Vital Energy, Inc. (NYSE:VTLE) Q2 2024 Earnings Call Transcript

Vital Energy, Inc. (NYSE:VTLE) Q2 2024 Earnings Call Transcript August 8, 2024

Operator: Good day, ladies and gentlemen, and welcome to Vital Energy, Inc. Second Quarter 2024 Earnings Conference Call. My name is Dee and I will be your conference operator for today. At this time, all participants are in a 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 to you 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 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 on our website at www.vitalenergy.com. I’ll now turn the call over to Jason Pigott, President and Chief Executive Officer.

Jason Pigott: Good morning. And thank you for joining us today. Vital Energy remains focused on maximizing free cash flow by integrating our recent acquisitions, adding low break-even inventory and maintaining a strong capital structure. Our team continued the trend of strong production results during the second quarter, with total and oil production set company records as packages turned in line during the quarter and both the Midland and Delaware Basins are exceeding expectations. Strong production helped drive free cash flow of $45 million for the quarter, which we used to reduce debt. We are increasing our full-year 2024 total production guidance midpoint to 129,000 barrels of oil equivalent per day to incorporate both outperformance of our current operations and for our acquisition of Point Energy Partners, which is expected to close at the end of the third quarter.

We are also increasing our full-year 2024 oil production guidance, raising the midpoint to 60,000 barrels of oil equivalent per day due to the outperformance of wells in the Delaware Basin and Howard County, as well as expected fourth quarter volumes from the Point acquisition. Turning to capital, investments in the quarter were almost $30 million below the midpoint of our guidance range. This was primarily based on activity timing, and we expect these dollars to shift to the third quarter. For full year, we have adjusted our capital investment midpoint to $845 million from the previous midpoint of $800 million, incorporating the expected fourth quarter capital for Point. For the quarter, operating expenses were higher than projected at $966 per BOE.

In our May call, we shared that LOE on the acquired assets was higher than expected due to the increased water production and H2S after close. Since May, we have reduced our run rate by nearly $4 million per month, which was accomplished by shutting in uneconomical wells and improving chemical spend across both basins, and applying new power generation capabilities in the Midland. This, along with additional optimization efforts, led to exiting Q2 at approximately $895 per BOE. While Q1 and Q2 costs were driven higher due to delayed billing throughout the acquisition transition process, we crossed over the peak in April and subsequently reduced run rate throughout the quarter. We expect second half LOE to remain around $895 per BOE on our base business, inclusive of lower production volumes for the third quarter.

In the fourth quarter, we expect total company LOE to increase to around $935 per BOE when the Point acquisition closes. We are intensely focused on optimizing operations and creating additional value from our acquired properties. We have been successful in lowering capital cost and improving productivity in the Delaware Basin. Since closing our initial acquisition in the basin, we have recognized capital cost reductions of 12% and believe we have line of sight to another 5% reduction in the future. Our strategy of widening spacing versus the previous operator continues to deliver productivity gains on our southern Delaware position, further enhancing capital efficiency. Over the past five years, our acquisition strategy has significantly bolstered our oil-weighted inventory, now providing approximately 10 years of development at our current pace.

Recently, we have taken further steps to enhance our portfolio of low break-even locations through both organic growth and the strategic acquisition of Point Energy. This organic growth has been primarily driven by the successful implementation of long lateral horseshoe wells across our leasehold. By developing these wells in the Midland and Delaware Basin, we’ve converted 84 short lateral locations into 42 long lateral horseshoes, reducing the break-even to below $50 for 30 of these locations. Additionally, we’ve identified and added 77 new long lateral horseshoe locations to our inventory that were previously excluded due to the economics of short laterals. In our ongoing efforts to strengthen our inventory, we have initiated a testing program in the Barnett formation, recognizing an opportunity to add more low-cost locations.

The associated activities, capital expenditures, and production have been fully integrated into our updated capital and production guidance. We anticipate sharing further details on this promising development in the coming months. Moreover, we are closely monitoring the performance of our recently turned-in-line Wolfcamp C wells, which were placed on ESP after two months of free flow. The early results are promising and we look forward to providing more information on this potential inventory as we gather additional production data. Thanks to these organic inventory additions and our acquisition of Point Energy assets, which expand our scale and sub $50 breakeven inventory, our portfolio is now deeper and more resilient than ever before. Maintaining a strong capital structure is key to executing our long-term value proposition and free cash flow generation capabilities.

Our strong balance sheet and liquidity position facilitated the purchase of Point on our credit facility, driving significant per share accretion for our shareholders. To support debt repayment related to the acquisition, we added approximately 9 million barrels of oil hedges in 2025 and now have more than 15 million barrels hedged in 2025 at almost $75 per barrel. Vital Energy is exceptionally well positioned for the future. Our strategy is focused on building durability in both well economics and our capacity to deliver free cash flow through volatile oil price cycles. We have built scale in both the Midland and Delaware Basins. We have demonstrated great progress in improving operations in both basins and are pursuing multiple new initiatives to improve both our capital costs and operating expenses.

We have built a decade of oil weighted inventory, 45% of which breaks even below $50 per barrel. We have a strong capital structure with no term debt maturities until 2029. In short, we are well equipped to deliver long-term value creation and sustain free cash flow generation for years to come. Operator, please open the line for questions.

Q&A Session

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

Neal Dingmann: Jason, my first question is just, again, when I look at the 10 plus years of project inventory out there, specifically it looks like you all boosted, I think, it’s around 77 total locations and even a number of $50 breakeven as a result of the organic horseshoe addition. So my question is just what areas are you planning on targeting for these incremental potential wells and could you speak to how you think about spacing and completion techniques around these type of wells versus the typical horizontal?

Jason Pigott: That’s a big priority for us, Neal. We target this technique anywhere we have short laterals. It’s well known that drilling long laterals are more efficient. This technique is a unique way for us to drill longer laterals on our acreage position. On slide 6, there’s a map where we highlight all of the current horseshoe locations. A great example of how we use this technique and leaning to it was with Point specifically. We have 16 wells, which we believe created a unique value proposition as part of that transaction process. And when you think about spacing, we plan these wells just like we would straight wells that are 10,000 feet long. So the inbound lateral, so you go away from your starting point and when you come back, you come back on that same spacing that you would traditionally have. So whether you develop on six wells per section or four wells per section, we designed that return lateral on that spacing.

Neal Dingmann: My second question is just really when you look at future D&C costs, you all definitely have reduced some notable costs during the recent quarters. I’m just wondering, can you speak to what current steps are taken to further reduce the cost? And I’m just wondering, as these costs are reduced, maybe speak to what the impact might or might not be on the cycle times around the wells?

Jason Pigott: The team has done a great job of getting the cost down. Part of it is just operating in these new areas. And I’ll turn it over to Katie. They’ve done a great job just looking at contracts and things like that, but they’ve made tremendous progress like you suggest.

Katie Hill: We’re continuing to drive costs down really both through operating efficiency and through a softening in the service market. We’ve already reduced Delaware costs by about 12% per well since closing on those acquisitions. And we have line of sight on an additional 5% in that area. Strategically, we tend to stagger our long term contracts to dampen operating cost fluctuation. However, we’re currently negotiating one of our four base rigs for an extension in Q3, and we’ll have an additional two contracts in negotiation towards the end of the year. So, we’ll be able to take advantage of the current service market. It’s another reason that we’re really excited about the Point acquisition as well. We have an opportunity to add incremental activity towards the end of the year, which is a great time again with where the market is.

And I think what’s important to highlight is our capital efficiency has allowed us to add activity this year, like Jason mentioned in the opening comments without a guidance change. Great work across the team. We’re excited to continue to get these Delaware assets integrated and to continue to work costs down.

Operator: Our next question comes from the line of Zach Parham with J.P. Morgan.

Zach Parham: I wanted to follow-up on the horseshoe wells. Can you just talk about how you view the economics of these new horseshoe wells that you added versus your current inventory and maybe give us some color on how much of the program over the next few years could be horseshoe laterals versus normal 2-mile development.

Jason Pigott: Look at the horseshoe wells, we’ve lumped everything into what is in that sub $50 breakeven bucket. On slide 5 of the deck, what we highlighted is that we’ve gone from 275 wells with sub $50 breakevens to 395 wells with sub $50 breakevens. Those horseshoe shaped wells are evenly distributed amongst, what we call, our skyline of return as wells as we sort and rank them. So they’re evenly distributed in there. The Delaware Basins with the higher productivity and the lower capital costs are also distributed in there. That’s the big challenge for the team going forward, is how do we optimize our budget for 2025? What we try to do is drill the highest return wells as quickly as we can. There are going to be wells that we co-develop that maybe have a lower return.

But what we’re really excited about is we’ve extended that inventory of sub $50 breakeven, as I mentioned, to 395 wells. We drill roughly 90 wells per year. That’s what we’d forecast for next year. So we’ve extended that that life of sub $50 breakeven wells – that’s almost four years now – over the last couple of years. So the team is really seeing this new technique and technology to reduce our breakevens and testing new zones and targets to bring in wells that have lower breakevens as well. So they’re doing a great job. We’ll have more color on it as we get to the budget for 2025.

Zach Parham: And my follow-up. I just wanted to ask on the Barnett. I know you didn’t give a lot of detail there, just that you initiated a testing program. Can you give us your initial thoughts on what you think those wells could cost? I know they’re a little bit deeper, but maybe any thoughts on cost of those wells versus kind of a core Midland Basin well?

Jason Pigott: Majority of our company’s focus has been to extend the quality and length of our inventory, and we’re approaching that on multiple fronts. The Barnett is one example of where we’re trying to bring in inventory at a lower cost. We have multiple Barnett wells that are being tested, as we speak, and starting flow back. These wells will provide great data to help us optimize our completion designs in the future. The first tests are more expensive. We’re coming in and putting – frac-ing one well at a time, and so it’s a less efficient process than our traditional zipper frac. I don’t know that we have a great idea of what the run rate will be in the future. They’ve continued to reduce the cost on every single well they’ve drilled.

One of the things I wanted to highlight is we did put a healthy risk factor on these wells. When you look at our 3Q and 4Q production guidance, it’s inclusive of four tests in new zones that we heavily risked down the production just because they were the first wells of that time for us. If it weren’t for those, our production guidance would be higher at the end of the day. We’ve also absorbed the capital to our [indiscernible], and these are more expensive wells to drill. So, I did want to highlight that. We’ve acquired 17,000 acres in the Barnett that’s not under our existing footprint. It’s competitive, but we think we’re going to have a great opportunity in the future. We look forward to updating you on these wells as we get them in, but it’s hard to say what the cost will be because, again, they’re the first tries, seems to be doing a great job, but we’ll have more guidance when we’ve got these wells done and we get to a program that is kind of more predictable and steady versus the one-off wells that are higher cost just because they’re drilled in isolation.

Operator: Our next question comes from the line of Paul Diamond with Citi.

Paul Diamond: Just a quick one following up on the Barnett. Outside of economics, what are your thoughts on the opportunity set there from notion of locations or additional inventory adds?

Jason Pigott: We’re really excited about it. It’s very early. Like I mentioned, we bought 17,000 acres. These wells are being developed at three to four wells per section. That’s one of the things the industry is working through is what is the right spacing, which will ultimately drive well count. That acreage I described is above and beyond what we would show on a map. Because it’s competitive, we don’t have it out there for you today. There are other places where Oxy is drilling. They’ve drilled two wells now just west of our western Glasscock position, so there’s an additional potential underneath areas like that. Because it’s so competitive right now, we’re kind of keeping our information tight, but it is something – I think SM came out with a report on some of their wells.

There’s some good excitement. These are not like the Barnett wells around the Dallas area. They’re oily wells with low water yields, so it’s going to be a great opportunity for us in the future to add low cost inventory.

Paul Diamond: Just one quick one. On slide 5, you talk about cadence of wells per rigs per year. With the additional rig being added in in the fourth quarter with Point probably being kept on a run rate basis, do you expect any kind of shift in those numbers, or is that kind of operational split between Midland, Delaware and just that rig cadence that’s pretty sticky, or should we expect some movement there with the efficiency gains?

Jason Pigott: The teams are working that, as we speak. As we mentioned, we’ve got great opportunities with things like the horseshoe shaped well that have low breakevens, Delaware wells, as we’ve highlighted in the past, with wider spacing, they’ve been outperforming by 45%. Katie and her team are continuing to reduce the cost out there as we get more experience drilling and completing in that area. The economics are definitely positive for both the Midland area and the Delaware. The Delaware, you get a little bit more expensive wells, but higher productivity. The Midland basin, a less expensive well, a little less productivity, and the team is just working through balancing all that right now. I would say there’s a bent that we would have more Delaware activity because – again, it’s both cost savings and higher production, but we’ll have better guidance for you in February.

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

Noah Hungness: I just wanted to ask here again on the U laterals. What kind of runway do you think you guys have for improving the cycle times and reducing those costs, just given they’re relatively newer than a more standard two-mile lateral?

Jason Pigott: If you’ll look on slide 6 at the bottom, one of the things we did break out this time was the cost and how that saves you money versus drilling two individual short lateral wells. I’ll turn it over to Katie. She can give you a little more color on efficiency gains and how those are working for us.

Katie Hill: When I think about the horseshoe wells, I would consider those to be an alternative well design for us that can improve economics through lateral extension. From a cost reduction opportunity, it looks really similar to our other Delaware and Midland capital efficiency projects. We have a little bit more opportunity in the Delaware because we’re newer in that part of the basin, but generally speaking, the horseshoe laterals would see the same type of efficiency and service cost improvements that we would expect with a straight conventional design.

Noah Hungness: I guess I was wondering too, as you guys start to really implement these at a larger scale, do you think you’ll be able to take any learnings and improve the cycle times for these U laterals?

Katie Hill: We see really similar cycle times with this design as we do with a more conventional straight lateral steering strategy where we may see expansion and improvement opportunity as we continue to test this design in alternative zones. We’ve already proven that we can execute in the Delaware and the Midland, have high confidence in our ability to deploy it. I think that, again, the cycle time and capital efficiency opportunity is really across all of these well designs. I wouldn’t just limit it to how we’re thinking about the horseshoe application.

Jason Pigott: There are definitely going to be performance improvement opportunities. When we were drilling the Allison pads [ph], every single well was getting faster. So, the more we do it, we’ll continue to get costs down and improve our breakevens.

Noah Hungness: As my second question, Katie, I was just hoping you could expand a little bit on your conversations with the service providers. As you guys are in negotiations with contracts now, could you talk about how those conversations are today and how that’s changed versus maybe a month ago?

Katie Hill: The market right now is experiencing consolidation, as you know. The opportunity for us is we’re able to grab high spec, technically advanced rigs and frac crews, which is great. We’re always looking to enter into stable long-term partnerships that dampen any impact from volatile pricing and are absolutely working to make sure that we enter into pricing agreements that can hold long-term and are not tied completely to volatility of the commodity market. I would say, over the last month, we’re seeing probably just a consistent shift from mid-year 2023. That was really the peak of some of the inflationary impact. Again, we have a good opportunity right now in the second half to take advantage of the market pricing today with our incremental rig and frac crew towards the end of the year.

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

John Abbott: Jason, it sounds like the focus here really is on your assets that you have in hand and also on reducing the borrowings under your revolver over probably the next year. I guess the question is, at this point, how do you view the importance of size and scale at this point in time for Vital Energy?

Jason Pigott: For us, we’re going through a little bit of a pivot here, I believe. When we look at the M&A landscape, there are less and less opportunities out there that will have inventory that will jump ahead of the low breakeven inventory that we’ve added today. I see us putting a little bit of a pause on some of the M&A compared to where we were in the past. We’re really going to focus more going forward on cash flow generation. We’ve got great opportunities with things like the simulfrac. We can pump lower fluid loadings in some of our wells to continue to get capital costs down. On the LOE front, we’re looking at infrastructure projects, work over expenses, chemical expenses that will continue to prove our LOE. There’s exciting things like our machine learning process for submersible pumps that we’ve tested in Howard County to move that over to the Delaware basin.

A lot of the LOE cost increase you see for that 4Q as a result of Point is the Point team – a lot of workovers and resizing of pumps, and we believe things like our AI technology will allow us to extend pump lives there and reduce operating expenses over the long haul. So that is going to be the higher focus for us really in this the next year or so is just improving cash flow, attacking it on the capital front, the LOE front. I don’t think the exit rate that we’ve got in there for 4Q this year is representative of where we’re going to be long term. And all of these things are going to come together. But just the landscape, I don’t see as many opportunities where inventory can jump ahead of what we’ve got today, which is a requirement for any future asset.

We’re really excited about Point because it’s in our backyard and had low breakeven wells. And we’re using horseshoe technology to improve economics out of that asset, but I believe there will be a little bit of a shift and much more emphasis on free cash flow growth and generation over the next year.

John Abbott: And just a really quick follow-up, for your hedges as you sort of think to 2025, you already have some hedges in place. How do you think about the extent that you want to be hedged next year just given commodity volatility?

Jason Pigott: If you look at our hedge table, you can see that we usually are putting hedges on when oil gets to $75. In the past, we’ve tended to be 75% hedged a year in advance. What I believe the team has done a good job is just work – when we see volatility and prices rising, we’ll layer on some hedges, but they’ve been at that $75 range. You saw the big jump in our heads position. That was a result of knowing that we were in the hunt on the Point acquisition and we wanted to lock in more free cash flow and the economics of that deal. So we’re in a higher – ultimately, at a higher hedge position than we would normally be in, but we wouldn’t hesitate to add hedges if we see oil spikes and put on additional layers in that $75 range.

Operator: That concludes our Q&A session. I will now turn the conference back over to Mr. Ron Hagood for closing remarks.

Jason Pigott: Thank you for joining us. As always, we appreciate your interest in Vital Energy. And this concludes this morning’s call.

Operator: Ladies and gentlemen, that concludes today’s call. Thank you all for joining. You may now disconnect.