Q4 2023 Vital Energy Inc Earnings Call

Participants

Kyle Coldiron; VP of Subsurface & Business Development; Vital Energy, Inc.

Paul Diamond; Analyst; Citi

Gregg Brody; Analyst; Bank of America Merrill Lynch

Derrick Whitfield; Analyst; Stifel, Nicolaus & Company, Incorporated

Presentation

Operator

Good day, ladies and gentlemen, and welcome to vital energy Inc's fourth quarter and full year 2023 earnings conference call. My name is Valerie, and I will be your operator for today. At this time, all participants are in a listen only mode. We will be conducting a question and answer session after the financial and operations report. As a reminder, this conference is being recorded for replay purposes.
And it is now my pleasure to introduce Mr. Ron Hagood, Vice President, Investor Relations. You may proceed, sir.

You, and good morning. Joining me today are Jason Pigott President & Chief Executive Officer,Bryan Lemmerman, Executive Vice President & Chief Financial Officer,Katie Hill, Senior Vice President & 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 condition, 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. Press release and presentation can be accessed on our website at w. w. w. dot vital energy.com.
Now I'll turn the call over to Jason Pigott, President and Chief Executive Officer.

Thank you, Ron, and thank you for joining us this morning. 2023 was a great year for BiDil energy as we drove change on multiple fronts throughout the year, we executed on our strategy to build shareholder value, expand our development portfolio, generate free cash flow and strengthen our balance sheet.
In 2023, we achieved record production of 96,600 barrels of oil equivalent per day and oil production of 46,300 barrels per day, an increase of 17% and 22% respectively versus full year 2022 add lower than anticipated capital costs.
12 months, we increased our oil production by approximately 60% for the full year 2023, net income of $695.1 million, adjusted net income of $325 million and cash flows from operating activities of over $811 million, closed six accretive Permian Basin acquisitions for $1.6 billion in cash and stock, adding approximately 88,000 net acres and 465 gross oil weighted locations, 280 of which were announced with the acquisitions, increasing inventory of oil-weighted development locations to more than 10 years at current activity levels, an increase of 85% compared to the beginning of the year.
We exited 2023 with a net debt to consolidated EBITDA ratio of 1.09 times, which was 8% lower than the prior year end for a reduced scope, one greenhouse gas emissions intensity and methane emissions intensity of 38% and 65% respectively, as of year end 2022. Additionally, we were the first Permian operator to receive the third-party trust WELL certification for responsible operations, placing vital energy in the top quartile of US onshore operators.
Our strategic shift to focus on entry into the Delaware Basin and expand the Southern Midland Basin is paying off and the transition process is going extremely well. We are drilling wells faster well, costs are cheaper, and they are more productive than originally anticipated.
Socially, we are transferring knowledge and technology across both basins, making us a stronger operator setting us up for more record-breaking activity in 2024 Turning to 2024, we are entering the year in a position of strength as a result of our work to extend our bond maturities, reduce the amount drawn on the RBL and reduce our total leverage.
We are pleased to confirm our prior guidance adjusted for the recently announced working interest additions of capital investment between $750 million to $850 million with oil production guidance of 55,000 to 59,000 barrels of oil per day and total production of 116.5 to 121.5 barrels of oil equivalent per day.
We plan to generate more than $350 million of adjusted free cash flow at current prices and our cash flow projections are supported by a strong hedge book focus on further paying down debt and reducing our leverage ratio to less than 1.0 times throughout the year.
Strategically, in 2024, we maintained focus on our core principles of generating free cash flow, reducing debt and leverage, expanding our development portfolio, advancing sustainability and integrating digital solutions.
I will now turn the call over to Katie to provide an operational update and integration.

Operationally, we had an extremely successful 2023. We consistently exceeded production expectations throughout the year, delivered capital investments below plan, successfully integrated six asset acquisition and established a core operating position in the Delaware Basin.
Our team has extensive experience onboarding new assets and optimizing development plans as we successfully demonstrated in our Howard County position over the past few years, we've gained experience with the asset we refine spacing, design, completion techniques and production methods the bulk of our 2023 development was in Howard County and the results showcase the success of this integration and optimization process.
New wells and Howard regularly exceeded production expectations and we continue to drive execution efficiencies. In the fourth quarter, we set company records in drilling, delivering a 10,000 foot lateral and 6.5 days, and our record-setting 7,716 drove fee in a day. They also set records in completions during the fourth quarter for daily pumping, our stages per day and average transition times on a pad.
Production processes brought on high value production from wells earlier than modeled as we optimize on sizes to dewater wells more quickly after drill-out and to better recover from offset frac hits our fourth-quarter oil production, driven by outperformance in Howard County and our recently integrated assets in Upton County exceeded the midpoint of our guidance range by 7% or 3,700 barrels per day. Two thirds of the beat was driven by new wells delivering above expectation.
So the driver of our 2023 results has been the optimization of our base production last year. Wells brought online prior to January first exceeded production expectations by 10%. It was accomplished through both process improvement and the continued application of optimization technology is the end result has been faster and more targeted response times and increased mechanical runtimes across the field.
This operating model has proved to be scalable, and we are improving results through integration of the Driftwood in Florida acquisitions that we closed on in early 2023. Production from new wells on the asset is exceeding expectations by 10% on legacy Driftwood and 33% on legacy Ford acreage.
We are early in the process of optimizing base operations on the properties that are already exceeding production expectations on the legacy Forge Asset by 4%. And we've also reduced well costs in the Delaware Basin by 12% versus what was assumed at the time of close through improved cycle time supply chain optimization and well redesign and waving.
Wells more quickly for less capital and with higher productivity than expected at acquisition fees, results have been built into our forward looking forecast reflects continued year-over-year improvements as we onboard new NASA as our teams are evaluating geologic data cost assumptions and production results from our asset and from offset operators.
Based on this work, we have organically added another 185 high return wells to the 280 originally included in our acquisition assumptions in the Midland Basin, we added 65 Spraberry and Wolfcamp locations in Upton County through detailed technical evaluation, so incorporated offset operator results and importantly, a robust dataset acquired from a vertical well, we drilled on our acreage that collected high-quality geologic data.
In the Delaware Basin, we added 120 wells in core development horizons across the position based on results from our recently completed wells and the improved economics from reducing well costs, 12%. And we've since we began operating in the area. In 2024, we remain focused on organically adding low cost inventory through additional technical work and through increased opportunities to bolt on acreage adjacent to our leasehold.
Our capital efficient development plan optimizes activity between the Midland and Delaware Basin. This quarter, we are bringing online several Delaware packages and a 20 well western Glasscock package production data from our recently turned-in-line Delaware wells continues to support our development plans on the Midland Basin.
Western Glasscock package drilling and completion operations have gone very well and five wells are currently flowing back, sir, any wells is promising and the package is already pretty big 3,000 gross barrels per day plan. The remainder of the package will be brought online over the next four to six weeks with peak oil planned for the middle of the second quarter.
I'll now turn the call over to Bryan for a financial update.

Thank you, Katie. During the fourth quarter, we closed three previously announced Permian acquisitions and an additional transaction to increase working interest on a portion of the acquired properties. Thoughtful approach to financing these transactions has significantly strengthened our capital structure. Recently, our bonds were upgraded by Moody's, and our bond yields have improved by around 175 basis points.
2024 budget is designed to generate substantial free cash flow while growing full year average production versus fourth quarter 2023 volumes. Free cash flow is expected to build throughout the year with capital being highest in the first quarter and then coming down throughout the year.
Capital progression is driven by first quarter activity being on higher working interest wells and as more activity moves to the Delaware Basin, the average working interest will lower, resulting in lower quarterly capital spend. We are focused on further strengthening our balance sheet, and we plan to utilize free cash flow to reduce absolute debt and achieve our year end 2024 target debt ratio of 1.0 times.
Debt reduction will be focused on our credit facility and we expect the balance to be zero in the third quarter of the year. We believe we can achieve substantial benefits from utilizing free cash flow to reduce leverage, including lower future interest expense. In early February, we announced a second transaction to acquire additional working interest on some of our recently acquired Permian properties.
Due to the shares issued in this transaction, our NOL carryforwards will likely be subject to three two limitations. Importantly, we have been managing our utilization of intangible drilling credits and estimate that at current pricing and projected activity levels, we will not pay federal cash taxes for at least the next three years.
So I'll now turn the call back over to Jason for closing comments.

Brian, to close, I want to reiterate that BiDil energy is much different company today than we were a year ago. We are much stronger and this would not have been possible without the talented team we have behind us. Operator, I will now turn the call over for questions.

Question and Answer Session

Operator

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

Murielle, nice quarter. Just my first question, maybe both of them are going to be around maybe Slide 9 and First, maybe some of you UK, you said that on both of these, could you maybe start on slide nine, I like where you show about the successful integration of the properties.
And I'm just wondering now that you've done that when you look at both now the mixture of the recently added Delaware as well as the Midland Basin I mean, has that changed? I know you've got the four well, four rig focus this year. Could you maybe talk about how you plan to attack that now this you've got all the assets sort of working together?

Good morning, Neil. This is Katie. We add throughout the year this airplane around, like you said, a four rig program and we're continuing with our strategy, of course, of drilling our best wells next. So as we think about the capital allocation throughout the year, will shift a little bit more heavily into the Delaware in the second half.
There's some really good opportunity as we've as we've closed on the assets and integrated them. We've been able to optimize the plan this year, and we're excited to get some capital deployed in that area. As we think about moving into '25, there's still some really great investment opportunity in the Midland.
So we'll continue with that mix of Midland, Delaware Basin and trying to optimize across the two assets throughout the next couple of years here, I think there's additionally quite a bit of opportunity in the Delaware that we've built into the plan around our production optimization work.
As you mentioned on slide 9, you can see that we've outperformed on base production assumptions early in the Driftwood and Florida assets from early 2023. And as we think about deploying that technology and base optimization work across the three assets we closed in the second half of the year, that will continue to support the 2024 plan and the projections that we have out there. So I think a lot of really good opportunity for us across the TVs and through.

Great good Katie, say. And then just a follow-up, looking actually at slide 7, rates really talks about the additional zones and then you show the sort of cost reductions. I'm just wondering something you had mentioned when you note tackle, I guess, what do you view as sort of the optimal project or optimal pad size? It seems like for even being a smaller operator, you all been able to walk that up and capture some efficiencies. So again, I guess what I'm looking at these two, I'm just wondering like when you co-develop now, you know how bigger projects are optimal and you think makes the most sense for you all.

Kyle Coldiron

I'm Neil. This is Kyle Coldiron. So I think the answer really depends on the area and kind of the stack pay that you have to if you look at our western Glasscock package that we have coming online right now, essentially that's kind of two very large pads that we drilled those 20 wells. And one of the great benefits of that was that we were basically able to park our Halliburton frac crew there. And complete 10 of those wells without ever having to move the fleet. So just the efficiency really skyrockets from those big pads.
As we move over to the Delaware side, we tend to drill a little bit smaller pads kind of in that three to five type of range. And ultimately, a lot of that has to do with just our well spacing assumptions over there and what targets we're hitting. So I think you're adding to your question. It depends on the area. But across the board, we are a continuous improvement culture on our operations team. And we've been able to drive both drilling and completion costs down across both basins. I think as you can see, the materials that we shared today makes sense.

Thanks for the details. Great job, guys.

Operator

Zach Parham, JPMorgan.

Good morning and thanks for taking my question. I guess first, can you talk a little bit about the inventory additions in the Delaware and the Midland? It seems pretty clear you added two additional zones based on some some industry activity around you. Can you detail exactly what you added in the Delaware and and kind of how that fits into the program going forward?

Yes, good morning, Stacy. I'll take a stab, and then I'll hand it over to Kyle. I mean, one of the things that we've done repeatedly is ad inventory. After we've completed acquisitions, you saw it in Howard County when we added the Middle Spraberry in western Glasscock, we added the Wolfcamp D and that's a zone that's being completed today and those large pads we've got out there.
So as you mentioned again, we've added Lower Spraberry and Wolfcamp A in Howard County sorry, the Southern Midland. We took core data that should indicate to us the zones would be good and then we have offset operators that brought those online and confirmed what we saw in the geology.
We would we would develop a little bit differently than some of the offsets were they live wells on top of each other where we would stagger them. So we think there's some upside even to those results that you could see out there. We go to Delaware, that's driven by costs.
And when you reduce well costs from $12 million to $10.5 million, that improves the economics of every well in the field when your production performance is 33% higher. That improves economics of every well out there. So it's, again, improving total returns across all those areas.
And I think the other thing, too, is I mean we've got other zones that we're going to be testing this year. We've got the Wolfcamp C, which we're going to be testing is coming online today in western Glasscock. That's a totally new zone for us that could add future inventory at our future earnings calls.
So we're putting a full court press on testing multiple zones across both the Midland and Delaware to again continue to increase inventory over time, and I'll turn it over to Kyle now he can give you a little more details on what they're doing on the operational front to create these efficiencies and outperformance.

Kyle Coldiron

Is that to your question on the Delaware side specifically, did the intervals or the inventory that we added was across our second Bone Third Bone and Wolfcamp A. And Wolfcamp B, which are core development horizons. So these aren't, you know, New Horizons or anything that we haven't previously previously disclosed but as Jason said, a well.
Ultimately, the improved economics of [1.5] off of your well cost improves all of the inventory and ultimately just provides a lot more opportunity to develop also the well performance has been outstanding so far, as you can see, both from the cume time curve and the IPs that we've highlighted here that from our recent packages that we've turned in line. Well, productivity has been fantastic. And so it just gives us a lot of confidence that we can go and develop cross benches there on the Delaware side.

Thanks. Appreciate the color there. I guess my follow up just on on M&A specifically. I mean, you've done a number of deals in 2023, but just talking about these organic inventory additions.I mean that's two plus years of inventory. How do you think about M&A versus organic additions at this point? Where just kind of M&A fit in in your mind going forward.

Another great question. I think we did amazing work in '23 to continue our transformation as a company. We've talked a lot last year about this transition to small ball which was performing a series of smaller transactions that weren't as competitive one that I think in the larger peers were bidding on things.
And it was it was wildly successful for us again, it was we completed again, almost [$1.6 billion in China of over $1 billion in transactions in '24]. We're switching a little bit more to the Moneyball, which is let's let's spend less testing new zones and get wells not for free, but almost for free. As you think about adding 185 wells in total last year with the acquisitions, again, we brought on 485 wells. And if you divide that by a rate of 80 wells per year, we added six years of inventory last year alone.
And so we're in really good shape. And as I mentioned, we're going to be testing some of these new zones. So I think we can get outsized well additions with less costs. However, we will still be active in the market. There's deals out there today. There's going to be deals in the future, but I would say the bar has been raised for us.
Any deals that we look at, we'll need to and be accretive to us and inventory will need to shop the inventory that we've added this year. So I'd say we're still going to look at it. I mean, there's going to be great opportunities with an Oxy or Diamondback.
They're looking to or endeavor our former endeavor properties that are adjacent to us and can make a lot of sense as those come to the market. So we're going to continue to be active and look at creating scale but I'd say for us, the bar is raised on that, the type of things that we'll look at in 2024.

Great. Thanks for taking my questions.

Operator

Tim Rezvan, KeyBanc Capital Markets.

Good morning, folks. Thanks for taking my question. This may be best for Katy. I know you all are pretty vocal about what you're doing on the technology side to optimize base production. And you gave an update on what's happening at that Driftwood and Forge.
I was wonder if you could give an update on kind of how things stand with their recently acquired assets and maybe when you would get that fully implemented into sort of year your cloud system, what the time line for that would be, thanks.

Good morning, Tim. So I think we would consider that technology implementation to typically come in phases. I think at this stage, we're really excited about the progress we've made on our early '23 acquisitions. So Driftwood, the Southern Midland Basin assets are effectively fully integrated into our operating platform.
We've taken some really strong stats on that first dollar asset and forward, like you mentioned, when we think about the three assets that were in the second half of the year, I think we've been successful at deploying our our operating platform from a from a people standpoint.
So really good work from the team on applying some of the technical learnings that we've seen in the Midland with specialized focus on either compression uptime on ESP. and artificial lift optimization and then on really great support for flowback in new wells that you see in our results from the second half of the year. What we're working on today is the deployment of the hardware and the structure that will allow for us to then apply that AI and machine learning work that we've been focused on for the last couple of years.
I think that's a really a fall 2024 effort to get the system set up and actually started to deploy that AI. piece of it late in the year. This year, we do assume continued success because we've seen such great work in the Midland across a variety of well, so bodes well that are lifted from EST. from gas lift, so different Artificial Lift types, different GORs. We've seen really successful implementation of AI, and we assume success in the Delaware as well as built into our forward-looking plan and what we expect it to take MR 2024 to get there.

Okay. Thanks for that color. And then as my follow-up, I'm looking at your deck on Slide 6 and 11 and just trying to kind of understand the pace of activity. Obviously, you're sort of working down some ducks with that Glasscock pad this year.
I'm just trying to understand that the Delaware activity 40 spuds, 20 turn-in-lines, just as a timing issue with the calendar year, are you looking to kind of build more of a a little bit of a backlog of ducks first for steady-state operations, trying to understand how we should think about Delaware, the pace of activity there over the next couple of years.

Kyle Coldiron

Thank you. And this is Kyle again. So I think you're right, it's just that ultimately the completion crews have lagged as the drilling rigs. And so when you look at the back half of '24, you have almost 100% of our drilling activity is allocated to the Delaware Basin. But then ultimately as you move into '25, you'll be bringing those wells online and you'll see a heavy allocation of completions of activity there in the Delaware side. So I think you hit it on the head that it's ultimately just the lag of the of the completion crews and the turn-in lines following those drilling rates.

Thank you.

Operator

Paul Diamond, Citi. Your line is open.

Paul Diamond

Thank you. Good morning and thanks for taking my call. Just a quick question on on your hedging structure as you guys progress more towards your kind of your debt targets that increase in scale. How do you anticipate that evolving over time you guys hold in that kind of currently high level? Or is that something you expect to trail down and I guess in what timeframe?

Well, good question. I don't think that our hedging strategy will be too much different than the past. We see 25 moving up into that $75 range. I think we would continue to layer on some additional hedges there. If you were to model our Company at $75 flat versus the strip. Those outcomes are very different at $75. We pay down debt more quickly. We improve the economics of our capital investments.
So I think you would see us as $75 creeps into '25 starting to put on some hedges, we tend to be 75 ish percent hedged out here in the future. So we're in good shape right now and we can kind of watch prices. But for us, we think of it $75 and higher this company is very different than we are today and we would start to put some of those. And you see that we've got some already in place for 1Q 25 of our top 25 already so that's a good number for us that again accelerates our return of cash to shareholder program and improves economics of our well.

Paul Diamond

Understood. Thank you. And just a quick follow-up on so in guidance, you guys talked about 1.7 crews through the year, and a lot of that seems to kind of turn on that optionality in Q4. I guess kind of digging into that a little bit. What do you guys see as really driving that decision is it purely on just timing and cadence? Or could there could well outperformance really drive that to be held back? And just how do you guys think about the ultimate decision on that gains?

Yes, this is activity level we've had in place for a while a lot of that is driven by, again, a desire to use free cash flow to pay down debt. What I would say is it also is one of the reasons we put bands on the capital range and we prefer to have operations steady, but it is February and we've got a lot of time left in the year. So if you see outperformance on production or higher prices or we continue to reduce capital to fund that program. So are all factors that would play into us maybe keeping that second crew going for the final quarter of the year, but we're just kind of it's early in the year and we'll kind of give updates as the year progresses.

Paul Diamond

Understood. Thanks for your time over there.

Operator

Gregg Brody, Bank of America.

Gregg Brody

Good morning, guys. Just two questions for you. The first one could you talk a little bit about some operating costs that sort of Ally have been trending up as you gave quarterly guidance for 1Q. Should we expect that to you? Are there or should we expect that to change in any direction?

Morning, Greg, this is Katie. We expect right now that LOE in Q. one to stay roughly flat to where we exited the year I think that's a fair representation of the first half of the year. Overall, as we bring on some of these new wells in Q2 and Q. three, we see a lot of water volume coming on at the time, productivity and outperformance is bringing high water volumes and then disposal costs with a So expect that our operating costs to be fairly flat here through the beginning of the year where we are today.

Gregg Brody

And then to that, that implies that the additional water implies in the second half, it will be a little higher.

I think we'll be fairly flat to where we are today through through Q2, Q3.

Gregg Brody

And then after that potentially trending down or is it or was how should we think about that starting.

So I think we have opportunity as we're continuing to onboard and optimize these assets here. I think we found some really good cost savings already from where we were in mid 2023 on the on the newly closed Delaware assets, I think and we would expect to stay relatively flat for the full year '24 average and are continuing to work those costs down as we get assets fully onboarded create and you made you've made some comments about paying down debt, and that's the focus right now.

Gregg Brody

And obviously, M&A is still part of the equation. And what does it I know I'm the debt guy asking this, but I'm curious, when do you think about returning cash to shareholders and in terms of dividends or for buybacks? Like how does that fit into how you're thinking about things this year?

Yes, this is Bryan. I mean, I think we've been pretty consistent in how we've messaged in the past. And I don't think we're really going to change here. We would like to see our drilling net debt to EBITDA, not on a forward looking get get below one times and would we have a good line of sight of that happening later this year and towards the end of the year.
And I think we'll have a serious discussion about a dividend policy. What that would look like at that point that it will be it will be important to see what the commodity price environment is looking forward, we want to be very careful about putting a policy in place that can be sustained and through cycles. So we're watching what others are doing the successes and maybe some of the not so successes. And when we put when we get to the point below that one times leverage, will we'll put something in place.

Gregg Brody

That's very well thought out and then what about just splitting the share buyback program?

It was yes, the share, but the share buyback program obviously is more flexible than the dividend policy, a dividend policy. So when we get below one times with the free cash flow generation, that's definitely something we would look at guys.

Gregg Brody

Thank you for the time.

Thank you.

Operator

Derrick Whitfield, Stifel. Your line is open.

Derrick Whitfield

Thanks. Good morning all, and congrats on a solid year in it. And one for my first question I wanted to lean in on the inventory additions in the Midland Basin. Based on your subsurface work, would it be safe to assume these locations are competitive with underwritten inventory and could be developed without material depletion concerns?

Kyle Coldiron

Yes, this is Kyle. So yes, I think you're right that that is competitive with our core underwritten inventory kind of in the fixed dollar breakeven range. When you look at the vertical separation there across the Lower Spraberry, Wolfcamp A. And Wolfcamp B, you've got about 350 feet between the Lower Spraberry and Wolfcamp A. And another 350 feet between the A. and the Upper B target that we developed.
The other thing that we do is we always kind of go in in one rack that development. And ultimately, what we've seen is that, that helps prevent have vertical interference that can occur. And so that's a part of our development strategy as well. And we are we've underwritten these locations coming out, come out of that today, and then we're putting our dollars to work in that area this year. And we're going to do a co-development of the Lower Spraberry A and the B there terrific.

Derrick Whitfield

And either for you or Katie, I mean, it's clear you guys are coming out of the gate really strong in the Delaware. Could you speak to what in your view is driving well performance versus the historical results and the composition of the units you're bringing online by interval. And I'm really speaking to more of the recent turn-in lines. Just we have a good baseline comparison.

Kyle Coldiron

Yes, it's a work as we as we've taken over these assets some of these wells we've completed. They were drilled by previous operators, and we've completed them. Others we've drilled and completed. And so ultimately, I think there's kind of two things that are contributing to the stellar well performance that we've seen. One is our our frac design.
We put a high intensity, tight cluster spacing and higher proppant loading and completion design on these wells. And we think that that certainly contributes. But we also pair that with a spacing design, a well spacing design that we think is optimal for the area. What we've seen over time is that operators have over drill.
They're kind of tightly spaced wells, and you've seen a lot of operators moving to a wider spacing solution. Fortunately, we underwrote a a four well per section solution from the very beginning. And I think you can see that the well results that we're seeing are supportive of that as being the we have the right path.

Derrick Whitfield

Perfect. And one last, if I could, maybe for Jason, wanted to ask if you could speak to the A&D environment in the Permian at present the recent flurry of deals we are seeing are signing an increasing amount of value to inventory, but how do you guys look at the market and the opportunities that are ahead of you.

Kyle Coldiron

As I mentioned that we will we're continuing to evaluate if there are things on the market today. There's things that are coming again, you've got your Diamondback's and Oxy that have announced they would potentially do divestitures. So we're watching some of those come at like waiting for those to come to the market as well. I think we're just going to continue to be very selective.
And again, in vitro inventory that would be part of these, again will need to jump ahead of the inventory we've added today and the things we expect to add later in the year. So we're just going to be again, much more elective.
Again, you are seeing large companies getting together, and we're one of the few Mid-cap remaining bids out there trying to buy an aggregate these assets. So there's less less competition for us and some of these areas. So I think that's also exciting for us because when the competition's high. I just get that up to a higher level.
So I think everything is happening in the macro environment is actually good for providing energy. But again, we we've proven here that we can add 185 wells at a very low cost just because of our technical work. And that's this wouldn't have been possible to add these wells today if we hadn't done the work we did in 2023. So I think we're just again in a great shape.
Bryan and his team done a good job of having our balance sheet in a position that if we want to do something we can. But it's not that we don't have to do anything in 2023 because we've again got new stuff coming on and ahead of us. So we're excited about where we sit today.

Derrick Whitfield

Terrific. Great update, and thanks for your time.

Operator

There are no further questions at this time. Mr. Hagood, I turn the call back over to you.

Thank you for your interest in Vital Rnergy, and this concludes today's call and have a great morning.

Operator

This concludes today's conference call. You may now disconnect.