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 Dessire (ph) and I will be your operator for today. At this time, all participants are in 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. It is now my pleasure to introduce Mr. Ron Hagood, Vice President, Investor Relations. You may proceed, sir.

Ron Hagood: Thank you, and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer; Bryan Lemmerman, Executive Vice President, 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. 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: Thank you, Ron, and thank you for joining us this morning. 2023 was a great year for Vital 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 at lower than anticipated capital costs. 12 months, we increased our oil production by approximately 60%. For a 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.

We closed six accretive Permian Basin acquisitions were $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 EBITDAX ratio of 1.09 times, which was 8% lower than the prior year end. Before we reduced Scope 1 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 TrustWell certification for responsible operations, placing Vital Energy in the top quartile of U.S. onshore operators.

Our strategic shift to focus on entry into the Delaware Basin and expand into 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. Mostly (ph), 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 and $850 million, with oil production guidance of 55,000 and to 59,000 barrels of oil per day and total production of 116,500 to 121,500 barrels of oil equivalent per day, 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.

Katie Hill: Thank you, Jason. Operationally, we had an extremely successful 2023. We consistently exceeded production expectations throughout the year, delivered capital investments below plan, successfully integrated six asset acquisitions, 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. Bulk of our 2023 development was in Howard County, and the results showcase the success of this integration and optimization process. New wells in Howard regularly exceeded production expectations and we continue to drive execution efficiencies.

Aerial view of an oil well and the rig in the Permian Basin, West Texas.

In the fourth quarter, we set company records in drilling, delivering a 10,000 foot lateral in 6.5 days and a record setting 7,716 drill feet in a day. We also set records and completions during the fourth quarter for daily pumping hours, 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 pump sizes to dewater wells more quickly after drill out and to better recover from offset brackets. 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 expectations.

Other driver of our 2023 results has been the optimization of our base production. Last year, wells brought online prior to January 1, exceeded production expectations by 10%. It was accomplished through both process improvements and the continued application of optimization technologies. The end result has been faster and more targeted response times and increased mechanical run times across the field. This operating model has proved to be scalable, and we are improving results through integration of the Driftwood and Forge acquisition that we closed on in early 2023. Production from new wells on the assets is exceeding expectations by 10% on legacy Driftwood and 33% on legacy Forge acreage. We are early in the process of optimizing base operations on the properties, but are already exceeding production expectations on the legacy Forge asset by 4%.

We have 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. We are delivering wells more quickly for less capital and with higher productivity than expected acquisition, these results have been built into our forward-looking forecast and reflect continued year-over-year improvement. We onboard these assets, 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 that incorporated offset operator results and importantly, a robust data set 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 cost 12% 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 capitally 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. Fluid production data from our recently turned in line Delaware wells continues to support our development plan. On the Midland Basin, Western Glasscock package, drilling and completion operations have gone very well, and five wells are currently flowing back.

Pressure on these wells is promising, and the package is already producing 3,000 gross barrels per day. Clients, 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.

Bryan Lemmerman: 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. Our thoughtful approach to financing these transactions have 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. The 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 382 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.

I will now turn the call back over to Jason for closing comments.

Jason Pigott: Hey, Bryan. To close, I want to reiterate that Vital Energy is a 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.

Operator: Thank you. The floor is now open for your questions. [Operator Instructions] Your first question comes from the line of Neal Dingmann, Truist Securities. Your line is open.

Neal Dingmann: Good morning, all. Nice quarter. Just my first question, maybe both of them are going to be around maybe Slide 9 and 8. First, maybe some of you and Katie said that on both of these. Could you maybe start on Slide 9, 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 [indiscernible] recently added Delaware as well as the Midland Basin. I mean, has that changed? I know you’ve got the four rig focus this year. Could you maybe talk about how you plan to attack that now that you’ve got all the assets sort of working together?

Katie Hill: Sure. Good morning, Neal. This is Katie. We had — throughout the year, this year, we’re planning to run, 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, we’ll shift a little bit more heavily into the Delaware in the second half. There’s some really good opportunity 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 try 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 Forge 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 really good opportunity for us across the basin.

Neal Dingmann: Yeah. Great details. And then just a follow-up, looking actually at Slide 7 or 8, where you talked about additional zones and then you show the sort of cost reductions. I’m just wondering something you had mentioned when you now tackle, I guess, what do you all view as sort of the optimal project or optimal pad size? It seems like for even being a smaller operator, you’ve all been able to walk that up and capture some efficiencies. So again, I guess when I’m looking at these two, just wondering like when you co-develop now, how big of projects are optimal and you think makes the most sense for you all?

Kyle Coldiron: Yeah, Neal. This is Kyle Coldiron. So I think the answer really depends on the area and kind of the stack pay that you have. So if you look at our Western Glasscock package that they have coming online right now, essentially, that’s kind of two very large pads that — where we drilled those 20 wells. And one of the great benefits of that was that we were basically able to park our Halliburton fracture 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 the three to five type of range. 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 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 in the materials that we shared today.

Neal Dingmann: It makes sense. Thanks for the details. Great job, guys.

Jason Pigott: Thanks, Neal.

Kyle Coldiron: Thanks, Neal.

Operator: Our next question comes from the line of Zach Parham with JPMorgan. Your line is open.

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

Jason Pigott: Zach, good morning. It’s Jason. 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 add 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 B, and that’s a zone that’s being completed today on those large pads we’ve got out there. So as you mentioned, again, we’ve added Lower Spraberry and Wolfcamp A in Howard — sorry, Southern Midland. We took core data that should indicated to us these zones would be good, and then we had offset operators that brought those online and confirmed what we saw in the geology. We would develop them a little bit differently than some of the offsets were they lined 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 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 test — is coming online today in Western Glasscock. That’s a totally new zone for us that could add future inventory or 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: Yeah. So Zach to your question on the Delaware side specifically, the intervals or the inventory that we added was across our Second Bone, Third Bone, Wolfcamp A and Wolfcamp B, which are our core development horizons. So these aren’t new horizons or anything that we haven’t previously disclosed, but as Jason said it well, ultimately, the improved economics of $1.5 million 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 turned in line, the well productivity has been fantastic. And so it just gives us a lot of confidence that we can go and develop across those benches there on the Delaware side.

Zachary Parham: Thanks. I appreciate the color there. I guess my follow-up just 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 conditions at this point, where does kind of M&A set in your mind going forward?

Kyle Coldiron: Yeah. Another great question. I think we did amazing work in ’23 to continue our transformation as a company. We talked a lot last year about this transition to small ball, which was performing a series of smaller transactions that weren’t as competitive when again, the larger peers were bidding on things and it was wildly successful for us. Again, as we completed, again, almost $1.6 billion in over $1.6 billion in transactions. In ’24, we’re switching a little bit more to the money ball, which is let’s spin 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 cost. 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 be accretive to us and inventory will need to jump the inventory that we’ve added this year. So I’d say, we’re still going to look at it. I mean there could be great opportunities with an Oxy or Diamondback that are looking to or endeavor – 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 the type of things that we’ll look at in 2024.

Zachary Parham: Okay. Thanks for taking my questions.

Operator: Next question comes from the line of Tim Rezvan with KeyBanc Capital Markets. Your line is open.

Tim Rezvan: Hey. Good morning, folks. Thanks for taking my question. This may be best for Katie. I know you all, you’re 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 Driftwood and Forge. I was wondering, if you could give an update on kind of how things stand with the recently acquired assets and maybe when you would get that fully implemented into sort of your cloud system, what the time line for that would be? Thanks.

Katie Hill: Sure. Good morning, Tim. I think we would consider the 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 acquisition. So Driftwood, the Southern Midland Basin assets are effectively fully integrated into our operating platform. We’ve taken some really strong steps on that first Delaware asset in Forge, like you mentioned. When we think about this three assets that were in the second half of the year, I think we’ve been successful at deploying our operating platform 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 and new wells, which 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 really a full 2024 effort to get the system stood up and actually start to deploy that AI piece that’s 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 wells. So both wells that are lifted from ESC, from gas lift to different artificial lift types, different GORs, we’ve seen really successful implementation of AI, and we assume success in the Delaware as well. So it’s built into our forward-looking plan, but we expect it to take moves to 2024 to get there.

Tim Rezvan: Okay. Thanks for the 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 that the pace of activity. Obviously, you’re sort of working down some DUCs (ph) with that Glasscock pad this year. I’m just trying to understand the Delaware activity, 40 spuds, 20 turn-in-lines, is this just a timing issue with the calendar year? Are you looking to kind of build more of a little bit of a backlog of DUCs for steady-state operations, trying to understand how we should think about Delaware, the pace of activity there over the next couple of years? Thank you.

Kyle Coldiron: This is Kyle again. So I think you’re right. It’s just ultimately, the completion crews lag 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 activity there in the Delaware side. So I think you hit it on the head that it’s ultimately just a lag of the completion crews and the turn in lines following those drilling rates.

Tim Rezvan: Okay. Thank you.

Operator: Next question comes from the line of Paul Diamond with Citi. Your line is open.

Paul Diamond: Thank you. Good morning, all. Thanks for taking my call. Just a quick question on your hedging structure. As you guys progress more towards your kind of your debt targets and increasing scale, how do you anticipate that evolving over time? Are you guys holding at a kind of currently high level or is that something you expect to trail down and what time frame?

Jason Pigott: Paul, good question. I don’t think that our hedging strategy will be too much different than the past. [Technical Difficulty] 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 hedged out a year in the future. So we’re in good shape for right now, and we can kind of watch prices. But for us, we think of $75 and higher, this company is very different than we are today, and we would start to put some of those on.

You see that we’ve got some already in place for 1Q ’25 first half of ’25 already. So that’s a good number for us that again accelerates our return of cash to shareholder program and improves the economics of our wells.

Paul Diamond: Understood. Thank you. And then, 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, just trying to dig into that a little bit. What do you guys see as really driving that decision? Is it purely on just timing of cadence or could they — could well outperformance really drive that to be held back and just how do you guys think about the ultimate decision on that cadence?

Jason Pigott: Yeah. This is the activity level we’ve had in place for a while. A lot of that is driven by 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 bans on the capital range. We prefer to [indiscernible] operations steady, but it’s February, and we 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. Those 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. I’ll leave it there.

Jason Pigott: Thank you.

Operator: Our next question comes from the line of Gregg Brody with Bank of America. Your line is open.

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

Katie Hill: Good morning, Gregg. This is Katie. We expect right now that LOE in Q1 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 Q3, we see a lot of water volume coming on, the high productivity and outperformance in is bringing high water volumes and then disposal costs with us. So expect that our operating cost to be fairly flat here through the beginning of the year with where we are today.

Gregg Brody: And then, so that implies the additional water implies in the second half, it will be a little higher?

Katie Hill: I think we’ll be fairly flat to where we are today through Q2, Q3.

Gregg Brody: Got it. And then after that, potentially trending down or is it — how should we think about that?

Katie Hill: Sure. So I think we have opportunity as we’re continuing to onboard and optimize these assets. I think we found some really good cost savings already from where we were in mid-2023 on the newly closed Delaware assets. I think we would expect to stay relatively flat for the full year ’24 average and are continuing to try to work those costs down as we get assets fully onboarded.

Gregg Brody: Great. And you made some comments about paying down debt, and that’s the focus right now and obviously, M&A is still part of the equation. When does — I know I’m the debt guy asking this. I’m curious, when do you think about returning cash to shareholders and in terms of dividends or buybacks? Like, how does that fit into how you’re thinking about things this year?

Bryan Lemmerman: Yeah. This is Bryan. 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 rolling net debt to EBITDA, not on a forward-looking get below 1 times. And we have a good line of sight of that happening later this year 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. 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 through cycles. So we’re watching what others are doing. The successes and maybe some of the — not so successes. And when we get to the point below that 1 times leverage, we’ll put something in place that’s very well thought out.

Gregg Brody: And then what about just the share buyback program utilizing?

Bryan Lemmerman: The share buyback program, obviously, is more flexible than the dividend policy. So when we get below 1 times with the free cash flow generation, that’s definitely something we would look at.

Gregg Brody: Okay, guys. Thank you for the time.

Bryan Lemmerman: Thank you.

Operator: And we do have our last question comes from the line of Derrick Whitfield with Stifel. Your line is open.

Derrick Whitfield: Thanks. Good morning, all and congrats on a solid year end update.

Bryan Lemmerman: Thanks, Derrick.

Derrick Whitfield: 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: Yeah, Derrick. This is Kyle. So yes, I think you’re right that it is competitive with our core underwritten inventory kind of in the $6 breakeven range. When you look at the, the vertical separation there across the Lower Spraberry, Wolfcamp A and Wolfcamp B, you’ve got about 350 feet between the Lower Spraberry and the Wolfcamp A and another 350 feet between the A and the Upper B target that we develop. The other thing that we do is, we always kind of go in and wine rack that development. And ultimately, what we’ve seen is that, that helps prevent 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 with 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.

Derrick Whitfield: Terrific. And either for you or Katie, I mean it’s clear you guys are coming out of the gate really strong in 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: Yeah. So we’re — 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 frac design. We put a high intensity type cluster spacing high proppant loading completion design on these wells, and we think that, that certainly contributes. But we also paired 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 drilled they’re kind of two tightly spaced wells, and you’ve seen a lot of operators moving to a wider spacing solution Fortunately, we underwrote 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 right path.

Derrick Whitfield: Terrific. One last, if I could, maybe for Jason. I wanted to ask, if you could speak to the A&D environment and the Permian at present. The recent flurry of bills, we are seeing our 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?

Jason Pigott: Yeah. I mentioned, we will — we’re continuing to evaluate it. There are things on the market today. There’s things that are coming. Again, you’ve got your Diamondback and [indiscernible] that have announced they would potentially do divestitures. So we’re watching some of those come — like waiting for those to come to the market as well. I think we’re going to just going to continue to be very selective. And like an inventory that would be part of these, again, we’ll 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 selective. Again, you are seeing large companies getting together and — we’re one of the few mid-caps remaining that’s out there trying to buy and aggregate these assets.

So there’s less competition for us in some of these areas. So I think that’s also exciting for us because when the competition is high, you just get it up to a higher level. So I think everything is again happening in the macro environment is actually good for Vital Energy. But again, we’ve proven here that we can add, again, 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 have 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 — 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. Thanks for your time.

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

Ron Hagood: Thank you for your interest in Vital Energy. This concludes today’s call. Have a great morning.

Operator: This concludes today’s conference call. You may now disconnect.

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VITAL ENERGY INC

Q4 2023

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