Vital Energy, Inc. (NYSE:VTLE) Q1 2025 Earnings Call Transcript

Vital Energy, Inc. (NYSE:VTLE) Q1 2025 Earnings Call Transcript May 13, 2025

Operator: Good day, ladies and gentlemen, and welcome to Vital Energy Inc.’s First Quarter 2025 Earnings Conference Call. My name is Fran 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 now 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 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’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 afternoon. The press release and presentation can be accessed at our website at www.vitalenergy.com. I will now turn the call over to Jason Pigott, President and Chief Executive Officer.

Jason Pigott: Good morning, and thank you for joining us. Vital Energy delivered solid first quarter results driven by our ongoing optimization efforts that are making us a more resilient enterprise while creating value for our shareholders. Today’s call, we will discuss our first quarter financial and operating performance, including significant progress to reduce costs and enhance efficiencies. Our 2025 outlook and how our strong start to the year provides confidence in our full-year assumptions and how our advantaged portfolio provides us with options and flexibility to effectively navigate today’s challenges. Turning to the first quarter. Our key financial results exceeded street expectations. I am excited that we are able to reduce net debt by $135 million.

Our debt reduction was supported by higher-than-expected adjusted free cash flow, which beat street consensus. We also benefited from our hedge position, adding more than $20 million to revenues and a non-core asset sale generated an incremental $20.5 million. Our capital investments and production were in line and our costs are clearly moving in the right direction. The accelerated capital spending reflected our continued improvement in drilling efficiencies that pulled incremental activity into the first quarter. First quarter volumes were driven by 23 turned-in-line wells all in the Delaware with 21 in the Southern Delaware. We saw good well performance and our schedule optimization allowed for early production from several development packages.

At the end of 2024, we shifted our focus from acquisitions to optimizing our asset base. Since that time, we have successfully reduced lease operating expense and general and administrative expenses by approximately 5%. In the fourth quarter of last year, LOE amounted to $121 million for the quarter. We now anticipate it will be around $115 million per quarter by the remainder of 2025. G&A expenses, excluding long-term incentive plan were slightly over $23 million in Q4, and we project these costs will be below $22 million per quarter for the duration of 2025. Our first quarter results provide confidence in our full year outlook. Today, we reiterated the midpoints of our full year capital and production guidance as well as lowering operating costs.

Let me share a few reasons why we have high confidence in our 2025 outlook. First is the high returns we expect from the packages we are completing in the second half of the year. On Slide 5 of our investor deck, you can see how we are prioritizing our capital allocation to our lowest breakeven packages. Our significant ramp in production later this year, which is highlighted on Slide 6 will be driven by a high turned-in-line count in the third quarter. These completions will be coming in from some of the highest return areas with low breakevens of about $45 per barrel WTI. Due to the high quality of these wells and the robustness of our hedge portfolio, we foresee substantial returns from these packages. Consequently, we do not intend to delay the generation of valuable cash flow or debt repayment.

We anticipate that production in the fourth quarter, supported by our hedges will contribute significantly to our adjusted free cash flow and facilitate debt repayment for the full year 2025. Second, we are encouraged by recent cost reductions and sustainable efficiencies. Let me share a few examples. Thus far, we have seen little impact from tariff-related price increases which have been more than offset by the price concessions we have successfully secured in the softening services environment. Our drilling and completions teams continue to set records for speed and efficiency. In the first quarter, we set cycle time records for both 2-mile and 3-mile wells. The continuous improvement demonstrated by our operations team has allowed us to improve our Delaware Basin year-over-year capital efficiency by 30%.

In 2025, more than 50% of our completions will be simul-frac. In the first quarter, we successfully implemented this technique, exceeding our expectations for completed feet per day and delivering every package in the first quarter ahead of schedule. Our operating teams are effectively using leading-edge technology to drill shaped wells like J-Hook and Horseshoes to maximize the value of our acreage and access high-quality resources. On Slide 10 of our investor deck, we provide an update on 2 of these developments. We have now drilled and completed our first 2 J-Hook wells, proving the concept and the potential to lower the breakeven for 135 wells by $5 per barrel. Third, our hedges provide confidence in our cash flow and debt reduction targets.

For the remainder of the year, 90% of our oil is hedged at $70.61 per barrel WTI ensuring returns and reducing risk. This should allow us to generate about $265 million in adjusted free cash flow and reduced net debt by $300 million including non-core assets sold to date. Lastly, our asset quality provides us with attractive options for the allocation of our capital. Slide 9 in today’s deck shows a 300% increase in completable lateral foot with a sub-$50 WTI breakeven. As we test new well shapes, we reduced well count through the combination of laterals, but not our developable reservoir footage. Not only are we improving the quality and durability of our inventory, we are reducing the breakevens of every foot we drill. Before moving to questions, let me quickly provide some thoughts on today’s macro challenges.

We are not immune to today’s market challenges and we have the flexibility to meaningfully adjust activities should conditions warrant. We have no rig or completion contracts that extend beyond early 2026 and are committed to delivering positive adjusted free cash flow in 2026. Further, we are conducting a full review of our cost structure, and we are confident in our ability to continue to reduce costs and enhance margins. Our focus today is clear, maximize cash flow and debt repayment. These are key ingredients to building long-term value for our shareholders. Operator, we are now ready for questions.

Q&A Session

Operator: [Operator Instructions] And your first question comes from the line of Derrick Whitfield from Texas Capital.

Derrick Whitfield: Congrats on a strong 1Q. With my first question, I really wanted to focus on maintenance capital as you guys see it going forward with really the benefit of your latest D&C efficiencies, optimized well design and base optimization work. Where would your maintenance capital be once some of your higher-priced service contracts roll off over the balance of this year and next year?

Jason Pigott: Thanks, Derrick. Our plan for right now is to be flat in production year-over-year. And our goal for next year is to remain free cash flow positive. And as you mentioned, all of our major service contracts expire in March of 2026 and provide us the flexibility to adapt activity levels as needed. If you think about service costs, the recent Rystad report suggested service cost could come down 10% in a sustained $60 environment. And if you use our current budget as a marker, that’s nearly $90 million in savings you could see on the cost front. This would reduce our breakeven from where it is today at about $57 per barrel, down to $53 per barrel. And then that doesn’t include other things like continued LOE reductions or G&A reductions that start to push that down closer to $50 a barrel. So we’re working on a lot of things, a lot of time ahead of us, but I think that’s kind of where we sit today.

Derrick Whitfield: That’s great. And then maybe as my follow-up, just leaning in on the cost initiatives. Katie, could you perhaps speak to some of the LOE self-help initiatives you’ve accomplished. And just comment on areas where you see further opportunity.

Katie Hill: You bet. I love getting to talk about this. I’m just really excited about the work and the progress that the team is making. Jason mentioned that in Q4 last year, we were at $121 million run rate, and we expect to be in the $110 million to $115 million a quarter for all of this year. We had a great Q1, $103 million. A big driver of that is continued outperformance on point. We’ve been really successful at lowering our operating costs there. We got it fully integrated late last year. We gave ourselves about a quarter window to get the invoicing process fully onboarded. And as a result, what we saw in Q1 was actually a $6 million adjustment from prior periods, so continued outperformance in Q4. So what that means is that $103 million was closer to $110 million run rate for the quarter.

The reason we go from $110 million to $114 million or $115 million is really driven by increased water volumes throughout the rest of this year. But from a fixed cost and workover standpoint, we expect to maintain the performance that we’ve been able to deliver here over the last couple of quarters. So big drivers, again, on point are reduced failure rates for some of the artificial lift specifically ESP, reducing the cost for all workovers in both Delaware and the Midland and then really great work from both basins on reducing our fixed operating costs. Again, we expect that to sustain for the rest of ’25.

Operator: And your next question comes from Zach Parham from JPMorgan.

Zach Parham: First, just wanted to ask on your hedging strategy. You added around 20,000 barrels a day of hedges for the back half of the year in the upper 50s, but didn’t have any hedges for 2026. Just curious about how you’re thinking about building out the hedge book for next year and future years?

Jason Pigott: Yes, as you mentioned, we did raise our hedges for this — rest of this year. A lot of that was driven by higher volumes coming into the fourth quarter being our highest production volume for the year and almost — we could actually see a company record for production as we get to the fourth quarter of this year. So we added those hedges to lock in our free cash flow generation for the year and assure our debt reduction. In general, we tend to be 75% hedged about a year in advance, taking this up to 90% plus first quarter. We’re at that mark. But as time progresses, we’ll continue to watch the environment and layer on hedges as we see fit to again, lock in free cash flow generation and our debt reduction goals.

Zach Parham: And then my follow-up, just wanted to ask on the trajectory of volumes and CapEx going forward. You laid that out for the remainder of the year in the slide deck, but oil will peak in 4Q and CapEx will be at the lowest level of the year. Can you just talk about the trajectory of production going into 2026? Just given that drop off in spending later this year, would you expect a pretty decent decline into 1Q and then you kind of stabilize? Just curious what that trajectory looks like?

Katie Hill: You bet. The 2026 program right now, we estimate to be flat year-over-year for both volume and capital. Jason mentioned in some of his comments, that we have most of our contracts rolling off, either in Q4 of ’25 or Q1 of ’26. We’re seeing really good movement from a market standpoint compared to our current averages. So looking forward to being able to capture some of those savings that will ultimately drive the capital program next year. So as we think about that volume and quarter-over-quarter cadence, we first will need to resolve what the activity level looks like in the first half, but I would think of full year volumes as being flat compared to ’25.

Operator: And your next question comes from Noah Hungness from Bank of America Merrill Lynch.

Noah Hungness: For my first question, you guys mentioned that there may be potential for future pricing weakness. But I was also wondering, do you guys see any opportunity to potentially high-grade your current rigs or crews, just as some of these service companies may be looking to keep some of these crews running if we do see some guys dropping them in the back half of the year and early ’26?

Katie Hill: We stagger all of our contracts, which allows for us to have a pretty good pulse on the market. Our most recent rig was about 20% below the fleet average for us. So certainly an opportunity for us to continue to capture some of those cost efficiencies and softening or to high grade from a performance standpoint. As we look at ’25 and ’26, the rig contracts continue to cycle through. We don’t have any that extend past the end of Q1 next year. So a lot of opportunity within that fleet and then similarly on the completion side, our primary contract is extended into the beginning of ’26. We’ll offer some opportunity after Q1 to capture the current mark rate. So yes, I do think there’s opportunity both on performance and some of the technical capabilities, technology capabilities and then also on cost.

Noah Hungness: Got you. And then, Bryan, this one is probably for you. You guys had a noncash impairment this quarter. As we kind of move through the year and if oil prices kind of stay where strip is implying the price would be, could you talk about how — if we may see more of these non-cash impairments? And then if so, like how much, what the quantity of it looks like? And then also if this will have any impact on the inventory numbers as well?

Bryan Lemmerman: Yes. if you’ll notice in the 10-Q, we talk about that going out 1 quarter. So that number is in there, and I’ll let you refer to it. But definitively, if we have — if oil price stays where it is today, we will have noncash write-downs just the way the — our pool is written down over time. So I think next quarter, it’s in the tune of a couple of hundred million dollars. We would expect to see that. We don’t really project out a lot further than that. But if you take the SEC pricing, you can do the math and see that it’s something like that until we stabilize with price. Again, this is just a write-down of the free cash flow. It doesn’t have to do anything with the underlying — the reserves aren’t gone. They’re just a calculation.

Operator: And your next question comes from John Abbott from Wolfe Research.

John Abbott: I want to go back to Derrick’s questions about breakeven. And you mentioned $53 per barrel next year, is that a well-head breakeven? And if it is, how do you think about your corporate breakeven and the movement in your corporate breakeven as you head into next year?

Jason Pigott: Yes. The number I quoted was actually our corporate breakevens. Our well breakevens are below that or on average. Again, we’re continuing to high grade the portfolio, but we’re at $57 today. And again, if you — if costs or service costs continue to come down in that 10% range, that would push it down to $53. And then again, great work that Katie is doing on LOE, can push it down further and then potential G&A reductions and things like that push it down even further. So we could be knocking on $50 by the end of next year or through next year.

John Abbott: Appreciate it. And then just one very quick one for me. You had a small asset sale here during the quarter. What’s the opportunity for additional asset sales this year?

Jason Pigott: We’re continuing to look at our portfolio. This opportunity was one where we didn’t have any inventory on the asset. The offset operator had wells that they could extend or put inventory value on there as a gassier asset at 200 — roughly 200 barrels of oil per day and 1,300 BOE per day. So not a significant drop in our production as a company. And we’ve actually absorbed that and maintained our current guidance. So for us, opportunity to bring cash in the door, accelerate our debt reduction goals and no impact on the full year’s projection. So it’s something that we’re excited about, maybe even more difficult to do those kind of things in this price environment because these assets, again, are just taken away from your free cash flow, but this buyer was willing to pay us for inventory that we didn’t even have on the book. So it was a good fit for us, and we’re continuing to look at the portfolio all the time.

Operator: And your next question comes from Jon Mardini from KeyBanc Capital Markets.

Jon Mardini: We saw WAHA realizations coming in nearly 40% of Henry Hub in the quarter, which is the strongest in the past few quarters, but still on a relative basis. We recognize the WAHA swaps you have in place to mitigate the impact of the takeaway constraint dynamics in the basin. And that basis could tighten with some regional peers reducing activity. I know it could be too early to tell, but is this reduction in activity, what you’re seeing or hearing on the field, maybe among the smaller private operators? And are there some takeaway or in-basin demand solutions that you’ve been looking at or planning?

Benjamin Klein: Yes. This is Ben Klein. So yes, it’s a great question. We definitely are seeing an improvement in the basis. We hear that it is activity driven and — but we’re not necessarily seeing anything different from a takeaway standpoint, nothing from a new standpoint or headline standpoint. We look at all of our options when it comes to taking firm and selling out of basin versus going ahead and selling in basin and simply putting on basis swaps or hedging the WAHA outright. So yes, so our expectation is for when activity levels soften for WAHA to strengthen and allows for us to take advantage of that higher price, as you said.

Jon Mardini: Okay. And just to follow up on that, the activity reductions. For you guys, how would a potential decision to trim activity levels look like? Would you prioritize building DUCs and deferring TILs? Or would you drop a rig? Just want to get a sense of your capital priorities in a potential lower price environment?

Jason Pigott: Yes. Again, as I mentioned, our goal is to be free cash flow positive next year. A lot of variables right now that are kind of difficult to calculate as far as whether we build DUCs or not complete wells. Again, we’ve got good line of sight on ways that we can reduce our corporate breakeven pretty close to $50 with continued efficiencies, service cost reduction. So I’d say it’s too early to do those game scenarios right now, but it’s something that we’ll — we have flexibility to adapt because both drilling services contracts and completion contracts expire in March. So we’ve got all the flexibility we need to adapt as needed.

Operator: As there are no further questions at this time. I would now like to turn the call back over to Mr. Ron Hagood. Please go ahead.

Ron Hagood: We appreciate your interest, and thank you for joining us this morning. This concludes today’s call.