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Good day, ladies and gentlemen, and welcome to Vital Energy, Inc.'s Fourth Quarter 2024 Earnings Conference Call. My name is Jericho, and I'll be your operator for today. [Operator Instructions] 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.

Thank you, and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer; Bryan Lemmerman, Executive Vice President and Chief Financial Officer; Katie Hill, Senior Vice President, 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 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. Press release and presentation can be accessed at our website at www.vitalenergy.com. I'll now turn the call over to Jason Pigott, President and Chief Executive Officer.

Good morning, and thank you for joining us. Vital Energy again delivered outstanding results this quarter. The results would not have been possible without our relentless pursuit to improve the quality of our assets over the last 5 years. Prior to taking your questions, there are 4 areas I would like to review. First, our fourth quarter 2024 results; second, our significant inventory additions and how they will enhance our capital efficiency going forward. Third, our 2025 outlook, which combines disciplined investments and a focus on generating free cash flow. Finally, how we will reduce debt and maintain a strong balance sheet. Let's talk about the fourth quarter. Vital Energy had strong financial and operating results this quarter. Consistent with our performance all year in 2024, results were driven by production that exceeded the top end of guidance for both total and oil production. We benefited from strong production from our Point Energy assets acquired last September. Capital investments were a little higher than guidance. This was primarily due to increased working interest and a carried interest on some bolt-on acquisitions that we developed during the quarter. This impacted D&C capital by about $17 million and increased our net production from the package. We continue to make significant sustainable progress, reducing operating costs on our acquired properties. This was our first full quarter operating the Point assets, and we are very happy with our results. We outperformed our LOE guidance by 5%, delivering at cost of $8.89 per BOE. Some projects were deferred to capture cost efficiencies and will bring our first quarter LOE a little higher, but both quarters together are expected to average around $9.20 per BOE. We continue to be on track to reduce LOE below $9 per BOE by the end of 2025. Financial performance beat expectations as we delivered strong EBITDAX and adjusted free cash flow. Some timing nuances are shifting the resulting debt paydown into the first quarter. Specifically, a $75 million increase in accounts receivable related to the closing of the Point acquisition and $20 million in non-budgeted acquisitions. January net debt was already down $50 million below year-end levels, and we expect total 1Q debt paydown to be approximately $100 million. Now let me talk about the significant and positive move in our oil-weighted inventory. Since early 2024, we have increased our total inventory by more than 10%. We now have approximately 925 oil-weighted locations, representing more than 11 years of drilling at our current development pace. Recent inventory additions were related to the delineation of deeper targets and lateral length increases that provided sustainable drilling cost efficiencies. I'll drill a little deeper on these changes and provide some additional color. First, the average lateral length of our inventory is now 12,800 feet, a 16% increase over last year. In total, we have increased future developable lateral footage by approximately 30%. These changes have been instrumental in improving the quality of our inventory and reducing our average breakeven oil price to approximately $53 per barrel WTI even as we extended out our inventory life. This makes our wells more price resilient and supports our ability to maintain current levels of capital efficiency well into the future. Next, we derisked significant inventory in deeper horizons. In 2024, we drilled 16 wells in the Wolfcamp C, the Wolfcamp D and the Barnett. These tests gave us a robust understanding of productivity in the newer formations, the Wolfcamp C and the Barnett, allowing us to add inventory in those formations for the first time. The Wolfcamp D wells had an average lateral length of more than 15,000 feet, giving us confidence to put additional long lateral locations in the Wolfcamp D. Third, we have new operational competencies and have successfully used shaped wellbores to extend lateral lengths, access stranded resources and enhance returns. Inventory now consists of approximately 120 Horseshoe-shaped wells that convert 2 5,000-foot wells into 1 10,000-foot well, improving breakevens by $15 to $20 per barrel WTI. We are now taking this concept another step, drilling J-shaped wells that convert 3 10,000-foot wells into 2 15,000-foot wells. We'll be drilling our first package later in 2025 with the opportunity to convert approximately 130 straight wells to around 90 J-shaped wells, reducing breakevens on those wells by around $10 per barrel WTI. A novel way we have combined leasing and shaped wellbores is through our 8-mile project, which we are about to begin drilling. We acquired a stranded section in the heart of the Midland Basin that would have been developed with 5,000-foot laterals. Utilizing horseshoe-shaped well designs, we will drill 12 10,000-foot wells that we estimate to have an average WTI breakeven of around $40 per barrel. We paid approximately $11 million for the section and with the additional carry, we'll have acquired these wells for an estimated $1.2 million per well in an area where operators consistently pay 3 to 4x that amount. In addition to the 925 wells we currently have in inventory, we have identified an additional 250 wells that can be added in the future with further delineation. Now turning to more details on our 2025 outlook. We expect to deliver 135,000 to 140,000 barrels of oil equivalent per day, including 62,500 to 66,500 barrels of oil per day. Our full year 2025 oil production expectation is about 2,000 barrels per day less than our initial 2025 outlook. This is due to the underperformance of a package of wells in Upton County that came online in late 2024 and included tests focused on delineating future development inventory as well as delays in our drilling program. These delays pushed out the completions and turn-in-line timing for a few packages of wells, which will defer production until later in the year. Total capital investments, excluding non-budgeted acquisitions, are expected to be $825 million to $925 million. Current commodity prices, we expect our plan to deliver adjusted free cash flow of approximately $330 million at $70 oil. We have continued to optimize our capital costs, expecting to invest less in 2025 while shifting more capital to the Delaware Basin and completing the same amount of net lateral feet as 2024. Efforts to high grade our development plan and extend laterals is expected to drive a significant improvement in capital efficiency in 2025 versus 2024. Our focus today is squarely on optimizing our existing assets and maximizing cash flow for our investors. As a result, we will deemphasize potential large-scale acquisitions and allocate substantially all free cash flow to reduce our net debt. Thanks again for joining us this morning. Operator, you can now open the line for questions.

[Operator Instructions] Our first question comes from the line of Neal Dingmann from Truist Securities.

My first question really just jumping straight to the early Point Energy activity that you've seen specifically results here, I'm just looking at a couple of slides and things, but the results appear to be as good, I would call it, if not better, than I was -- at least I was expecting. I'm just wondering, could you all -- you, Katie, the team, maybe discuss how you're thinking about the early results versus your prior estimates and what you're doing to drive this upside?

Neal, I'll turn that over to Katie.

Neal, we love this asset. There's a few areas that we were outperforming early, but the integration has been really smooth. We're seeing better-than-expected downtime on the base wells. Some of the early new wells are coming online stronger than expected. We've already been able to drive down some of the LOE costs and are seeing some capital efficiency that's going to carry into '25. So really excited about the performance in Q4, like you said, outperforming our initial expectations.

Awesome. Okay. And then just secondly, Jason, just something you got into a little bit in the prepared remarks just around the recent Upton well -- Upton County well delineation activity. It just seemed a few of the wells, as you mentioned, were a little bit under your expectations. I'm just wondering, can you discuss there also what might be the potential issues? And would you call this sort of just limited to an isolated area?

Yes, thank you. The Upton County wells are just part of our program this year. We took core on the location. It's actually what has fostered us to drill a Barnett well out there. The primary issues were related to Wolfcamp A and Lower Spraberry wells. These were newer formations. We had traded data with an offset operator where performance was great. And we wanted to test these wells. These are kind of the east edge of the play, and we want to test these zones before we incorporate them into full development as we move west. And they just -- these wells were not as strong as we would have liked. We've done multiple tests in other zones that we highlighted. We drilled 16 wells in the Barnett, Wolfcamp C, Wolfcamp B last year, and our production was outperforming each quarter. The challenge is these were coming online right as we gave guidance. And when wells come on that are disappointing earlier in the year, it just takes a little time to catch up. And what you'll see in our program is these capital efficiencies we've highlighted. We'll continue to grow production throughout the year. We'll go through a little dip and then grow production back. But unfortunate, but we had a lot of successes. And if you think of the 140 wells that we added in these deeper targets, they're just part of the business, but unfortunate time for us. No, no plans to complete any other wells in that area this year. Rigs are moving to other Midland areas and then the Delaware Basin focused primarily on Point all of our inventory that we highlighted this morning has taken into account those impacts.

That I was going to ask that slide that shows what 925 locations, 250 upside, that's not impacted now.

No, sir, they’re adjusted for it.

Our next question comes from the line of

In the inventory slide, you added 140 locations in the deeper zone that you talked about earlier. Can you just give us a little more detail on those locations? Really just looking for a bit more color on the zones and geographic areas where those wells sit?

Yes. So I'd say on Slide 9 in our deck, we highlight all of the tests that we've done or some of the tests that were used to inform these decisions to add them. So we've gotten really good results from Wolfcamp B, C, as we've talked about lateral length, how that helps us in these areas because they're deeper zones, the team is able to drill longer laterals, which really enhances the economics in those areas. And I'd say that, again, the well additions are kind of sprinkled evenly among those different formations.

And then my follow-up, you added some core acreage in Midland County at a very low cost. You mentioned $1.2 million per location. You all seem to be a little bit further along in drilling the horseshoe laterals than some of your peers. Do you see more of an opportunity set to add these kind of stranded single-section acreage blocks in core areas? Is that something you all could potentially take advantage of?

Yes, it's something the team is very focused on this year. I mean there's really -- when we think of A&D, there's only 2 types of things that we are focused on, and that is white space next to our acreage position where we can make 10,000-foot wells, 15,000-foot wells and things like this. The team did a great job of being flexible. A lot of times, these opportunities come because the leases are expiring and things like that. So we jumped through a few hoops because we bought this in December, and we're going to be drilling it here pretty soon. So being able to move it into the schedule and then the economics work for us because you're -- again, you're taking what a normal operator would have 5,000-foot wells. We make them 10,000-foot wells. On a Diamondback release, they pay much more per well than we paid for this at just us being just over $1 million. So I really think our team does a great job of thinking outside the box to create incremental value and be flexible with rig schedules to be able to incorporate things like this.

Our next question comes from the line of Noah Hungness from Bank of America.

For my first question, I was just wondering on the impact of steel tariffs. If we see these tariffs last more than 12 months, what kind of impact do you think that would have on your CapEx budget?

We're secured out through most of '25 on OCTG, and that's really where we see the most exposure to potential tariffs. If it extends out into '26, we have a little bit less contracted. I think that there's opportunity probably for some of the service providers to start to pass through some of those costs, but very little exposure this year.

Got you. And then for my second question, how should we think about the decision tree between debt paydown versus the small acquisitions that you guys have done? And how could we think about debt paydown moving forward if more of these deals do pop up?

We’re going to be – we’re entirely focused on debt paydown as the #1 thing. It takes opportunities like this 8 mile, I think, to get us off of that strategy. So we’re really trying to put substantially all of our free cash flow to debt pay down this year. But when you have an opportunity to bring in $40 breakeven wells at a relatively low cost per well, we’ll do those every day. And then the lateral addition, the other thing we’re really looking at is just lateral extensions. When we go from a 10,000-foot lateral to a 15,000-foot lateral that it only takes, I think, 1,500 feet to equal a 5% improvement in well cost. So when you’re going an extra 5,000 feet, you reduce breakeven by $5 or more. So those are real ways that we can improve the quality of our inventory. When you look at our inventory, we have a long length of inventory and our focus is how do we take our length of inventory and improve the quality of the average well in that stack of inventory. And that’s what you’re seeing from the team is this push to increase lateral length to improve the quality of our inventory.

Our next question comes from the line of John Abbott from Wolfe Research.

Just curious, so when you -- it's really about your drilling program this year. And you were testing some new zones in Upton or some new areas there. When you think about your drilling program, how much of your drilling program is actually aimed towards testing new zones and new potential? And then my second question as a follow-up is like you've talked about these 250 upside locations. How do you think about the time progression in terms of derisking those?

John, when we look at the '25 program, the bulk of our capital early in the year is dedicated to the Point asset, really high-return, high confidence locations. In the second half of the year, we have a mix between the rest of the Southern Delaware and Midland. Very little of our capital in '25 is going towards risk or appraisal opportunities. We've done a good job over the last couple of years, proving out inventory and at this stage are really in co-development mode. As we look at the upside 250 locations that you mentioned, we're not in a rush to delineate those. Those are in deep zones. We have high confidence in them. Some of the 140 that we've added that have direct offset, direct subsurface control. So we have an opportunity to really work our way through that deliberately, and it's not a substantial portion of the outlook in '25 or in '26. So I think there's a kind of multiyear effort that it would take to start to pull that 250 into the core.

I appreciate it. If I can squeeze just one really quick other question in there. I mean, you plan to catch up in the second half of this year. Any idea what the exit rate would be for this year by year-end for oil?

I think is where we expect to be. We’re going to – the shape of the production profile this year is kind of a V-shape. So we’ll have a little bit of lull midyear and then kind of ramp up at the end of the year.

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

Thank you very much for joining us for our call this morning. We appreciate your interest in Vital Energy, and this concludes our call.