Vital Energy, Inc. Price & Performance (VTLE)

Press release and presentation can be accessed at our website at www.titleenergy.com. We'll now turn the call over to Jason Paget, President and Chief Executive Officer. Good morning.

Thank you for joining us. Cell 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 five years. Thanks to taking your questions. There are four areas I would like to review. First, our fourth quarter twenty twenty four 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 our focus on generating free cash flow. Finally, we will reduce debt and maintain a strong balance sheet. Let's talk about the fourth quarter. Energy had strong financial and operating results this quarter. Consistent with our performance all year in 2024, results were driven by production that exceeded top end of guidance for both total and oil production. We benefited from strong production from our Point Energy assets acquired last Vital 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 and C capital by about $17,000,000 and increased our net production from the package.

We continue to make significant sustainable progress reducing operating cost 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 $920 per BOE. We continue to be on track to reduce LOE below $9 by the end of twenty twenty five. Financial performance beat expectations as we delivered strong EBITDAX and adjusted free cash flow. Some timing nuances are shifting the resulting debt pay down into first quarter Typically, a $75,000,000 increase in accounts receivable related to the closing of the Point acquisition and $20,000,000 in non budgeted acquisitions. January net debt was already down $50,000,000 below year end levels and we expect total 1Q debt pay down to be approximately $100,000,000 Now let me talk about the significant and positive move in our oil weighted inventory. Since early twenty twenty four, we have increased our total inventory by more than 10% We now have approximately nine twenty five oil weighted locations representing more than eleven 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 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 killed 16 wells in the Wolfcamp Sea 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. For Wolfcamp D wells, an average lateral length of more than 15,000 feet giving us confidence to book additional long lateral locations in the Wolfcamp D. Third, we have new operational competencies and have successfully used shaped well bores to extend lateral lengths excess stranded resources and enhanced returns. Inventory now consists of approximately 120 horseshoe Caped wells that convert two five thousand foot wells into one ten thousand 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 three ten thousand foot wells into two fifteen thousand foot wells. We're drilling our first package later in 2025 with the opportunity to convert 130 straight wells to around 90 J shaped wells reducing breakevens on those wells by around $10 per barrel WTI. Novel way we have combined leasing and shaped well bores is through our eight 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 twelve ten thousand foot wells that we estimate to have an average WTI breakeven of around $40 per barrel. Paid approximately $11,000,000 for the Section and with the additional carry, we'll have acquired these wells for an estimated $1,200,000 per well in an area where operators consistently pay 3x to 4x that amount.

In addition to the nine twenty five wells We have identified an additional two fifty 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. 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 twenty twenty four 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 $825,000,000 to $925,000,000 Current commodity prices we expect our plan to deliver adjusted free cash flow of approximately $330,000,000 at $70 oil We have continued to optimize our capital cost 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.

Thank you. And we will now begin the question and answer session. Our first question comes from the line of Neil Dingmann from Credit Suisse. Please go ahead.

Good morning, Jason, and thanks for you and the team for all the details. My first Just jumping straight to the early point energy activity that you all see specifically Results here, 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 estimate what you're doing to drive this upside? Good morning, Neil, and I'll turn that over to Katie. Hi, good morning, Neal.

Love that there's a few areas that were outperforming early, but the integration has been really 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 been carry into '25. So really excited about the performance in Q4, like you said, outperforming our initial expectations.

Awesome.

Okay. And then just [indiscernible] Jason, just something you got into a little bit in your prepared remarks just around the recent Upton well. Upton County well doing a stake activity, you've just seen a few of the wells as you mentioned, were a little bit under your expectations. I'm just wondering, could 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 draw Barnett well out there The 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 East edge of the both full development as we move west And they just those wells were not as strong as we would have liked. We know we've done multiple tests in other zones that we highlighted. We drilled 16 wells in the Barnett Wolfcamp C, Wolfcamp D last year and our production was outperforming each the challenge is these were coming online right as we gave guidance and when wells come on that are catch up and what you'll see in our program as 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 timing for us.

No plans to complete any other wells in that area this year. Rigs are moving to 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's what I was going to say. Slide that shows the nine twenty five locations and the two fifty up upside, that's not impacted now.

No, sir. They're adjusted for.

Thank you. Thank you, Neil.

Our next question comes from the line of Zach of JPMorgan. Please go ahead.

Good morning. In the inventory slide, you added 140 locations in the deeper zone that you talked about earlier. Could 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 fit? Yes. So I'd say on Slide nine 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 Adam. So we've gotten really good results from Wolfcamp DC, as we've talked about lateral length, how that helps us. In these areas because they're deeper zone The team is able to drill longer laterals, which really enhances the economics in those areas. And I'd say that again, well additions are kind of sprinkled evenly among those different formations.

Thank you, Jason. And then my follow-up you added some core acreage in Midland County at a very low cost. You mentioned 1,200,000 location You all seem to be a little bit further along in drilling the Horseshoe laterals then 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 can potentially take advantage of?

Yes, it's something the team is very focused on. They I mean, there's really we think of A and D, there's only two 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 was 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 to 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 make them 10,000 foot wells, On the Diamondback release, they paid much more for well than we paid for this at just us being just over $1,000,000 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.

Thank you. Our next question comes from the line of Noah Hambliss from Bank of America. [indiscernible] ahead.

Good morning, everyone.

My first question, I was just wondering on the impact it's [indiscernible] If we see these tariffs last more than twelve months, what kind of impact do you think that would have on your CapEx 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 2026, we have a little bit less contracted I think that there's opportunity for some of the service providers who 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 pay down versus the small acquisitions that you guys have done? And how could we think about debt pay down moving forward if more of these deals do pop up? [indiscernible] entirely focused on pay down as the number one thing It takes opportunities like this eight 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 we'll do those every day. And then the lateral addition, the other thing we're literally 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, 15 feet. To equal a 5% improvement in well cost. When you were going an extra 5,000 feet, you reduced 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 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.

Great.

So much.

Our next question comes from the line of John Abbott from Wolfe Research. [indiscernible] Go ahead.

Hey, good morning.

Just curious, so when you it's really about your drilling program this year. And you were testing some new zone in Upton for some new areas there. When you think about your drilling program, how much of your drilling program is actually aimed toward testing new new zones and new potential.

And then my second question, as a follow-up was like you've talked about these two fifty upside locations. How do you think about the time progression in terms of derisking those?

Hi, good morning, John.

When we look at the 2025 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 2025 Vital 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 two fifty locations that you mentioned, we're not in a rush to delineate those. Those are in these 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 2025 or in 2026. I think there's a kind of multiyear effort that it would take to start to pull that $250,000,000 into the core.

Appreciate it. If I could 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? Hi, I mean, it's where we expect to be. We're going to the shape of the production profile this year is kind of a B shape. So we'll we'll have a little bit of low midyear and then kind of ramp up at the end of the year. All right.

Thank you very much.

All right. Thanks.

There are no further questions. It's time Mr. Ron Higgins, 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. Please wait. The conference will begin shortly.