VTLE - NYSE

Good day, ladies and gentlemen, and welcome to Vital Energy's Second Quarter 2025 Earnings Conference Call. My name is Danny, and I will 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 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 afternoon. The 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 thanks for joining us. Second quarter results show solid execution on our optimization plan, delivering sustainable cost reductions that strengthen our outlook for adjusted free cash flow in the second half of this year and beyond. This morning, we'll cover 3 key areas. First, the progress we've made in reducing expenses in a sustainable way; second, recent operational achievements, including our successful J-Hook wells and how they can enhance our inventory; and third, our outlook for the second half of the year where large, high-quality well packages are expected to drive meaningful debt reduction. Let's start with a look at the second quarter. We posted strong results, delivering consolidated EBITDAX of $338 million and adjusted free cash flow of $36 million. Total production and oil volumes came within our guidance range even after accounting for weather- related impacts and temporary curtailments. On average, these factors reduced daily production by 780 barrels of oil equivalent per day with roughly 500 barrels of that being oil. Capital for this quarter came in at $257 million, above the high end of our guidance. That increase was driven by 2 factors. First, we accelerated $11 million of activity from the third quarter. This move helped us solidify the turn-in-line timing for the 38 wells we'll bring in over the next 2.5 months. Second, we saw $13 million in drilling cost overruns. The technical challenges behind those overruns have been resolved, and we're now seeing improved performance and cost consistency on newer wells. Overall, we made strong progress on capital savings initiatives this quarter. executed 3 horseshoe wells using water- based fluids instead of oil-based mud, saving $5 per foot. We improved our completion stage architecture, reducing pumping cycle times by 9%, saving $13 per foot. We shaved a day off our drill-out cycle time in the Delaware Basin, marking a 30% improvement in drillout speed, saving $9 per foot. These changes generated savings in the quarter, improved operational efficiency and will reduce our per well cost going forward. On the capital efficiency front, we continue to push the envelope in drilling and completions. This quarter, we drilled the 9 longest wells in our company's history, including our longest lateral ever at 16,515 feet. and set new company Delaware Basin records for the most feet drilled in a single day and the most feet completed in a week. We also achieved a major milestone in our effort to extend lateral lengths through innovative well designs. In Midland County, we drilled 6 of our 12 Horseshoe wells during the quarter. Since then, we've drilled 5 more and expect to finish the 12th in the coming days, which we believe is the first time any company in our industry has drilled a stacked horseshoe development like this one. We also successfully completed our first 2 J-Hook wells, turning 3 wells into 2, fully developing the resource and saving millions in drilling capital. Looking ahead, we estimate that around 130 of our 10,000-foot straight locations can be converted into 90 J-Hook locations at 15,000 feet each. This optimization lowers WTI breakevens by about $5 per barrel across the 1.3 million completable lateral feet tied to these locations. We have also continued to make great progress optimizing our cash costs. When we closed the Point acquisition late last year, our lease operating expense run rate was between $115 million and $120 million per quarter. Through the renegotiation of service contracts, optimized chemical usage, more efficient power generation and the consolidation of lease operator routes, we delivered an average of less than $111 million per quarter over the past 3 quarters. These sustainable savings will deliver an incremental $25 million in cash flow per year from our efforts. At the end of the second quarter, we took additional steps to streamline employee and corporate expenses. This aligns with our shift from an acquisition-focused strategy to one that's focused on optimizing the assets we already have. As part of that effort, we reduced our combined employee and contractor headcount by about 10%. While these decisions are never easy, they're already making an impact, driving nearly a 20% reduction in total G&A expenses when compared to the average of the past 3 quarters. Net debt at the end of the second quarter rose by $8 million as we reduced our net working capital by $41 million, in line with our expectations for the quarter. For the quarter, we recorded a noncash pretax impairment on our oil and gas properties, along with a valuation allowance against our federal net deferred tax asset. Details can be found in the press release. Neither the impairment nor the valuation allowance impact our ability to generate adjusted free cash flow, reduce debt or continue to utilize our NOLs. We are well positioned to generate substantial adjusted free cash flow in the second half of 2025. We expect to turn in line 38 wells, all of which should be producing by October. We are maintaining capital discipline and remain on track to meet the midpoint of our capital investment guidance of $875 million. We have also closed an additional $6.5 million noncore asset sale to further support our debt reduction goals. Our capital discipline, combined with increased production is expected to drive adjusted free cash flow in the back half of the year, resulting in net debt reduction of approximately $25 million for the third quarter and around $185 million in total for the remainder of the year. Our debt reduction outlook is supported by a solid hedge position. We swapped roughly 95% of our expected second half oil production at an average price of $69 per barrel. We've also hedged about 85% of our expected natural gas production and 75% of our ethane and propane volumes. We remain firmly committed to our optimization strategy focused on generating adjusted free cash flow and reducing debt to build long-term value for our shareholders. Operator, please open the line for questions.

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

For my first question, I wanted to focus on your trajectory into 2026 and how the capital efficiency you're attaining in the second half projects in 2026.

Sorry, Derrick, could you repeat the last a little bit there?

Sure. So I wanted to focus on your trajectory -- production trajectory into 2026 and how the capital efficiency you're attaining in the second half projects in 2026.

Derrick, this is Katie. Yes, we're really excited about the cost reduction work that we've been able to achieve year-to-date. We put into the slide deck this quarter the progress that we're making between the first half and the second half of the year. You can see a lot of improvement in our capital efficiency in the second half, and that's really being driven by some of these larger packages that we're bringing online. We've successfully extended lateral length across really all the development in the second half and then really applied some great drilling best practices that came out of the second quarter. Some of the capital overspend that we saw on wells that we drilled in May really impacted how we're thinking about casing design, how we're thinking about our fluid management system. It's helping support some of the standard operating procedures that we've put in place, and it's carried into the third quarter really successfully so far. Over the last 6 weeks, we've drilled some of our fastest wells, some of the best cycle time wells and certainly some of the lowest dollar per foot so far. So we're starting the second half strong. As we think about going into '26, many of our long contracts are starting to expire. We have an opportunity to go to market with most of our large contracts on both the drilling and completion side, which we believe to be good timing from an oilfield services market standpoint. We also are continuing to focus on our dollar per foot efficiencies. Like Jason said, we've really pivoted into cost optimization, and that continues to be our focus. So you can see on the capital slide that we have now added our lowest dollar per foot well to help give context to where we're headed as we continue to drive costs down.

Terrific. And Katie, maybe you lean in just on the cost accomplishments on Slide 5. Could you offer some color on what's assumed in the upper and lower ends of your LOE projections? And separately, maybe speak to some of the other cost initiatives you currently are pursuing that aren't reflected in the guidance for the second half?

You bet. If you look at the Slide 5, we're covering both LOE and G&A. What we're representing there is a shift in the second half on our G&A spend. We believe that to be sustainable at a fair run rate on the go forward. For LOE, we've made really just a ton of progress since we first stepped into the Delaware following the Point asset late last year. We've been successful at eliminating costs every quarter. That dollar per quarter run rate that we're showing in the second half of '25 reflects the progress that we've made on shifting away from rental generators and going to high line power. There's a lot of compression and chemical optimization that's included in there. And then we're really working through using our joint asset scale effectively in our bid process and working through every line item of our LOE statement. So made good progress year-to-date. Those ranges reflect continuing the improvements that we've made today. As we think about getting into '26, an area of focus for us is really on workover spend. We're investing this year in building out our gas lift infrastructure and it's supporting a large switchover campaign to get off of our high-cost ESP and transition to a more LOE effective gas lift type. And so we'll be able to see the benefit of that in workover as we get into '26. There's still some opportunity beyond what we're showing in the second half here for cost reduction. That's really driven by, again, improvement in failure rate, but then shifting to a more efficient lift type. So excited to continue to work on it as we get into next year. These ranges again, just reflects the work that we've done so far in 2025.

Next question comes from the line of Noah Hungness with Bank of America.

For my first question here, I was just wondering if you could maybe talk about the production cadence kind of heading into '26 in 1Q and 2Q of '26, just considering that as you pull activity forward and you're planning to turn in line your second half, what, 25 wells by early October, what does the beginning of '26 really look like from a production perspective?

We're really excited about the second half. We have 38 wells left to bring online this year. So absolutely focused on getting those large packages online. We have 3 that contribute to 33 of the 38. So hyper focused on the delivery of that. Some of the capital acceleration that we talked about in Q2 was really to derisk the timing, but not necessarily to accelerate. So it was taking operations off critical path to ensure that we could deliver the plan in the second half. We're keeping our third quarter and fourth quarter volume flat to previous guide, definitely progressing along the timing plan as we expected. Because of that flush production, we would expect to exit the year high in the fourth quarter, and it will come down a little bit as we get into '26 just because of the timing of that turn-in-line cadence. So not yet ready to talk about full year '26, but certainly excited about bringing on some really great wells in the second half of this year.

Got you. I appreciate that color. And then could you maybe talk about -- you guys have been able to consistently sell off parts of your noncore acreage that's been a source of funds this year, even given the volatile commodity price, how do we think about the potential cadence of those -- of potential noncore asset sales moving forward? Is something that we've seen kind of year-to-date a pace that you guys could keep moving forward? Or is it something that's more opportunistic and it will just come depending on how the market?

Yes. I'd say we've been more opportunistic with these. We're always looking to optimize our portfolio. We're high-grading our near- term development plans, and we're monetizing assets that are not in our near-term plans. we're being paid for inventory on wells that we won't develop to further out in the future. So I'd say there's no set goal, but there is a market out there where people are looking to continue to buy assets. For us, these are just helping to accelerate our debt reduction goals, which create more value for our shareholders over time. But we want to -- if we're getting good prices, we'll execute on those, and that's what you've seen over the last couple of quarters.

Next question comes from the line of Jon Mardini with KeyBanc.

You remain well hedged for the back half of this year that are -- those hedges are well in the money, and it's helping to fund the net debt reduction as well. But just looking out to 2026, how do you see that net debt or leverage trending given the strip that's, call it, $8 or so below the 2025 hedges that you have in place?

Well, for '25, like you said, we're pretty well hedged, and we've talked about our free cash flow and debt paydown. In '26, we would -- we haven't come out with the guidance, but we would expect to continue to pay down debt. So it should be heading down, not higher.

Our corporate breakeven right now for '26 with the hedges we have in place is below $55 a barrel. We tend to be hedged a year out in advance around 75%. So I wouldn't be surprised if you saw us adding third quarter hedges for '26, which will continue to further reduce that corporate breakeven to the low 50s.

Okay. That's helpful. And just on your development program in 2025, the first half is kind of heavily weighted towards these 2 to 6 well pads, while the second half is heavier in these larger scale developments. Just curious about the opportunity set that you have to allocate capital towards more of these larger scale developments into 2026. I know it's a bit early, but any kind of details you have on that would be helpful.

So you're right, we had some smaller wells per pad early in the year. A large part of that was driven by the remaining development that we captured in Howard County. So we brought online kind of the last -- the most competitive inventory that was up there. That was part of why we had several 2, 3-well pads. As we get into the second half, we have 8- to 13-well pad development that's going on. So really excited about the capital efficiency opportunity that's driving. And we're seeing a lot of success with that development plan so far as we're working through it. So we've been able to apply simul-frac because of these larger developments. We've been able to really capture some good drilling cycle time efficiency. It's certainly driving as we think about development planning for next year. And the inventory depth as we move into early '26 supports continuing some of these really efficient development strategies. So I would expect that to carry into the year next year.