $300 million. But as long as you have the ability to, uh, you know, move crews and rigs within a quarter, within a year, you know, keep hitting numbers, you know, we're going to keep doing that at a, at a larger scale.

And, you know, Neil, as we built this company over the last 10 years, we've, we've always maintained a couple of constants. One is the fact that 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 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 of our evolving culture as a much larger company. But those two things will stay the same. Flat organization, no silos.

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

Thanks, Jim. Thanks, Neal.

Thank you.

Please stand by for our next question. Our next question comes from the line of Derek Woodfield of Stifle.

Your line is open. Thanks.

Good morning, all, and congrats on another solid print. Thank you, Derek. With my first question, I wanted to focus on the second request from the FDC 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?

Yes, that's consistent.

All right, terrific. And then shifting over to OPS, So during the quarter, you completed three additional upper sprayberry 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?

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

You know, I think Phil's off to the top of that, Derek. You know, if you start to add in zones like the Upper Sprayberry, Wolf Camp D, we've got some really good Wolf Camp D tests and some of those same pads. You know, if you start to add those in and you don't see degradation on a corporate basis in terms of, you know, the CUME curves that everyone looks at so closely every year, you know, that's inventory extension issues. you know, in our existing asset base. And, you know, with the combination of us and Endeavor, adding in zones like the Upper Sprayberry, Wolf Camp D, and the full-scale development, you know, only extends the duration of what we can do here in the Midland Basin.

I agree. Very helpful. Thanks for your time.

Thanks, Dirk.

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

Thank you. Good morning, guys. Good morning, Paul. Sharpest, in your presentation, you have an interesting statement on the ESG intent to eventually invest in income-generating projects that are expected to more directly offset remaining Scoop 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 a new business for you, or that it's really 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 EMP producer, no one really talking much about AI, but the service provider, like number J, they start to brag about, say, how AI is going to drive their revenue and is going to allow the improvement of EUR and productivity, of the well productivity. So just curious that is Diamondback, you guys have been always do a lot on the technology. Have you tested on the AI application and whether that you see that going to be meaningfully change your EUR or your wealth productivity?

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 EUR 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. 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, you know, smart algorithms or AI to help us process that information in a more usable and more real-time fashion. His first question was income generating tech to offset that.

We have a subsidiary snake company called Cottonmouth Ventures that's kind of our new ventures snake, I'll call it. It's not a 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 million cubic feet a day of gas, natural gas, lean gas, into 3,000 barrels a day of gasoline. So that, I think, fits our motto of if we can contribute molecules and expertise to a project, you know, not just capital, but the other things to drive value, you know, we're going to look at it. I would say that project, you know, might FID by the end of this year and be up and running in a couple years, and that might be a good little offtake for, you know, $35 million a day of gas. And if it works, we're going to build more of them.

Paul, when you look at a capital program that's going to spend between $4 and $5 billion a year on a pro forma basis, the percent of that that we're going to allocate to income generating projects is probably pretty small. 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 and $5 billion a year.

Thank you.

Thanks Paul.

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

Hey, just wanted to touch base on sort of activity cadence this year. It looks like you guys had kind of 89, you know, 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, you know, as the year goes and, you know, just seem like a quicker pace than I expected here in the first quarter?

Yeah, Leo, a couple things. I think we were having a pretty good end of the year last year in the Q4, and so we pushed some completions into Q1, so 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 one for a period of time over the summer, as well as kind of get down into that 12, 13 rigs, you know, on the drilling side to drill the same number of wells. So, you know, we look at the plan, you know, almost weekly with the planning team, and I think, you know, generally the efficiencies have led to less overall activity, more capital efficiency, and, you know, setting us up well for this potential close here in Q4 with Endeavor.

Okay, now 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, you know, 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. You talked about raising cash for, you know, 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, you know, asset sales in the interim.

Yeah, not many. You know, we sold a piece of our Viper ownership in the first quarter, and that put another $450 million 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 of 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 the last couple 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.

Okay, that's helpful. And then just wanted to ask about your production kind of severance tax here. You've been 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%. 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?

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

Okay, thank you.

Thanks, Leo.

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

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.

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