Vital Energy Inc (VTLE) 2024 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Vital Energy's first-quarter 2024 earnings conference call. My name is John, and I'll be your conference operator for today. (Operator Instructions)

It is now my pleasure to introduce Mr. Ron Hagood, Vice President of Investor Relations for the company. Please go ahead.

Thank you and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer; and Bryan Lemmerman, Executive Vice President and Chief Financial Officer; Kathryn Hill, Senior Vice President and Chief Operating Officer, as well as additional members of our management team.

During today's call, we'll 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 will 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 will now turn the call over to Jason Pigott, President and Chief Executive Officer.

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 have 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 would 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 of 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, but 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 costs 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 horizontal 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 higher-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're 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 will now turn the call over to Katie for an operational update.

Thank you, Jason. First quarter production exceeded expectations, driven primarily by the outperformance of our 20 well package in western Glasscock and a three well package in the Delaware Basin. Western Glasscock package with 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 safely executing ahead of schedule in this package completions operations spend three months utilized two crews and achieved a 10% efficiency improvement over our previous development in the year.

And most of them on 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 expectation by 15%. We are particularly encouraged by the performance of the two Wolfcamp C wells drilled as productivity appraisal tests.

The early results are promising. Since our current public inventory does not include will can't see positive outcomes here could significantly extend our inventory life and enhances 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 costs and enhancing productivity compared to prior operators.

Since our initial acquisition in southern Delaware and midyear 2023, we reduce the well costs from $12 million to $10.5 million or a 10,000-foot lateral by improving all design, enhancing operational efficiencies and leveraging lower service costs due to increased scale.

Moreover, their productivity of 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 designs. The two completed packages one was acquired with the Forest assets in mid 2023.

They had drilled a two-well package of Horseshoe wells and 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 horizontal 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 capital-intensive and more efficient, reducing expected breakevens on the package of $45 per barrel.

Preliminary impact to our total inventory convert 84 stated locations to 42 extended laterals, reducing breakeven 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 have already identified several opportunities to improve operating costs on our new dollar position. In the first quarter, we spudded inefficiencies in the chemical usage program carryover from the preceding operators, along with outsized water production driven by improper well design and targeting these two impacts cause higher operating costs and eliminate 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 centralized service infrastructure and treating equipment and further leveraging the shared water gathering system for new wells coming online.

We're encouraged by the speed and effectiveness with which we've been able to integrate new assets in the first quarter results speak to the strength of our acquisition strategy. We are continuing to focus on opportunities or further improve both quality and quantity of available inventory, increased effectiveness of operating expenses and enhanced free cash flow generation.

I'll now turn the call over to Bryan.

Thank you, Katie. The first quarter, we delivered solid financial results, operating 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.

Our 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% in 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.

If 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.

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 1.13 times. Our ratio rose slightly as a result of our new debt issuance and redemption of 2028 and 2030 notes, due to debt issuance costs 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, focused on paying down debt, reducing interest expense and targeting smart accretive acquisitions that build scale and strengthen our business.

Operator, please open the line for questions.

Thank you. (Operator Instructions) Neal Dingmann, Truist Securities.

Good morning all. Nice quarter. Jonson, my first question, maybe for you or Katie, on slide 7 on the latest presentation. Specifically, like on that slide where you talk about the optimized development. You highlight the spacing and completion design. All these things that I've seen improved results.

I'm just wondering, could you talk about now what you 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?

Again, my name is Katie, there's a few pieces of this that we're pretty excited about. I think the first is that we've outpaced comparatives from the previous development plans. You can see in the productivity results that that's really well supported for the other pieces of our story is that we've been able to drive down capital costs really effectively in the first six months 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 spacing and certainly having a really strong profitability impact on the Delaware inventory, we also are continuing to test them in the completion design in the area. And I think that we'll be able to see results of that across 2024 that will influence the 2025 plan as well, but a promising results so far from the Delaware acreage.

That's great to hear. Go ahead, Jason.

Well, I think you all have 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 had we've talked about these new zones both last quarter and this quarter, as Katy mentioned, in her commentary that we have the wine rack for the Western Glasscock development.

There's a new zone in there that see 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 '25.

Will you bake that into that inventory at some point that those additional zones?

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

Okay. And then just lastly on capital allocation, Jason, for you or Brian? Well, we show in our estimates that the free cash flow continues to ramp very nicely, especially second half this year, will that almost entire focus continues to be debt repayment or on that. Could you talk about I mean, are there acquisitions you've already seen that you had tried to slip in there, maybe what you wanted, what thoughts have to do with it with the capital?

Sure. This is Brian. 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 we'll be focused on it.

So that will be somewhat dependent upon what packages come out, how we 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 Patrick, take the opposite, what we're trying to hunt our mill.

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 are fairly and team are getting more out of these wells, the new completion techniques, we're reducing capital costs, we're finding new zones. And so we still think that that's a great use of capital for us when we find the deal that that works and fits in our portfolio and expect to see several things kind of come on the market the next few months.

Look forward to that guys. Thank you.

Correct.

Zach Parham, JPMorgan.

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 figure out how we should think about you developing those going in the future?

Yes. Zach, thanks for the question. This is Kyle Coldiron. So I think ultimately, we think about this Eastern well 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 capital-efficient way to develop.

Our ability to drill these as almost 14,000 foot laterals with this Horseshoe shaped design, it really drives a ton of capital efficiency into the program. And as you mentioned, the breakevens 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 that we're planning on drilling at Horseshoe laterals in the Delaware Basin. So it's something that we're going to put to work right away.

I'd say too, we've got these wells that we have improved the economics on. We don't talk about wells that are 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, our breakevens on wells in our inventory and then creating new inventory that we have counted before.

Thanks. And then, Jason, maybe following up on some of your earlier comments, you talked about that 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.

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. We're like I 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 B, we did book our locations.

There are five wells per section, which is what we drilled this 20 well package out 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 of 5.5 casing at the 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 at what we see.

Thanks. Really appreciate the color.

Thanks, Zach.

Derrick Whitfield, Stifel.

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

Thanks, Derrick.

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 guidance is clearly inflecting higher shown on page 6, expected the rollover as the chart indicates.

Wonder, I think there's a couple of pieces here to hit on. So the first, the really strong execution by the team across all phases of the largest package that we developed at Vital and really excited by the team's ability to deliver at or faster than planned cycle times.

We started drilling on this package mid-year last year. We were completing really Q4 of last year and across all the teams that handover between disciplines was better than planned. We were able to get the wells online earlier and then really to speak to Carl's point earlier, really good performance on the C and D help support cutting oil before plan.

So there's a couple of pieces of both day one being sooner than planned and getting the oil cuts sooner as well that supported the Q1 outperformance. In terms of how that influences our full year. We are not reforecasting at this package until the well start to turnover. It's really just too soon.

There's enough with the C and D tests that we want to get better data support before we start to build that in. I think that's a 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 a heavier weighting from a volume standpoint on our dailies.

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'd like to implement to lower drive LOE, lower?

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 that to the so far, we're tackling and making progress on in Q2 is around chemical costs and around salt water disposal costs in the Delaware.

So there's a small subset of wells that have effectively flat water production with declining oil and increasing water cut overtime. They seem to have turnover early in Q1. And so it 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 so many mines 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 sites have been 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 costs and infrastructure support from a trading 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 in our right bolt onto each other to more effectively treat and get everything to sales.

Terrific. Great update, guys.

Thank, Eric.

Tim Rezvan, KeyBanc Capital Markets.

Good morning, folks, and thank you for taking my questions from item. I wanted to ask them and I'm just more for Katie or Jason, but can you provide an update on where you stand with base production optimization on the recently acquired assets? And 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.

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've 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 add 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 '24 to be able to effectively complete across the Delaware side so I think there's quite a bit of opportunity still in by leveraging our base optimization toolkit.

Okay. Great. It's great. And then just as a follow-up on some Midland Basin peers, over the last couple of years have been reporting really strong gene results. You've seen them in Martin County and farther north. Where is that something that's on your 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 in that on that interval. Thank you.

This is Kyle. Again. So the Dean has been a great animal for us up in our Howard County acreage as we developed that there essentially being between the Lower Spraberry and Wolfcamp A. And so there were times where we would target Dean explicitly and other times where we would we would essentially hit the boundaries between the dean and the Wolfcamp A or the gain or the Lower Spraberry.

We know the gain was a huge contributor to the outperformance we saw in the South County assets. So we took 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've 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 in western Glasscock and South Upton. And on the Delaware. It's part of our acquisition value unlocking model.

Okay. Thank you.

Hanwen Chang, Wells Fargo.

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

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.

I don't think it's so much basin weighted as your acreage footprint weighted in this plant where whereas a zone a perfect set of wells trapped because we'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.

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

Yes. Part that 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 later that earlier last year. And so getting through this period of time until the Matterhorn Express pipeline comes online, it's going to be tight, but we are expecting a rise as soon as the next quarter.

Thanks, guys.

Thank you.

Geoff Jay, Daniel Energy Partners.

Hi, guys. My question is really about sort of 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 if you are you pulling some things forward? Is it purely a function of sort of the increased efficiencies you guys are seen?

Good morning. I appreciate it on Slide 9. I think there's some good visual to help support those. 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 modest 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.

Okay, great. And then around the Horsham wells, I was just wondering, I guess my understanding is the real savings is sort of having the needs for them vertical casing. Are there other savings associated with these wells? I am again, I'm not aware of.

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, EPSs, when the wells come on production effectively, it's cutting those costs, 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 savings comes from.

Excellent. Hey, that's all for me. Thanks, guys.

Thank you.

Paul diamond, Citi.

Thank you. Good morning and thanks for taking my call. Just a quick one then on the Horseshoe wells, can you talk a bit about the decline rates, for us relative to standard wells, and anythink you're seeing that differential differentiates you versus it was standard lateral?

So if you look at slide 7, one thing that we wanted to make sure and highlight here is that the teller, the teller wells are or she wells that are drilled in a very similar pattern to what we drilled the Allison well as on the Midland Basin side, you can see from the sort of production versus time profile in the bottom right, that those wells are performing very well relative to industry benchmarks in the area.

So that's just a 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 spacing as we come into these assets. We space a little bit wider than the industry peers have in the past.

And we think that that is a big driver of our outperform and our well results in the area we're using the same approach with the new terms 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, the straight long lateral would be.

The benefit really comes from the save capital that you get by not drilling six? Well, we're only drilling three effectively.

Understood. And just a quick follow-up on kind of quarterly capital spending on some optionality in that for just how does that what drives that? Is that going to be I mean versus what drives that versus how it's set up into '25? I know it's very early to talk about that, but is that more of a function of what you want to do this year, or is it more of a function of how to market next?

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 '24, and 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 '24 and moderating not with getting into '25 in a sustainable way.

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

Gregg Brody, Bank of America.

Hey, guys, appreciate all the details on this whole issue of obviously, everyone's really interested in it. You gave you a split of how much opportunity there is for to sort of leverage this technology based on Midland versus Delaware. Do you have a cumulative number, how many wells that you could convert better inventory in inventory net of inventory?

As you can see on slide 8, on the bottom bullet, we talk about within our previously public stated inventory, 84 of those wells of this opportunity. So effectively, it becomes 42. It is a reduction in accounts of inventory. But as Jason said in his comments, it's $140 million of capital save Brent for effectively recovering the same resource that you would have with those eight wells.

The other thing to think about, and we'll then we'll update this when we when we come out with our updated inventory counts is that there are now wells that because of increased capital efficiency, it 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-grade our inventory improves breakevens by a dramatic amount can ultimately our inventory counts will stay flat or even go up as a result.

Is that was a two-thirds, one-third Midland diversion from Petrobras should think about it, the total 84.

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, how many opportunities are there based upon. But the way our acreage is laid out and that in the 84 to 42 is reflective of that kind of two-thirds, one-third split that we talked about.

Got it. I guess the question is why not do this with some of your core inventory? Is there an opportunity to go? Or what is what's the physical limit. You think that that is that you have derogation segregation and performance.

So to date, we've drilled wells 15,000 and even just above the industry is continuing to extend lateral length. That'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, we're 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.

Do you think there's a thought from a time where we could actually see you drill to take your 10,000 foot laterals and tried to do a U-turn there, two wells like that?

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'd consider those types of creative opportunities. But it's just something that we have to evaluate on a case-by-case basis.

And let's say, I mean, you need to consider the risks to and then that much capital being invested in any one. Well, but I guess 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 and Delaware Basin and immediately moved it to the new assets in the Midland Basin.

So see, again, it's great execution, and they did this on their first try, so really proud of the team. But there's like 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 Aqua's acquired asset to another and just really kind of build this one vital energy culture that's embracing technology and trying to do is take the best techniques from all the acquisitions and drive ultimately a corporate performance.

So just as I look at the data set, you have here, you have two wells from the from the tower unit and it look like 240 days of data. If you're saying for the for the Midland, you have similar performance. How much data do you have there in terms of time in terms of time? And maybe just conceptually, like how much other data is there around the industry that you're that gives you the confidence that that this is repeatable throughout ready to drill?

On the business side, we have successfully drilled and submitted 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 shade. And we have not seen any kind of production degradation associated with the shape with that well with that type of well planned.

Got it. I appreciate that. But one last question for you usually get asked about M&A. Obviously, portion was it's been dominant today and what's there's what's your sense of what's out there and your opportunity set, just as you look at it today?

I think there's still a pretty good pipeline of opportunities that we see. Some of them have data rooms out there and some we expect to come. I think there's several let you know, 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 energy that again, as we've tried to highlight with these quarterly results, we've been really good at being able to drive out costs, buying new zones, implement new technology on acquired assets development wells were things that we acquired from the Henry team.

So we immediately took again a technique from one to one acquired company and took it to assets acquired from another one. So I think there's lots of opportunity there where we've done a really great job, I think of as just squeezing more out of these assets front when we after we've acquired them. And so we still think that's an important part of our portfolio, but we 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.

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.

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

Thank you.

Brian Velie, Capital One Securities.

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?

Great question. Yes, I think with the transactions we accomplished last year, we got the balance sheet where we want it. And I think going forward, you'll see any transaction that we do. We'll 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, our accretive to all metrics are shareholders and are protective of the balance sheet going forward. So, we believe we can do that through all the all the tools we've used in the past for acquisitions, and that is the focus.

Perfect. Thank you very much, That’s very helpful.

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

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

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