Diamondback Energy Inc (FANG) — Q2 2025 Earnings Call Transcript

Thank you, Briana. Good morning, and welcome to Diamondback Energy's Second Quarter 2025 Conference Call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on our website. Representing Diamondback today are Kaes Van't Hof, CEO; Danny Wesson, COO; and Jere Thompson, CFO. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Kaes.

Great. Thank you, Adam, and good morning, everyone. Thanks for taking the time to listen to our earnings call. We're in our conference room in Midland, Texas, with no air conditioning and truly valuing the importance of American Energy this morning without air conditioning in this office. So we'll get it started. I hope you read our letter and investor presentation and release last night, and we're going to go straight into Q&A.

I apologize for the air conditioning situation. I hope you have a few fans because it can get quite warm in Midland during summer. Yes, I hope this isn't indicative of issues, Kaes, what are your thoughts on cost reduction at the company since air conditioning is quite essential? Yes. However, I want to shift topics a bit. Kaes, I'd like to address this directly. There has been a lot of discussion about consolidation in the industry, especially from some of your larger peers who have mentioned the advantages they have gained from synergies in past deals. Could you share your perspective on the consolidation strategy in the Permian, FANG's position within the industry, and your general thoughts on mergers and acquisitions?

Yes. I mean good question, Arun. I think, first and foremost, we have to remind everybody that our job is to maximize shareholder value. And I think we've done that very successfully at Diamondback over the last 15 years in what I think investors would agree has been an extremely tough tape. So generating alpha and creating value in a tough market is what we've done. And we've done that via an acquire and exploit strategy in the Permian, where we've been able to cut costs and execute better than anybody else on the assets we acquired. The most recent example is Endeavor, which almost doubled the size of the company, and to investors, it looked like we didn't skip a beat. We've got a young team executing at the highest level in the prime of all of our careers, and we're only getting better quarter in, quarter out as proven with today's results. So the way we see it is we should naturally be the consolidator of choice, and until someone else can prove they can do it better than us and we lose our edge, then we should be the consolidator of choice. That's what I spend my time thinking about. I think it's interesting to see larger peers get bigger in the basin and talk about M&A. But I think we're singularly focused on continuing to execute at the highest level, and we exhibited that today.

Great. My follow-up, you announced some noncore non-op Delaware Basin property sales in the quarter. I was wondering if you could maybe give us some thoughts on the broader asset sale target of $1.5 billion, in particular, maybe an update on the Endeavor water drop?

Yes. So we announced a $1.5 billion noncore asset sale target with the Double Eagle transaction that closed early in the second quarter. We're a small way through it with 2 small sales, non-op sale and the BANGL sale, getting us to about $250 million, $260 million of cash in the door coming in this quarter. The other 2 big pieces of noncore assets that we see as on the block are our EPIC pipeline stake, which we've increased to 27.5% of that pipeline. It's a pretty valuable pipe now with the last remaining expansion out of the basin. The other piece being our Endeavor Water assets, which we feel make a ton of sense in our Deep Blue JV. We're working on both of those projects imminently. It's hard for us to put too much detail when we don't have binding documents done, but we are working on binding documents for both of those. So expect to have a very detailed update for our shareholders at some point in the next quarter or 2 on hitting that target and getting that cash in the door.

I'm wondering if you can contextualize a bit more Kaes, the opportunity to address some of the production downtime and focus on the production tail. Can you quantify the size of that opportunity that you think can be addressed over the next couple of years?

Yes, I'll give it a high level. This commentary is kind of new to us, right? If you look back at the development of Shale or Diamondback, it used to be that 80% of our spend was on capital and 20% on operational costs. Now, capital is about 65% of our spend, and operational costs are about 35%. We think it’s going to become a more balanced 50-50. There are a lot of things to work on, on the tail of our production, some of which came over from ideas the Endeavor team had, and we're seeing some interesting results on some of our - we call them HTL jobs. If we can get a lot of little wins on the production side of the business, reduce downtime by 1% here, 1% there, do some of these workover jobs that bring some of the old wells back to life, so to speak, that kind of adds up over a very large program. I don’t know, Danny or Chad, do you want to add anything that we've been doing on that and our focus on that, but that’s the highlights.

Yes. This year, we've significantly intensified our workover program. The budget for non-DC&E spend is larger than in previous years, allowing us to allocate more capital to enhance older wells and maximize their output. We've observed some promising results from this initiative. While we don't have any quantifiable data at the moment, we plan to continue collecting information to discuss these results in the future. Some wells that are 3 to 5 years old have been affected by nearby fracking operations. When we intervene by cleaning them and applying certain chemical optimizations, we've seen production improve by as much as 100% on lower output wells, which is very encouraging.

And maybe, Kaes, just following up on just Arun's comments with some of the noncore sales targeted for perhaps the back half of this year. How do you think about managing that cash coming in the door versus some of your debt targets by the end of the year and some shareholder returns?

Yes. I mean I think getting the cash in the door will help pay down our 2-year term loan that we took out with the Double Eagle deal. That's really our big piece of debt that's due in 2027. We have another note due in 2026, but it's at 3% interest. We'll just build cash to be able to take that out and enjoy that 3% interest for the last year that we have it. I think overall, we have some nice tailwinds here in Q3, a little lower CapEx, strong production, and a significant cash tax tailwind with the one Big Beautiful Bill flowing through. That should create significantly more free cash in Q3, some of which can be used to pay down debt. A combination of that plus noncore asset sales should get us into a really good spot where we could potentially lean in on repurchases should things weaken further.

If you can provide an update to the stop light analogy, it sounds like you still think we're at yellow here, but your perspective on the macro and how that informs your activity decisions. There's some bifurcation in the industry about how players want to approach the back half of the year, and you guys have definitely taken a more guarded position. So talk about the top-down view that informs how you're approaching your activity.

Yes, Neil, good question. I think the stop light has revealed itself last quarter, and I don't think it's going anywhere anytime soon. Unfortunately, we still think we're in a yellow situation. But if you go back to May 5, when we released Q1 earnings, there was probably still more uncertainty than there is today. We said we're prepared to go red if needed back then, and I think we're still ready to do that. It seems that the double whammy of a demand and supply shock is anticipated. There are still firms that see oil prices much lower next year. I don't know if I believe that they'll be that low, but it's certainly hard for me to get extremely bullish today, and that's why I think 2025 for us is a year of debt reduction and share count reduction, waiting for that spring to coil when commodity prices do rally at some point.

And regarding the M&A last quarter, I believe your message indicated that Double Eagle provided an opportunity for you to pause since you had consolidated many of the higher quality positions in the Permian and aimed to remain a pure-play. Is that still your perspective, or do you have a different approach so far this year?

No. That's still our base case. I mean I think at Diamondback, we're very fortunate to have the inventory quality and depth that we have today. There certainly is more consolidation to happen in the Permian. I think for Diamondback, we need to be a lot more selective than we’ve been in the past because there's not a lot of inventory out there that competes for capital in our top quartile. That's why we were so aggressive on Double Eagle. Unfortunately, the timing wasn't great as it closed right before Liberation Day, but we're happy about the assets we acquired there—the sub-40 breakeven inventory we acquired there. We really don't see much sub-40 breakeven inventory in the hands of potential targets. So we have to be a lot more selective. Now Viper, on the other hand, can talk about that on the Viper call, has had a great year consolidating and building that business. Diamondback is going to be more patient, and Viper is going to keep growing its business.

You all seem to find ways of squeezing out more efficiency every quarter, getting drilled days down, etc. How many more things can you do? I mean drilling days can't go to zero, but do you have a line of sight on how you can continue to improve efficiencies? Or are you getting to a point where you're at a more optimal level?

Scott, yes, thanks for the question. I'd love to talk about the ops guys and the nice reprieve and some of the stuff we talked about in these calls. So I think the drilling guys have done a phenomenal job of really chasing that leading-edge well and getting to that leading-edge well more consistently. We've hit these 4- and 5-day wells that we talk about sporadically throughout quarters in the past, but they're getting to where they're hitting them more consistently. That’s the real efficiency driver—how do we become more consistent in chasing those record wells? We continue to push lateral lengths longer. We put in our letter highlighted a well that we drilled 30-plus thousand feet. I think it was a record well in Texas. We continue to push the limit on drilling capability, and I don't know where the threshold limit will take us. We're consistently eliminating downtime and chasing that top-tier well in every section. On the completion side, we're doing the same thing, chasing that final frac efficiency, and you see that in the results of the aggregate lateral footage per day, pushing 4,000 feet per day on the SimulFRAC crews. I think there are still opportunities to improve efficiency in the SimulFRAC world, where we can grow that efficiency 15% to 20% more. We aren't done chasing those efficiency improvements—not yet.

That's good to hear. You all had a bit stronger gas production this quarter. It sounds like it came from more gas capture and processing improvements. Can you tell us how much more of that is yet to come? And is that something where your midstream partners are investing more capital to improve it? Are you doing things differently with them or give us a little bit of color behind what drove that? How much more can we see from that perspective?

Yes, Scott, I mean, the backstory here is a business that we invested in, WTG, West Texas Gas sold to Energy Transfer a year ago. WTG has been spending a lot of capital, adding plants and capacity to a very high-growth area, Martin County, of which we were the largest producer on the system. With that growth, there were some growing pains and power issues that took both WTG and Energy Transfer some time to work through. But now we've started to see those plants operate a lot more efficiently. The big increase was to our liquids yields. We've added 33,000 barrels a day of NGLs to our production in Q2 over Q1, like the snap of a finger. That's very positive for our long-term cash flow and makes production in that area more economic. So big wins from the Energy Transfer team. That's why we put them in the letter. We continue to do things on our side too—our flaring was down 75 basis points or 100 basis points in the second quarter versus the first quarter, which ties back to the gas capture side. We are trying to get all 3 molecules generating as much revenue as possible for Diamondback here.

One of the majors has recently highlighted some pretty ambitious targets for dramatically improving oil recovery rates in the Permian. Just your thoughts on that side of the equation. Obviously, you've done a fantastic job on the cost side. Any insights into what you're looking at regarding recovery rates?

Yes. I mean, listen, we're always trying to drill better wells, right? We added an interesting slide this quarter, Slide 9 about our development strategy, where we talk about how many zones per section, how many wells per section we're drilling. It's well known that Diamondback is a cost leader in the basin, but it’s also less understood that we’re a technical leader in the basin, maximizing both returns and resource. With our cost structure, we're able to put in another couple of wells in every section. If we're getting the same production per well than peers that are spacing wider, then we're naturally generating better returns and more recoveries for our shareholders. Your comments on ambitious goals are amazing. I'm not going to knock technology developments in the basin because Diamondback is going to be a beneficiary of that. Overall, I think it's positive, so I hope it all works. We’re going to continue looking to drill the best well possible, which I think we’ve done over the last 10 years. Some technology will help us alongside our low-cost structure over the next 10 years.

And then just one housekeeping item for me. Was there production associated with the Delaware Basin divestiture?

Yes, there was a little bit, John. A little bit over 1,000 barrels a day of net oil production—a little bit more on the BOEs—but we just added it to the guidance going into the back half of the year.

Wondering how you're viewing the cost of capital advantage right now for Viper vs FANG and how this shapes capital allocation decisions at the parent level. It looks like both stocks are yielding around 10% free cash right now at $70, but I know you guys look at it in more detail.

Yes, I mean, listen, I think there's some technical things going on at Viper right now. We're trying to get a public merger closed, and that limits some of the actions we can take regarding repurchases. But it also brings in a different kind of investor for the period of time between sign and close. I look forward to the window opening at the Viper level and being able to repurchase some shares aggressively because I think it's a very unique investment in the space. Another note, from a debt cost to capital perspective, Viper just did its first investment-grade deal that priced basically at or inside some very large peers, showing there's a lot of investor support for that business. I think there are some temporary equity issues that still need to be resolved.

Okay. Great. Then from a macro perspective, can you talk about typical cycle times right now in the Permian, considering efficiency gains, larger pad sizes, longer laterals? I'm trying to understand how long it takes to start seeing the production impact from some of the reduced activity in rig and frac that we've seen in the basin.

Yes. If you think about it—you could look at Slide 9 in our deck, actually, and we highlight some of the average wells per section from ourselves and some peers. If you look at kind of 15 to 25-ish wells per section, call it 20, at an average of 10 days a well, you're looking at about 200 days of drilling time to cycle off that pad. So somewhere in the neighborhood of 6 to 9 months is a typical pad development or DSU development that may be broken down into multiple pads. These projects are not as short-cycle as I think they're often referred to as because to properly develop the whole DSU does take quite a bit of time. The completion process following that much lateral footage could take a month or 2 of completion timing. I like to think of these as kind of 12-month cycles on a full DSU timeframe. There’s a lot of flexibility in there if you see volatility and you're not bringing in rigs at certain times or frac crews at certain times, but these are not a short cycle as I think we regard them in the public markets.

Yes, but from a macro perspective, you can't take 60 rigs out of the Permian in 3 months and 20 to 30 frac spreads out of the Permian in 3 months and not see—eventually see a production response. I think we’re doubling down on that commentary. I think we're going to see U.S. production roll a bit at these prices. It is taking a little longer than we all expected. Maybe that was the price reprieve we had in June, but there's just too much activity being taken out of the U.S. basins.

I had a question on your excess DUC balance. How big will that be at the end of the year? What's the strategy kind of going into '26 considering the excess stocks? If oil is weak, would you pull it down because there's less incremental spend per well? Or would you like to maintain it for some quick to respond barrels in case oil moves higher?

Yes, good question, Scott. The DUC balance has gotten a little more attention than we expected. But we're completing 500 to 550 wells a year. It's good to have 250 to 300 in the hopper, especially with this large pad development waiting for completions. We'd be comfortable going as low as high 100s to 200 DUCs, but would still like to maintain flexibility in that range. This year, we're completing efficiencies and well costs are low. We've decided to maintain that flexibility later through this year, which gives us 2 options: If things are weak, we can slow down a bit; if things are strong, we can accelerate pretty quickly. We've built a lot of flexibility into our entire plan, which is why our results are always consistent and best-in-class. Our investors expect us to do that.

Got it. On cash taxes, you realized a good bit of savings this year following the one Big Beautiful Bill. I think some of that is kind of a makeup in the second half. How do you think about '26 and beyond from a cash tax rate perspective?

Yes, Scott. In 2026, we expect the cash tax rate to kind of level out at 18% to 20% of pretax income. When we look at 2025, we're expecting a 15% to 18% cash tax rate, down from roughly 19% to 22%. So a reduction of about $300 million in total. About $200 million of this is a one-time benefit. Two components of that $200 million in 2025 are primarily related to the accelerated recovery of remaining unamortized R&E expenditures that were capitalized over the last 3 years, with the remainder related to the full expensing of depreciable equipment, primarily related to LWE we acquired earlier this year in the Double Eagle transaction.

I want to ask about the development mix. If I look at the development mix provided in the back of the slide, there's an increase in other zones and also Wolfcamp B. At the same time, you're able to maintain performance, if not better performance, which is quite impressive. How do you see development mix evolving over time? Can you talk about what you're seeing in the other zone development performance-wise vs. the traditional zones?

Yes, Betty, that’s a great question. We've focused on delineating some of these upside zones over the past couple of years. On the slide you're talking about in the back of the deck, you can see that mix changing over time. I expect that to increase over time as we delineate and rationalize where the highest returning areas are for those zones in the Upper Spraberry and the Barnett and other deeper zones like the Wolfcamp B.

I think also on top of that, Endeavor acreage probably had some better Wolfcamp D than our legacy acreage, along with better overall Wolfcamp B further south in the Midland Basin. That’s driving it a little bit. Adding these zones into the mix and not seeing productivity degradation as a company is a very impressive feat.

I think the two big value drivers for Diamondback are: one, finding an in-basin egress solution for our natural gas molecules; and two, lowering what we view as probably the most inflationary piece of our cash cost structure on a go-forward basis, which is electricity costs found within LOE. When you PV those two items, that’s where you're seeing the greatest benefit to Diamondback. If we could lock in a behind-the-meter solution for power generation, we’re not going to go out and build anything on spec here. We’ve continued to look at opportunities for advancing power generation within the basin. It’s just taken a little longer. There are likely opportunities over the next 5 to 10 years, but we are being patient.

I think there are some other small improvements we can make on our existing asset base; we don't do large power trades. Just using the example today, right, our NGL yield and gas capture increased in Martin County because the gas plants had a better power solution in place. That shows that there are power issues throughout the basin.

There's been a lot of industry discussion about your comments from the 1Q reporting cycle, both supportive and nonsupportive. How would you characterize the support from your peers out of the basin and the pushback within the basin?

I would say most of the industry either reached out and supported what we were saying at the time. I think there's been pushback, and I'd also say most investors agree with what we said in Q1. It’s interesting to hear the pushback come from some in the industry, but that’s just natural competition, and we welcome that. What we said in terms of activity has been spot on—15% of the rigs are out of the Permian in Q2, and that number has been exceeded. I just think we know what's going on in the Permian and in the U.S. It's inevitable that so much activity being taken out of the plan will impact production declines because of the natural high-decline nature of this business. I didn't mean to be doom and gloom, but we are highlighting how sensitive shale has become to prices compared to 3 or 4 years ago.

Shifting to operations, I wanted to lean in on Scott's earlier question on your 4-day spud to TD record. If you were to compare the segment performance of the 4-day to the average of the 8, where do you see the greatest differences in performance? Do most of your wells fall within a day or so of the 8-day average?

Yes. I think the 4-day well is in the top decile of our performance for sure. We have 30-something wells that we’ve spud in less than 5 days, not just in this quarter, but in company history. Most of our wells are within a day or 2 of the 8-day average. The drilling team has done a phenomenal job of consistently delivering that top-tier well, and they're getting better at it. The real story in efficiency going forward is how do we continue to grab that 4- and 5-day well?

Kaes, your letter warns of 25% casing cost inflation from tariffs. Can you remind us if you have any of that locked in? How much of that inflation is baked into your guidance?

We've taken about 15% inflation since Liberation Day was announced on casing. We anticipate a little bit more of that to come. We have a procurement agreement with a casing supplier, but the pricing kind of floats with regards to market pricing formulaically. So we're not necessarily locked into casing supplies, except on a quarterly basis. If the market increases because of tariffs, we will follow along with that.

It will be interesting to see how the push from a lower rig count and lower steel use in the industry compares to steel costs. It seems steel costs are winning today, but we’ll see what happens over the next year or so.

As a follow-up, it looks like lower OpEx was beneficial to your 2Q financials. Can you walk us through the moving parts of your changes to guidance in LOE and GP&T?

Yes, I'll take GPT quickly. The GPT moves between whether we’re taking in kind or not taking in kind on the gas side. We’ve flipped some contracts to take in kind, and that number goes up. On the LOE side, generally, the teams had a good first half of the year. We expect run-rate LOE to be somewhere in the kind of $5.60 to $5.80 range on a normalized basis. We’ve generally been surprised to see some of those smaller synergies in the field between Endeavor and Diamondback teams kind of come through on the LOE side. Long term, should we get a water sale done to our JV partner at Deep Blue, LOE will go slightly up, but there are lots of things going on with LOE work. Not all LOE is lower turn; some can be very high return.

It’s kind of a follow-up to Neil's question. I'm curious about the calculus around lowering activity. We've had companies tell us that with service cost declines and efficiency gains, returns even in lower-tier acres are pretty strong. Obviously, you have super high-quality acreage and low cost. What metric are you looking at to make the decision to lower even here?

I wouldn't say we're lowering much from here. We actually increased well count; drilled wells are up 30 wells this quarter versus last. Completed wells are down a little, but that's just due to volumes outperforming. While there were concerns 3 months ago that we were heading lower, the calls for $50 and $40 oil were ramping, and we were prepared to reduce further if needed. The price pressures have eased over the last 3 months, and we decided that we can hold production here at 490. All our investors have been supportive of our decision to make the right capital allocation. I flip that question back to you to ask the higher-cost operators why they're maintaining activity levels when the lowest-cost operator is doing what's right, waiting for a better day. Not at all. That excuse is not allowed inside Diamondback. Everyone knows that efficiency cannot be used as an excuse for maintaining activity. We change things every day; the Diamondback activity plan is like a duck on a pond. The pond is calm and the duck appears calm above the water, but below the water, there's a lot going on. We change drilling rigs and frac spreads every year and adjust activity levels within quarters to ensure flawless execution, which takes a lot of work.

Just looking at your hedge book for 2026, it looks quite exposed on the oil side. Does that align with your outlook for oil prices in '26?

No, it’s really just patience on adding puts. We’ve been buying puts, but 2026 puts are currently expensive. We plan to slowly build that position. We’re well protected in the second half of this year and are starting to build for '26. We do not want to pay too much per barrel for the deferred premium puts. I think the base dividend is protected today at $37-$38 a barrel at maintenance CapEx. We're due for a dividend review at the beginning of next year. As the balance sheet improves and noncore asset sales proceed, the need to hedge reduces or we could lower the hedge price to pay less for the puts.

That makes sense. My second question is on operations post the water sale. The Endeavor asset will effectively flow out into a bigger system. Does that create opportunities to improve your own operations regarding water, i.e., be able to move more water to the right places or being able to move more water to different places that you currently don't have access to?

Not in a meaningful way. I think we’ve set up the deals with our partners at Deep Blue to enable us to simulFRAC or use 2 simulFRACs across our position. I don’t think much of that changes. I do think getting a deal done and bringing these two systems together will create some synergies, but you probably won't see it at the Diamondback level.

It sounds like you guys are holding up well. One question for me, Kaes, can you give us an update on what the green light conditions would be in your metaphor to reaccelerate? Have there been changes in light of a lot of dynamics you've been discussing here today?

Yes, that’s a good question. We are closer to the second half of the year when a perceived supply wave is coming our way. We’ll see what actually happens. OPEC has unwound their initial cuts and is moving to a world where instead of discussing who is cheating on their quota, they’re discussing who can hit their quota. That's a huge shift in messaging. If OPEC production hangs in there and you see U.S. production start to struggle, the curve will need to react. The curve reacting is our biggest signal. The tone over the last 4 months has been more companies running lower price scenarios compared to the traditional $60, $70 and $80 scenarios. When you start seeing changes in U.S. production coupled with OPEC barrels, it's about seeing what a normalized market looks like.

Kaes, I wonder if I could ask a different question to the growth question. It seems with your current perspective, it sounds like there's a case for growth that makes sense now. Is that a change of stance from Travis to you?

I wouldn't say it's a change of stance, Doug. We're closer to discussing it again. If you consider why U.S. shale or the big publics went to an X growth strategy, it's coming out of 2020 when we went through a near-extinction event as an industry. Shareholders said it was time for returns. Companies decided to exert capital discipline, which has been a positive outcome for our shareholders. I don’t think we are talking about spending all our dollars to grow the business. But I do think that at some point, there will be a market that calls for growth from companies like Diamondback, and we’ll be there to answer that call cautiously and efficiently.

My follow-up relates to that because not everyone can grow because of inventory. You've previously talked about 8 to 10 years of Tier 1 inventory. But considering practical development, what would today's actual consumption rate of your inventory be?

It's a bit higher than that, Doug. We're fortunate that a lot of these secondary zones are pretty economic today before we have to get to true Tier 2 or Tier 3 zones. We need to focus on pad-level breakevens because you're really developing half a section or a section at a time, which is where we achieve the rate of return.

I wanted to ask about the red light scenario; a lot of focus on the green light. What causes you to consider slowing down? Obviously, oil price is a key factor, but what else would you consider?

Yes, it's really just oil price, Leo. If we're printing a month in the low 50s for a full month, then we have to discuss it. We've cut a lot of CapEx out of the plan to generate more free cash and shrink the balance sheet and share count. I'm not getting ahead of other operators who are maintaining activity despite weak prices; we’ve already done our part.

Just looking at your targeted debt levels. For Venom, you guys announced a new target of $1.5 billion in net debt at which point you would increase returns to shareholders. Can you provide any similar methodology at the FANG level?

At the FANG level, having more flexibility is important. Right now, we’re committed to at least 50% of free cash going to equity, a combination of the base dividend and share repurchases. If there's share price weakness, that number should go higher than 50%. If things are strong, it should stay around 50%. We have all the CapEx associated with the business, so it’s hard to put an exact number on where we’d like debt. We’d like to maintain lower debt but also have cash on the balance sheet for flexibility when cycles turn against us.

I’m proud of all the analysts for still going a full hour despite the temperature rising 20 degrees in that hour in this office. Thank you for your interest in Diamondback, and we look forward to discussing any questions anyone might have offline. Thank you.