Vital Energy, Inc. (NYSE:VTLE) Q1 2024 Earnings Call Transcript

Vital Energy, Inc. (NYSE:VTLE) Q1 2024 Earnings Call Transcript May 9, 2024

Vital Energy, Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day, ladies and gentlemen, and welcome to Vital Energy’s First Quarter 2024 Earnings Conference Call. My name is John and I will be your conference operator for today. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. As a reminder, this conference is being recorded for replay purposes. It is now my pleasure to introduce to you Mr. Ron Hagood, Vice President of Investor Relations for the company. Please go ahead.

Ron Hagood: Thank you, and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer; Bryan Lemmerman, Executive Vice President and Chief Financial Officer; Katie Hill, Senior Vice President and Chief Operating Officer; as well as additional members of our management team. During today’s call, we will be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts and assumptions are intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Our actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we’ll be making reference to non-GAAP financial measures.

Reconciliations to GAAP financial measures are included in the press release and presentation we issued yesterday afternoon. The press release and presentation can be accessed on our website at www.vitalenergy.com. I’ll now turn the call over to Jason Pigott, President and Chief Executive Officer.

Jason Pigott: Good morning and thank you for joining us today. First quarter results were solid as we achieved record production, exceeded adjusted free cash flow expectations, and delivered outstanding operational execution across our leasehold, again demonstrating our ability to create additional value on acquired acreage. We’ve integrated our 2023 acquisitions and we are working to optimize operations to lower capital, reduce operational costs and enhance productivity. We have already recognized significant gains on our properties versus what we underwrote, and we will continue to focus on creating additional value. As a company, we are highly focused on development that will both extend our inventory and reduce our breakevens.

I’d like to highlight three examples of ways that we are accomplishing this. To start, we recently completed a 20 well package of 15,000 foot wells in Western Glasscock on leases that we acquired in 2019 and 2021. Notably, seven of the 20 wells target the Wolfcamp C and D horizons, to which we did not assign value at the time of the acquisitions. The Wolfcamp C wells are our first modern test of this horizon in the area and are currently not included in our publicly stated inventory. The initial results are very encouraging with just a couple weeks of flowback. The entire package was brought online ahead of schedule and is a significant contributor to our production outperformance for the quarter. Next, from our Southern Delaware position, we’re observing strong production results from the assets we acquired.

Highlighted in our investor deck, the Teller wells are from the Forge acquisition and the Niedermeyer wells are from Tall City. The Teller wells Vital Energy’s first horseshoe shaped wells are designed to optimize productivity and reduce breakeven cost on smaller leases. These wells, paired with our high intensity completion techniques, are outperforming offsetting industry wells. Third, the success of the Teller wells gave us confidence to expand the use of this innovative design in the Midland Basin. In Upton County, we drilled three horseshoe wells averaging 13,900 feet of lateral length instead of six short lateral wells. This markedly improved our capital and operational efficiencies. More significantly, we expect to apply this concept to 84 short lateral wells that are in our public inventory, saving as much as $140 million in capital and reducing the average breakeven of these combined wells by $20 per barrel.

As a company, we’re pursuing multiple paths to reduce breakevens and extend inventory. We are improving productivity by extending lateral lengths, pumping high intensity completions, testing and proving up new horizons, implementing a wide array of new technologies, acquiring new assets, improving base operations and so much more. We’ve increased our average well productivity by 35% since 2019, and nearly 95% of our oil production comes from assets we acquired in the past five years. We have been consistent in our strategy to create value by building depth and quality of inventory, while also improving our financial structure and generating free cash flow. I’ll now turn the call over to Katie for an operational update.

Katie Hill: Thank you, Jason. First quarter production exceeded expectations, driven primarily by the outperformance of our twenty-well package in Western Glasscock and a three-well package in the Delaware Basin. Western Glasscock package was a full-DSU development consisting of 20 15,000-foot laterals targeting four horizons. This is the largest package Vital has ever developed and our team did an incredible job in safely executing ahead of schedule. In this package, completions operations spanned three months, utilized two crews and achieved a 10% efficiency improvement over our previous development in the area. On average, these wells began producing oil 19 days ahead of schedule. As of mid-April, all wells are producing with gross oil production from the package currently beating peak expectations by 15%.

We are particularly encouraged by the performance of the two Wolfcamp C wells drilled as productivity appraisal test. The early results are promising. Since our current public inventory does not include Wolfcamp C, positive outcomes here could significantly extend our inventory life and enhance its quality, leveraging organic appraisal within our existing footprint. The first quarter marked our first complete quarter managing the three assets we acquired last November. These assets are now fully integrated both operationally and administratively. When acquiring properties, we unlock value by decreasing well cost and enhancing productivity compared to prior operators. Since our initial acquisition in Southern Delaware in mid-year 2023, we’ve reduced the well cost from $12 million to $10.5 million for a 10,000-foot lateral by improving well design, enhancing operational efficiencies and leveraging lower service costs due to increased scale.

Moreover, the productivity of the two Delaware packages we’ve completed is approximately 45% higher than comparable industry wells adjacent to our acreage due to our optimized development, spacing and completion design. Of the two completed Delaware packages, one was acquired with the forge assets in mid-2023. They had drilled a two-well package of horseshoe wells in the Teller Unit that we subsequently completed and brought online. Between capital efficiency, completion design and development strategy, we are lowering breakevens on our Southern Delaware inventory by $5 to $10 a barrel. We have successfully transferred the horseshoe well design to our Midland position and have drilled three long lateral horseshoe wells in Upton County. This converted what would have been six 6,500 foot laterals into three extended laterals averaging close to 14,000 feet of lateral length per well.

We are currently completing these wells and the economics are extremely compelling. Development is less capitally intensive and more efficient, reducing expected break evens on the package to $45 per barrel. Preliminary impact to our total inventory converts 84 stated locations to 42 extended laterals, reducing break evens by an average of $20 a barrel. In addition to the inventory enhancement and capital efficiency work completed since close, our integration of the producing assets is also beating plan. In Q1 we exceeded production expectations averaging 124,700 BOE per day and 58,500 barrels of oil per day. We delivered 20 new wells ahead of schedule and anticipate bringing online roughly 60% of our planned 2024 wells by mid-year. Thanks to this accelerated schedule, we expect higher production rates in the first half of the year while maintaining our full year oil guidance of 55,000 to 59,000 barrels of oil per day.

We’ve already identified several opportunities to improve operating cost on our new Delaware position. In the first quarter, we spotted inefficiencies in the chemical usage program carried over from the preceding operators, along with outsized water production driven by improper well design and targeting. These two impacts caused higher operating costs in a limited area of our leasehold. We are temporarily shutting in the wells that are not meeting our profitability requirements, which will result in a reduction in both total and per unit LOE, starting in the second quarter. The shut in wells were forecasted to produce 400 net barrels of oil per day throughout the remainder of the year. This reduction in volume has been accounted for in our second quarter and reaffirmed annual production ranges.

Permanent solutions will be implemented that will further drive down LOE in the second half of the year, including expanding the chemical optimization program, using our consolidated operating footprint to centralize surface infrastructure and treating equipment, and further leveraging the shared water gathering system for new wells coming online. We are encouraged by the speed and effectiveness with which we’ve been able to integrate new assets and the first quarter results speak to the strength of our acquisition strategy. We are continuing to focus on opportunities to further improve both quality and quantity of available inventory, increase effectiveness of operating expenses and enhance free cash flow generation. I will now turn the call over to Bryan.

Bryan Lemmerman: Thank you, Katie. In the first quarter, we delivered solid financial results, generating cash flows from operating activities of $159 million and adjusted free cash flow of $43 million, driven by higher-than-expected production and lower capital investments. Lower capital in the first quarter was largely timing related and our full year guidance is unchanged at $750 million to $850 million. Continue to be focused on further strengthening our balance sheet, we made great progress on this front in the first quarter, executing two transactions in the bond market that extended maturities and redeemed higher rate debt to reduce interest expense. In March, we issued $800 million of senior unsecured notes at an interest rate of 7.875% compared to around 10% just six months prior.

Due to strong demand for the notes, we subsequently issued another $200 million at just under 7.7%. Utilize these proceeds of the issuance to fully redeem our 10.125% notes due 2028 and to redeem a portion of our 9.75% interest notes due 2030. These opportunistic moves will save us $11 million annually and we now have no term maturities until 2029. Additionally, as part of our regular semi-annual redetermination process for our RBL, our banks increased our elected commitment to $1.35 billion from $1.25 billion and we added an additional bank to the facility. We consistently use hedging to reduce commodity price volatility, ensure we can deliver strong returns with our drilling program and generate cash to reduce debt and reduce our leverage ratio.

Hedging is an integral part of delivering on this commitment. For the year, we are 97% hedged on our anticipated oil production at around $75 per barrel. This produces a very consistent cash flow profile, insulating us from risk associated with lower prices. Net debt to consolidated EBITDAX ratio is currently 1.13x. Our ratio rose slightly as a result of our new debt issuance and redemption of 2028 and 2030 notes, due to debt issuance cost and redeeming the notes at a premium to their par value. We have significantly improved our capital structure since mid-2023. Capital efficiency benefits from our successful integration of acquisitions are driving sustainable free cash flow generation. We’re focused on paying down debt, reducing interest expense, and targeting smart accretive acquisition that builds scale and strengthen our business.

Operator, please open the line for questions.

Operator: Thank you. We will now begin our question-and-answer session. [Operator Instructions] Thank you. The first question comes from the line of Neal Dingmann from Truist Securities. Please go ahead.

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Q&A Session

Neal Dingmann: Good morning all. Nice quarter. Jason, my first question maybe for you or Katie on Slide 7 on the latest presentation. Specifically, I like on that slide where you talk about the optimized development, you highlight the spacing, completion design, all these things that have seen the improved results. I’m just wondering, could you talk about now – how has that changed? What is now that you consider the most effective type of spacing and completion both in the Midland and Delaware versus, let’s say, even last year?

Katie Hill: Good morning, Neal. This is Katie. There’s a few pieces of this that we’re pretty excited about. I think the first is that we’ve up spaced compared to some of the previous development plans. You can see in the productivity results that that’s really well supported. But the other piece of the Delaware story is that we’ve been able to drive down capital costs really effectively in the first six to nine months of operating. So we reduced well costs for a 10,000 foot lateral by about 15% already. And together, between that and the up spacing is certainly having a really strong profitability impact on the Delaware inventory. We also are continuing to test some of the completion design in the area and I think that we’ll be able to see results of that across 2024. That’ll influence the 2025 plan as well, but a promising results so far from the Delaware acreage.

Neal Dingmann: That’s great to hear. Go ahead, Jason.

Jason Pigott: Well, I think you also had Midland in your question. I think for Midland, we’re just part of what we’re working through right now is just the co-development. We’ve talked about these new zones both last quarter and this quarter, as Katie mentioned in her commentary, we have the wine rack for the Western Glasscock development. There’s a new zone in there, the C, that is a new test for us that wasn’t underwritten. So when we think about Midland, we’re really working through how do we co-develop these new zones that we’re finding with the existing inventory that we have. And so that’s something that we’re going to continue to optimize into 2025.

Neal Dingmann: Will you bake that into the inventory at some point that those additional zones?

Jason Pigott: Yes. I mean, we talked about some last quarter and then the C zones again, they look really good, but they have just two weeks of production. It’s the first test with this kind of new higher intensity design. So – and they’re very, very promising. And those C zones are one of the contributors to our outperformance of that Western Glasscock package.

Neal Dingmann: Okay. Then just lastly on capital allocation, Jason, for you or Bryan, well, we show in our estimates that free cash flow continues to ramp very nicely, especially second half this year. Will the almost entire focus continue to be debt repayment or could you talk about, I mean, are there acquisitions you’ve already seen that you would try to slip in there maybe what thoughts to do with the capital?

Bryan Lemmerman: Sure. This is Bryan. I would say, absent any acquisition opportunities, it will definitely go towards debt paydown. On the M&A front, it’s been a slow first half of the year, but there are numerous packages coming from operators, consolidation operators, et cetera, in the back half of the year. So we’ve got our eyes looking at that stuff and we’ll be focused on it. So that will be somewhat dependent upon what packages come out, how we see those fitting into our portfolio, and whether or not they’re accretive to our business. But we’re definitely looking at those things. But in the absence of any of that, we’ll be continuing to pay down debt.

Jason Pigott: What we’re trying to highlight with this quarter is the impact of the acquisitions we’ve done in the past and what they’re doing for us now. We’re – Katie and team are getting more out of these wells, the new completion techniques, we’re reducing capital cost, we’re finding new zones and so we still think that that is a great use of capital for us when we find the deal that works and fits in our portfolio and expect to see several things kind of come into market the next few months.

Neal Dingmann: Look forward to that, guys. Thank you.

Jason Pigott: Thank you.

Operator: The next question comes from the line of Zach Parham from JPMorgan. Please go ahead.

Zach Parham: Thanks for taking my questions. First, could you talk a little bit more about the opportunity set on the horseshoe wells? You talked about the breakeven on those wells being reduced at $20 per barrel. Going forward, how do you think about those wells slotting into your future inventory plans or future development plans? Do those get moved forward? Just trying to think about how we should think about you developing those going in the future.

Kyle Coldiron: Yes. Zach, thanks for the question. This is Kyle Coldiron. So I think ultimately we think about this [indiscernible] wells as another tool in our toolbox that allows us to strategically unlock acreage that perhaps wasn’t available to us before. In this case, you can see that development could have been 6,000 foot laterals, which ultimately is not the most capitally efficient way to develop. Our ability to drill these as almost 14,000 foot laterals with this horseshoe shaped design really drives a ton of capital efficiency into the program. And as you mentioned, the break evens dropping by $20 a barrel is really incredible. The team is looking at where do we deploy this opportunity or this tool in our toolbox going forward. We already have wells towards the back end of this year and early next year that we’re planning on drilling as horseshoe laterals in the Delaware Basin. So it’s something that we’re going to put to work right away.

Jason Pigott: I’d say too, we’ve got these wells that we have improved the economics on. We don’t talk about wells that aren’t in our inventory, that this technology will now move or have the ability to move into our inventory in the future. So it’s both a win for reducing cost or breakevens on wells in our inventory and then creating new inventory that we haven’t counted before.

Zach Parham: Thanks. And then, Jason, maybe following up on some of your earlier comments, you talked about the early success of those Wolfcamp C wells. And I know it’s early on, but if the Wolfcamp C does prove to be successful on that Glasscock pad, what’s the potential impact to inventory? And maybe could you remind us how much inventory you’ve already booked in the Wolfcamp D and the spacing that you’ve assumed for that inventory versus what you drilled on this latest Glasscock pad.

Kyle Coldiron: Zach, this is Kyle again. So to your answer on the Wolfcamp C, we think it could unlock up to 70 locations over there in our Western Glasscock acreage. So it’s obviously a big add for us. Like Jason said, we’re very encouraged by what we see so far, but we’re only just a few weeks into our flowback period. On the Wolfcamp D, we did book our locations there at five wells per section, which is what we drilled this 20 well package at. The results so far, again, have been encouraging. It’s early on these wells, both the Wolfcamp C and D had a lot of pressure during drill out, and in fact, free float up 5.5 casing to start for a number of weeks before we ultimately put them on ESP. So strong bottom hole pressure, strong results so far. We’re encouraged with what we see.

Zach Parham: Thanks. Really appreciate the color.

Jason Pigott: Thanks, Zach.

Operator: The next question comes from the line of Derrick Whitfield from Stifel. Please go ahead.

Derrick Whitfield: Good morning, all, and congrats on a strong quarter and operational update.

Jason Pigott: Thanks, Derrick.

Derrick Whitfield: Leaning in on the 20 well package in Western Glasscock. Could you speak to the actions that led to the faster than expected oil cut and how you’ve accounted for the production response in your Q2 guide? It’s clearly inflecting higher, shown on Page 6, but expected to roll over as the chart indicates.

Katie Hill: Good morning, Derrick. I think there’s a couple pieces here to hit on. So the first is there’s really strong execution by the team across all phases. This is the largest package that we developed at Vital and really excited by the team’s ability to deliver at or faster than planned cycle time. We started drilling on this package mid-year last year. We were completing really Q4 of last year, and across all the teams, a handover between disciplines was better than plan. We were able to get the wells online earlier and then really, to speak to Kyle’s point earlier, really good performance on the C and D helped support cutting oil before plan. So there’s a couple of pieces of both day one being sooner than planned and then getting to oil cut sooner as well.

That supported the Q1 outperformance. In terms of how that influences the full year, we are not reforecasting yet this package until the wells start to turn over. It’s really just too soon. There’s enough with the C and D test that we want to get better data support before we start to build that in. I think that the key part is, it has accelerated volume from later in the year. And so we now expect the first half of the year to be heavier weighting from a volume standpoint on our dailies.

Derrick Whitfield: Terrific. And Katie, perhaps staying with you just on the higher LOE expenses, could you elaborate on your near and medium term objectives that you would like to implement to lower drive LOE, lower.

Katie Hill: You bet. So, LOE in Q1, I think, is a reflection of the team getting these assets integrated and really quickly trying to understand where there’s some operating cost efficiencies. The two that so far we’re tackling and making progress on in Q2 is around chemical costs and around saltwater disposal costs in the Delaware. So there’s a small subset of wells that have effectively flat water production with declining oil, so increasing water cut over time. Those seem to have turned over early in Q1, and so had some opportunity for us to shut in and make sure that we’re only producing profitable wells. Those came from one of the assets that we bought late last year and were drilled across some lineaments in the area.

I think we’ve got good subsurface control that that would not be our development plan, but is now from a producing well set, something that we’re managing on the LOE side. For chemicals, I think I’m really encouraged by the opportunity that we have in front of us this year. The way that these assets were previously operated, there really wasn’t much consolidation or shared cost and infrastructure support from a treating standpoint. So the high 2S area in the Delaware, we’re continuing to focus on how do we improve the efficiency of our chemical program, how do we reduce the costs associated with it, and then how do we better leverage our scale with these assets that are right fault onto each other to more effectively treat and get everything to sales.

Derrick Whitfield: Terrific. Great update, guys.

Jason Pigott: Thanks, Eric.

Operator: The next question comes from the line of Tim Rezvan from KeyBanc Capital Markets. Please go ahead.

Tim Rezvan: Good morning, folks, and thank you for taking my question. I wanted to ask – I don’t know if it’s more for Katie or Jason, but can you provide an update on where you stand with base production optimization on the recently acquired assets? I know it takes some time to get all the tech in place and work to optimize production. I know that’s sort of a critical part of the value proposition. So just any color on that now that you have a full quarter under your belt.

Jason Pigott: We’re continuing to evolve our base optimization tools in the Midland. So I think there’s been a great expansion of that into Southern Midland as we picked up the Driftwood and some of the Henry acreage that has really been focused on ESP wells. And we’re starting to transition that over to the Delaware. At this stage, I would frame it as we’ve completed a lot of the technical expertise and sort of support from the Midland team. They’ve expanded over into the Delaware. They’re leading a lot of our Delaware operations. And so I think we’re taking advantage of a lot of the knowledge and the technical ability from our group. We are not yet in a spot that we’ve fully deployed any of the hardware that would support some of the machine learning and AI tools that we’ve talked about before.

That’ll really take most of 2024 to be able to effectively complete across the Delaware side. So I think there’s quite a bit of opportunity still in leveraging our base optimization toolkit.

Tim Rezvan: Okay. That’s great. That’s great. And then, just as a follow-up, some Midland Basin peers over the last couple of years have been reporting really strong Dean results. You’ve seen them in Martin County and farther north. Where is – is that something that’s on your radar as you look to kind of fully develop the rest of your Midland inventory? Just kind of curious what your thoughts are on that interval. Thank you.

Kyle Coldiron: This is Kyle again. So the Dean has been a great interval for us up in our Howard County acreage as we developed up there, essentially, the Dean sits between the Lower Spraberry and the Wolfcamp A. And so there were times where we would target the Dean explicitly, and other times where we would essentially hit the boundaries between the Dean and the Wolfcamp A or the Dean in Lower Spraberry. We know that Dean was a huge contributor to the outperformance we saw on those Howard County assets. So we took a full advantage of it where it was available to us. And then, as you’ve seen in other parts of the basin, on other acquisitions that we purchased, we are always looking for upside zones that we can test and appraise and add inventory to. We’ve demonstrated that in Howard County and Western Glasscock and South Upton and on the Delaware. It’s a part of our acquisition and value unlocking model.

Tim Rezvan: Okay, thank you.

Operator: The next question comes from the line of Hanwen Chang from Wells Fargo. Please go ahead.

Hanwen Chang: Thanks for taking my questions. I want to follow up on the development of the horseshoe wells and the potential upside to inventory and lowering your breakevens. Are there any specific areas or producing zones in the Midland Basin or the Delaware Basin. That could disproportionately benefit from it? Thank you.

Jason Pigott: When we look at the opportunity set across the assets, we probably see a two-thirds weighting to the Midland Basin side just in terms of our footprint and having a greater opportunity set because of the size of our footprint on the Midland side. But what we’re really excited about is that we have now demonstrated that this opportunity can be done on the Delaware side and the Midland side, which really unlocks the opportunity for us across our portfolio.

Bryan Lemmerman: Yes, I don’t think it’s so much basin weighted as your acreage footprint weighted. And just where is a zone or a set of wells trapped? Because you’ve got development on either side. But that could be again, an opportunity for us as we’re looking to do bolt-ons and things like that as we’re kind of testing this technology and testing longer laterals compared to a lot of our peers.

Hanwen Chang: Thank you. Could you provide some colors on your outlook for gas price differentials in the second half of 2024? Thank you.

Jason Pigott: Yes. From a gas price standpoint, we’re definitely looking at a strengthening specifically in the basin. We are expecting some additional capacity with the Matterhorn Express Pipeline to come online later in the year in the third quarter, that’s going to add another 2.5 Bcf a day of capacity to the basin. The last few months has been hampered with not only tight capacity, but on and off maintenance, some of the existing brownfield and greenfield projects that have already been put into place earlier last year. And so getting through this period of time until the Matterhorn Express Pipeline comes online is going to be tight. But we are expecting a rise as soon as the next quarter.

Hanwen Chang: Thanks, guys.

Jason Pigott: Thank you.

Operator: The next question comes from the line of Geoff Jay from Daniel Energy Partners. Please go ahead.

Geoff Jay: Hi guys. My question is really about the cadence of CapEx this year. It looks like it changed a bit from your expectations last quarter. Obviously you spent less than you thought Q1, and it looks like CapEx is going to crest in Q2. And I’m just wondering what that is are you pulling some things forward? Is it purely a function of sort of the increased efficiencies you guys have seen?

Katie Hill: Good morning. I appreciate on Slide 9, I think there’s some good visuals to help support this. But I appreciate your point about Q2. So a lot of the movement that we’re seeing in the first half of the year is timing related, small movement between Q1 and Q2. But over the first half we plan to stay flat. It’s less reflective of capital reduction in Q1 and more just movement into Q2. And then, as you’ll notice, in the second half of the year, we have some opportunity to continue to moderate capital spend with a spot crew in the fourth quarter. We’ll use that to ensure that we’re hitting our full year plan.

Geoff Jay: Okay, great. And then around the horseshoe wells, I was just wondering, I guess my understanding is the real savings is sort of having the needs for vertical casing. Are there other savings associated with these wells that maybe I’m not aware of?

Jason Pigott: Yes, I think you’re thinking about it correctly. It’s all the things associated with the wellhead, the pad, the vertical portion of the well, ESPs, when the wells go on production effectively, it’s cutting those costs in half. And so your ability to spend more time drilling productive rock in the lateral and spending your dollars there, as opposed to spending dollars to get to that point, that’s where the real, true savings comes from.

Geoff Jay: Excellent. Hey, that’s all for me. Thanks, guys.

Jason Pigott: Thank you.

Operator: The next question comes from the line of Paul Diamond from Citi. Please go ahead.

Paul Diamond: All right. Thank you. Good morning, all. Thanks for taking my call. Just got a quick one. Staying on the horseshoe wells, can you talk a bit about decline rates, performance relative to standard wells, and anything you’re seeing that differentiates these versus standard lateral?

Bryan Lemmerman: Yes. So if you look at Slide 7, one thing that we wanted to make sure and highlight here is that the teller wells or horseshoe wells that are drilled in a very similar pattern to what we drilled the Allison wells on the Midland basin side. You can see from the production versus time profile on the bottom right that those wells are performing very well relative to industry benchmarks in the area. So that’s just one example of how these wells can perform. When we look at the opportunity set, when we think about our design, we have always taken a more conservative approach to spacing. As we come into these assets, we space a little bit wider than industry peers have in the past, and we think that that is a big driver of our outperformance and our well results in the area.

[Indiscernible] and they are spaced in our wider spacing pattern. So ultimately, we do not anticipate seeing any kind of degradation or differential performance that’s negative as a result of the horseshoe. We think of them as being as efficient at draining the reservoir as a straight long lateral would be. The benefit really comes from the saved capital that you get by not drilling six wells and only drilling three effectively.

Paul Diamond: Understood. And just a quick follow-up on kind of quarterly capital spending. There’s some optionality in Q4, just how does that and what drives that? Is that going to be, I mean, versus what drives that versus how to set up into 2025? I know it’s a bit early to talk about that, but is that more of a function of what you want to see this year, or is it more of a function of how to market next?

Katie Hill: This is really an opportunity for us to continue to optimize development throughout the year. So we’re really excited about the work so far in the Delaware, but where we will see capital efficiencies throughout 2024 that can help support maintaining that spot crew later in the year. We’re really using that to help make sure that we stay where we want to be on total spend in 2024 and moderating that with getting into 2025 in a sustainable way.

Paul Diamond: Understood. Thanks for the clarity. I’ll leave it there.

Operator: Next question comes from the line of Gregg Brody from Bank of America. Please go ahead.

Gregg Brody: Hey, guys, appreciate all the details on these horseshoe wells. Obviously, everyone’s really interested in it. You gave a split of how much opportunity there is to sort of leverage this technology based on Midland versus Delaware. Do you have a cumulative number, how many wells that you could convert that are in inventory and out of inventory?

Bryan Lemmerman: Yes. So you can see on Slide 8 on the bottom bullet, we talk about within our previously public stated inventory, 84 of those wells have this opportunity. So effectively it becomes 42. It is a reduction in the count of inventory. But as Jason said in his comments, it’s $140 million of capital saved for effectively recovering the same resource as he would have with those 84 wells. The other thing to think about, and we’ll update this when we come up with our updated inventory counts is that there are now wells that because of increased capital efficiency will be pulled into our public inventory that previously weren’t there, making up for the effectively lost 42 laterals that we’re talking about. So we view this as a positive all around. It high grades our inventory. It improves breakevens by a dramatic amount. And ultimately our inventory counts will stay flat or even go up as a result.

Gregg Brody: Is that where the two-thirds, one-third Midland Delaware came from? That’s how we should think about it that total 84?

Jason Pigott: Yes. So the two-thirds, one-third is really is talking about where the opportunity set is and as Jason and I said earlier it’s really a function of how big is your footprint and how many opportunities are there based upon the way our acreage is laid out. And that– and so the 84 to 42 is reflective of that kind of two-thirds, one-three split that we talked about.

Gregg Brody: Got it. I guess the question is, why not do this with some of your core inventory? Is there an opportunity to go longer? What’s the physical limit that you think that you have degradation in performance?

Jason Pigott: So to date, we’ve drilled wells 15,000, and even just above the industry is continuing to extend lateral links. It’s obviously one of the largest drivers of capital efficiency that’s available. We are certainly thinking about that open to that possibility. These wells that we drilled on the Allison package were near 15,000 feet themselves. So we will continue to push lateral lengths to the optimum limit, driving capital efficiency, improving capital efficiency, and getting all that we can out of these wells.

Gregg Brody: Do you think there’s a time where we could actually see you drill, take your 10,000 foot laterals and try to do a U-turn there with two wells like that?

Jason Pigott: If the team is always thinking about creative opportunities to do something like that, there have been situations where we’ve been locked in by with a land position where we’ve considered those types of creative opportunities, but it’s just something that we have to evaluate on a case by case basis.

Bryan Lemmerman: And let’s say, I mean, you need to consider the risk, too, and that much capital being invested in any one well, but again this is our first shot at it so I think there’s going to be lots of opportunities in the future. And the team again, quickly took a technology from an acquired asset in Delaware Basin and immediately moved it to the new assets in the Midland Basin. So again it’s great execution. They did this on their first try, so really proud of the team but there’s – we’re trying to highlight today there’s just lots of potential for us in the future as we take technology and take it from one acquired asset to another, and just really kind of build this one vital energy culture that’s embracing technology and trying to take the best techniques from all the acquisitions and drive, ultimately corporate performance.

Gregg Brody: So just as I look at the data set you have here, you have two wells from the tower unit, and it looks like 240 days of data. You’re saying for the Midland you’ll have similar performance. How much data do you have there in terms of time and maybe just contextually, how much other data is there – is around the industry that gives you the confidence that this is repeatable throughout wherever you drill?

Jason Pigott: On the Midland side we have successfully drilled and cemented those wells, and we are in the middle of our completion operations and everything is going well, going according to plan. In terms of industry data we’re aware of 43 wells, including these, that have used this horseshoe shape. And we have not seen any kind of production degradation associated with the shape with that type of well plant.

Gregg Brody: Got it. I appreciate that. One last question for you. Usually you get asked about M&A. Obviously, horseshoe wells has been dominant today. What’s your sense of what’s out there and the opportunity set just as you look at it today?

Jason Pigott: I think there’s still a pretty good pipeline of opportunities that we see. Some of them have data rooms out there, some we expect to come. I think there’s several. But, as a result of these large corporate deals, we could see some assets hit the market from other public companies, which will be new and haven’t been a lot of those here recently, versus just privates that are selling. So, see a good pipeline for us. It’s still something that we’re very interested in. As you, again, as we tried to highlight with these quarterly results, we’ve been really good at being able to drive out cost, find new zones, implement new technology on acquired assets. These, Allison Wells [ph] were things that we acquired from the Henry team.

So we immediately took, again, a technique from, one acquired company and took it to assets acquired from another one. So I think there’s lots of opportunity there. What we’ve done a really great job, I think, of, is just squeezing more out of these assets after we’ve acquired them. And so we still think that’s an important part of our portfolio. But we’re trying also to build inventory organically in case some of these acquisitions don’t go in our favor or we’re not successful. This year, we’re extending inventory through technology and finding new zones. And so we’ll have a great year, whether we do acquisitions or not. But it’s still something that’s important to us as a company.

Gregg Brody: Thanks for all the time, guys, and then appreciate all the color.

Jason Pigott: Thank you.

Operator: The next question comes from the line of Brian Velie from Capital One Securities. Please go ahead.

Brian Velie: Good morning, everyone. Thanks for taking my question. Just one more on M&A while we’re at it here. As you look at future possibilities, should we think about your current trading multiples, free cash flow yields as metrics that any future deals would have to be accretive on for you to transact? Or those guidelines, or how do you think about that in terms of deals that you go after?

Jason Pigott: Great question. Yes, I think with the transactions we accomplished last year, we got the balance sheet where we want it. I think going forward you’ll see any transaction that we do will need to be accretive to shareholders on virtually every metric. I mean sometimes that’s hard to catch every single one of them. But that will be our focus is to make sure that the acquisitions this year are creative to all metrics for shareholders and are protective of the balance sheet going forward. So, we believe we can do that through all the tools we’ve used in the past for acquisitions. And that is the focus.

Brian Velie: Perfect. Thank you very much. That’s very helpful.

Operator: Thank you. As there are no further questions at the queue this time, this concludes our Q&A session. I would like to turn the call over back to Ron Hagood for brief closing remarks.

Ron Hagood: Thank you for joining us this morning. We appreciate your interest in Vital Energy. And this concludes today’s call.

Operator: Ladies and gentlemen, this concludes today’s conference call. Thank you for your participation. You may now disconnect.