Q2 2024 Vital Energy Inc Earnings Call

August 8, 2024

Unknown Executive: 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. I will now turn the call over to Jason Pigott, President and Chief Executive Officer.

Unknown Executive: 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.

Unknown Executive: In addition, we'll be making reference to non-GAAP financial measures.

Unknown Executive: Reconciliation to gap 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.fidalenergy.com.

Jason Poggett: I'll now turn the call over to Jason Poggett, President and Chief Executive Officer. 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. Total production and oil production set company records as packages turned in line during the quarter in 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.

Jason Pigott: Our team continued the trend of strong production results during the second quarter. Both total production and oil production set company records as packages turned in line during the quarter in both the Midland and Delaware basins exceeded 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.

Jason Poggett: We are increasing our full year 2024 total production guidance midpoint to 129,000 barrels of oil equivalent per day to incorporate both out performance 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 dollars below the midpoint of our guidance range.

Jason Pigott: 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. For the 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 per point. For the quarter, operating expenses were higher than projected at $9.66 per BOE.

Jason Poggett: This was primarily based on activity timing, and we expect these dollars to shift to the third quarter. The 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 BLE. In our May call, we shared the LLE 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 on economical wells and proving chemical spend across both basins and applying new power generation capabilities in the Midland.

Jason Pigott: Since May, we have reduced our run rate by nearly $4 million per month, which was accomplished by shutting in uneconomical wells, improving chemical spend across both basins, and applying new power generation capabilities in the Midlands. This, along with additional optimization efforts, led to exiting Q2 at approximately $8.95 per BOE, subsequently reducing run rate throughout the quarter.

Jason Poggett: This, along with additional optimization efforts, led to exiting Q2 at approximately 895 per BLE. While Q1 and Q2 costs were driven higher due to delayed billing throughout the acquisition transition process, we crossed over the peak in April. Rural, and subsequently reduced run rate throughout the quarter. We expect second half LLE to remain around 8.95 per BLE on our base business inclusive of lower production volumes for the third quarter. In the fourth quarter, we expect total company LLE to increase to around 9.35 per BLE when the point acquisition closes. We are intensely focused on optimizing operations and creating additional value from our acquired properties.

Jason Poggett: 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 5 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.

Jason Pigott: 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. In our ongoing efforts to strengthen our inventory, we have initiated a testing program in the Barnett Formation. Thanks to these organic inventory additions and our acquisition of point energy assets, which expand our scale and sub $50 breakeven inventory. Maintaining a strong capital structure is key to executing our long-term value proposition and free cash flow generation capabilities.

Jason Poggett: 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 have 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-lateral. 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.

Jason Poggett: 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 Wolfkant Sea Wealth, 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 break-even 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.

Jason Poggett: 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. Neal 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.

Jason Pigott: Our strong balance sheet and liquidity position facilitated the purchase of a point on our credit facility, driving significant per share accretion for our shareholders. 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.

Jason Poggett: 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.

Jason Pigott: 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.

Jason Poggett: In short, we are well equipped to deliver long-term value creation and sustained free cash flow generation for years to come.

Unknown Executive: Operator, please open the line for questions. Thank you. We will now begin the question and answer session. If you have value and would like to ask a question, please press star one on your telephone keypad to raise your hand and join a queue. If you would like to withdraw your question, simply press star one again. If you are called upon to ask your question or listening via loud speaker on your device, please pick up your handset and ensure that your phone is not on mute when asking your question. We do request for the day session that you please limit the one question and one follow-up.

Operator: Thank you. We will now begin the question and answer session. If you have dialed in and would like to ask a question, please press star 1 on your telephone keypad to raise your hand and join the queue. If you would like to withdraw your question, simply press star 1 again. If you are called upon to ask your question or listen via the loudspeaker on your device, please pick up your handset and ensure that your phone is not on mute when asking your question.

Unknown Executive: Again, press star one to join a queue, and their first question comes from the line of Neil Dingman from Two Securities.

Operator: We do request for today's session that you please limit to one question and one follow-up. Again, press star 1 to join the queue. And our first question comes from the line of Neal Dingmann from Truvia Securities. Please go ahead.

Neil Dingmann: Please go ahead.

Neal Dingmann: Morning, and thank you all for the time. Jason, my first question is just, you know, 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 breakevens as a result of the organic horseshoe addition. So my question is just what areas would you, 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 types of wells versus the typical horizontal?

Neil Dingmann: Morning. Thank you all for the time. Today's my first question is just, you know, again, when I look at the 10-plus years of project inventory out there. So, simply, it looks like you all boosted. I think it's around 77 total locations and even a number of $50 break even as a result of the organic horseshoe addition.

Jason Poggett: So, my question is just, what area is, 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.

Unknown Caller: Thank you. Bye.

Jason Poggett: That's a big priority for us, Neil. We target this technique anywhere we have short laterals. It's well known that drilling long laterals is more efficient.

Jason Poggett: This technique is a unique way for us to drill longer laterals on our acreage position. On slide six, 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 points 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 really, we plan these wells just like we would straight wells that are 10,000 feet long. So, the inbound laterals, you go away from your starting point.

Jason Pigott: On slide six, 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 points specifically. We have 16 wells, which we believe creates a unique value proposition as part of that. We really 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 design that return lateral on that spacing.

Jason Poggett: 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 design that return lateral on that space.

Neil Dingmann: Great details.

Neal Dingmann: Great details. And then my second question is just, really, when you look at future DNC costs, you all definitely have, you know, 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, you know, I'm just wondering, as these costs are reduced, maybe you could speak to what the impact might or might not be on the cycle times around the wells. Thank you.

Neil Dingmann: And then my second question is just really when you look at future DNC costs, you all definitely have reduced some notable costs during recent quarters. I'm just wondering, can you speak to what current steps are taken to further reduce the cost? And, you know, I'm just wondering if these costs are reduced?

Neil Dingmann: Maybe speak to what the impact might or might not be on the cycle times around the world.

Jason Poggett: Thank you.

Jason Poggett: Team has done a great job of getting the cost down. Part of it is just operating in these new areas.

Unknown Executive: The team has done a great job of getting the cost down. Part of it is just operating in these new areas, looking at contracts and things like that, but they have made tremendous progress, like you suggested.

Katie Hill: 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 said.

Katie Hill: Hi, good morning, Neal. 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 cost by about 12% per well since closing on the vacuitions. And we have line of sight on an additional 5% in that area. Strategically, we tend to stagger our long-term contract 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.

Unknown Executive: Strategically, we tend to stagger our long-term contracts to dampen operating cost fluctuations. 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.

Katie Hill: 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 his opening comments, without a guidance change. Great work across the team. You know, we're excited to continue to get these Delaware assets integrated and to continue to work off down.

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

Unknown Executive: Thank you both for the time. Our next question comes to the line of Zach Quarham with JP Morgan. Please go ahead.

Operator: Our next question comes from the line of Zach Parham with J.P. Morgan. Please go ahead. Thank you for taking the time.

Zach Quarham: Thanks for taking about questions. 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 lava rolls versus normal two mile development. Look at the horseshoe wells. We've lumped everything into what is in that sub $50 break-even bucket on slide five of the deck. What we highlighted is that we've gone from 275 wells with sub-$50 break evens to 395 wells with sub-$50 break evens.

Zach Parham: Thanks for taking my questions. 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, you know, give us some color on how much of the program over the next few years could be horseshoe laterals versus normal two-mile development?

Jason Poggett: Those horseshoe shaped wells are evenly distributed amongst our skyline, or what are our return, as well as we sort and rank them. So they're evenly distributed in there. The Delaware basins with the higher productivity and the lower capital cost are also distributed there.

Jason Poggett: That's the big challenge for the team going forward: how do we optimize our budget for 2025? What we try to do is drill the highest return well as quickly as we can. There are going to be wells that we co-develop that maybe have a lower lower return. What we're really excited about is we've extended that inventory of sub $50 break even, as I mentioned, to 395 wells. We drill roughly 90 wells per year. That's what we forecast for next year. So we've extended that life of sub $50 break even wells that's almost four years now over the last couple of years.

Jason Poggett: So the team is really putting this new technique and technology to reduce our break evens and testing new zones and targets to bring in wells that have lower break evens as well. So they're doing a great job.

Jason Poggett: That'll we'll have more color on it as we get to the budget for 2025.

Jason Poggett: Hey Jason, 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, but can you give us your initial thoughts on, you know, what do you think those wells could cost? I know they're a little bit deeper, but maybe any thoughts on the cost of those wells versus kind of a core Midland Basin well. Yeah, a 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.

Jason Pigott: Hey Jason, and my follow-up question. I know you didn't give a lot of detail on the Barnett, just that you'd initiated a testing program, but can you give us your initial thoughts on, you know, what you think those wells could cost? I know they're a little bit deeper, but maybe any thoughts on the cost of those wells versus kind of a core Midland Basin well?

Jason Poggett: 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, fracking one well at a time, and so it's a less efficient process than our traditional zipper fracks. So I don't know that we have a great idea of what the runway will be in the future. They've continued to reduce the cost on every single well they've drilled.

Jason Pigott: Tested as we speak in starting flow back, these wells will provide great data to help us optimize our completion designs in the future. However, the first tests are more expensive. We're coming in and fracking one well at a time, and so it's a less efficient process than our traditional zipper frack. So, I don't know that we have a great idea of what the runway will be in the future. They've continued to reduce the cost of every single well.

Jason Poggett: We also, one of the things I've 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 and 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 current guidance, 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.

Jason Poggett: It's competitive, but we think it's 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 they're going to their first tries. It seems to do 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 costs just because they're drilled in isolation.

Unknown Executive: Thanks for the detail.

Paul Diamond: Our next question comes from the line of Paul Diamond with the City. Please go ahead. Good morning, all. Thanks for taking the call. Just a quick one following up on the Barnett.

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

Jason Poggett: So outside of the economics, were your thoughts on kind of the opportunity to set there from the notion of locations or additional inventory ads? We're really excited about it. It's very early. We've got, like I mentioned, we've 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. And that acreage is not 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.

Jason Poggett: There are other places where Oxy is drilling. They've drilled two wells now just west of our western glass coct position. So there's additional potential underneath areas like that. But because it's so competitive right now, we're kind of keeping our information tight, but it is something that I think SM came out with a report on some of their wells. There's some good excitement. These are not like the Barnett Well. on the Dallas area.

Jason Poggett: They're oily wells with low water yield, so it can be a great opportunity for us in the future to add low-cost inventory.

Jason Poggett: And you're stood, thanks for clarity, and just one quick one on slide five: you talk about kind of that cadence of wells per rigs per year. And with the additional rig being added in fourth quarter with point and probably being kept in a low rate basis. You expect any kind of shift in those numbers, or is that kind of operational split between Midland, Delaware, and just that rig, you know, that rated that pretty sticky. You should expect some movement there with the efficiency gains teams are the teams are working that kind of as we speak.

Jason Poggett: As we mentioned, we've got great opportunities with things like the horseshoe shape wells that have low break evens. Delaware wells, as we've highlighted in the past, with wider spacing. They've been outperforming by 45%. Katie inner team are continuing to reduce the cost out there as we get more experience drilling and completing in that area. So the economics are definitely positive for both the Midland area and the Delaware, and the Delaware you get. And a little bit more expensive wells, but higher productivity; and the Midland basin, a less expensive well, a little less productivity, and the team is just working through balancing all that right now.

Paul Diamond: I would say there's a bent that we would have more Delaware activity because the been both cost savings and higher production, but we'll have better guidance for you in February. Understood.

Paul Diamond: Understood. I appreciate your time.

Noah Hungness: I appreciate your time. Our next question comes from the line of Noah Hungness with Bank of America. Please go ahead. Morning all, I just wanted to ask here again on the you laterals, how what kind of runway do you think you guys have for improving the cycle times and reducing those costs just given their relatively newer than a more standard, you know, two mile lateral.

Paul Diamond: Morning all. 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, you know, two-mile lateral?

Unknown Caller: We're in all

Katie Hill: If you look on slide six at the bottom, one of the things we did break out this time was the cost and how that saves you money versus drilling.

Katie Hill: Two individual short ladder wells, but I'll talk. I'll turn it over to Katie; she should give you a little more color on efficiency games and hello to work before. Hi, good morning Noah. When I think about the horseshoe wells, I would consider those to be an alternative well designed 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 improvement that we would expect with a straight conventional design.

Unknown Executive: 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.

Katie Hill: Well, I guess I was wondering too, as you guys start to really implement these out at a larger scale, do you think you'll be able to take any learning to improve the cycle times for these you laterals. 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 is as we continue to test this design and alternative zones. We've already proven that we can execute in the Delaware and the Midland. It's a high confidence in our ability to deploy it.

Unknown Executive: 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 opportunities as we continue to test this design in alternative zones. We've already proven that we can execute in the Delaware and the Midland with 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.

Katie Hill: I think that again, the cycle time and capital efficiency opportunity is really across all of these well designed. I wouldn't just limit it to how we're thinking about the horseshoe application.

Unknown Executive: There are definitely going to be performance improvement opportunities. When we were drilling the Allison pad, every single well was getting faster. So the more we do it, we'll continue to get costs down and improve our break-evens.

Noah Hungness: We're definitely going to be in performance improvement opportunities. When we were drilling the Alice in Pat, every single well was getting faster. So the more we do it, we'll continue to get costs down and improve our break evens. Gotcha. I really appreciate that.

Paul Diamond: Gotcha. Really appreciate that. And then, as my second question, Katie, I was hoping you could kind of expand a little bit on your conversations with the service providers. As you guys are in negotiations with kind of contracts now, could you kind of talk about how those conversations are today and how that's changed versus maybe a month ago?

Noah Hungness: And then that's my second question. Katie edges, hoping you could kind of expand a little bit on your conversations with the service providers.

Katie Hill: As you guys are negotiations with kind of contracts now, could you kind of talk about how those conversations are today and how that's changed versus maybe a month ago? Yeah. Market right now is experiencing consolidation, as you know, the opportunity for us is we're able to grab high specs, techno, you know, technically advanced rigs and brat 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 the volatility of a commodity market.

Katie Hill: I would say over the last month, you know, we're seeing probably just a consistent shift from mid year 23. That was really the peak of some of the inflationary impact. And 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 Brat crew towards the end of the year.

Katie Hill: That was good.

Unknown Executive: Really appreciate it, guys. Thank you.

Chan Abba: Our next question comes from the line of Chan Abba with Wolf Research. Please go ahead. A good morning, and thank you for taking our questions. Jason, you know, it sounds like the focus here really is on your access that you have in hand and also on reducing the powerings under your revolver. Over probably the next year.

Operator: Our next question comes from the line of John Abbott with Wolf Research. Please go ahead. Hey, good morning, and thank you for taking

John Abbott: Hey, good morning, and thank you for taking our question and also on reducing your DE powerings under your revolver for probably the next year.

Jason Poggett: 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? For us, we're really 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 break even in where they were added today. So I see just putting a little bit of a pause on some of the M&A compared to where we were in the past.

Unknown Executive: There are fewer and fewer opportunities out there that will have inventory that will jump ahead of the low break-even inventory that we've added today. So I see us putting a little bit of a pause on some of the M&A compared to where we were in the past. On the LOE front, we're looking at infrastructure projects, workover expenses, and chemical expenses that will continue to improve our LOE. There are 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.

Jason Poggett: We're really going to focus more going forward on cash flow generation. We've got great opportunities with things like that the Simal Frack. We can pump lower fluid loadings in some of our wells to continue to get capital costs down. The L.O.E. Front. We're looking at infrastructure projects, work over expenses, chemical expenses that will continue to prove our L.O.E. 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 L.O.E. cost increase you see for that 4Q as a result of point is the point team.

Unknown Executive: These statements, including those describing our beliefs, goals, expectations, forecast and assumptions, are intended to be covered by the safe harbor provisions of the private security solidification 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.

Jason Poggett: 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. That is going to be the higher focus for us, really, in the next year. So it's just improving cash flow, attacking it on the capital front, the L.O.E. 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. The landscape I don't see is many opportunities where inventory can jump ahead of what we've got today, which is our requirement for any future asset.

Unknown Executive: In addition, we'll be making reference to non-gap financial measures. Reconciliation to gap 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.fidalenergy.com.

Jason Poggett: I'll now turn the call over to Jason Poggett, President and Chief Executive Officer. 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. Total production and oil production set company records as packages turned in line during the quarter in both the Midland and Delaware Basins are exceeding expectations.

Jason Poggett: We're really excited about Point because it's in our backyard and had low break even 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.

Jason Poggett: I appreciate it. And just a really quick follow-up for your hedge, 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 the commodity volatility?

John Abbott: Appreciate it. And just a really quick follow-up. How do you think about the extent to which you want to be hedged next year, just given the commodity volatility?

Jason Poggett: 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 out performance 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 out performance of wells in the Delaware Basin and Howard County as well as expected fourth quarter volumes from the point acquisition.

Jason Poggett: 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. 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 that they've been at that $75 range. You saw the big jump in our hedge 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.

Jason Poggett: Turning to capital investments in the quarter were almost 30 million dollars 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. The 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 BLE.

Jason Poggett: So we're going to hire ultimately at a higher hedge position than we would normally be in, but I wouldn't hesitate to add the other hedges if we see oil spikes and put on additional layers of that $75 range.

Unknown Executive: Thank you very much for taking our questions.

John Abbott: Thank you very much for taking our questions.

Unknown Executive: Thank you.

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

Jason Poggett: In our may call, we shared the LLE 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 on economical wells and proving 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 BLE.

Ronald Hagood: As always, we appreciate your interest in Vital Energy, and this concludes this morning's call.

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

Jason Poggett: While Q1 and Q2 costs were driven higher due to delayed billing throughout the acquisition transition process, we crossed over the peak in April. Rural, and subsequently reduced run rate throughout the quarter. We expect second half LLE to remain around 8.95 per BLE on our base business inclusive of lower production volumes for the third quarter. In the fourth quarter, we expect total company LLE to increase to around 9.35 per BLE when the point acquisition closes.

Jason Poggett: 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.

Jason Poggett: Over the past 5 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 have converted 84 short-lateral locations into 42 long-lateral horseshoe reducing the break even to below $50 for 30 of these locations.

Jason Poggett: 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-lateral. 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.

Jason Poggett: Moreover, we are closely monitoring the performance of our recently turned-in line Wolfkant Sea Wealth, 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 break even inventory, our portfolio is now deeper and more resilient than ever before.

Jason Poggett: 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. Neal Energy is exceptionally well positioned for the future.

Jason Poggett: 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 sustained free cash flow generation for years to come.

Operator: Operator, please open the line for questions. Thank you. We will now begin the question and answer session. If you have value and would like to ask a question, please press star one on your telephone keypad to raise your hand and join a queue. If you would like to withdraw your question, simply press star one again. If you are called upon to ask your question or listening via loud speaker on your device, please pick up your handset and ensure that your phone is not on mute when asking your question.

Operator: We do request for the day session that you please limit the one question and one follow-up.

Neal Dingmann: Again, press star one to join a queue and their first question comes from the line of Neil Dingman, from two securities. Please go ahead.

Neal Dingmann: Morning. Thank you all for the time. Today's my first question is just, you know, again, when I look at the 10-plus years of project inventory out there. So, simply, it looks like you all boosted. I think it's around 77 total locations and even a number of $50 break even as a result of the organic horseshoe addition. So, my question is just, what area is, 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 Poggett: That's a big priority for us, Neil. We target this technique anywhere we have short laterals. It's well known that drilling long laterals are more efficient.

Jason Poggett: This technique is a unique way for us to drill longer laterals on our acreage position. On slide six, 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 points 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 really, we plan these wells just like we would straight wells that are 10,000 feet long.

Jason Poggett: So, the inbound laterals, 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 design that return lateral on that space.

Neal Dingmann: Great details.

Neal Dingmann: And then my second question is just really when you look at future DNC costs, you all definitely have reduced some notable costs during recent quarters. I'm just wondering, can you speak to what current steps are taken to further reduce the cost? And, you know, I'm just wondering is these costs are reduced?

Jason Poggett: Maybe speak to what the impact might or might not be on the cycle times around the world. Thank you. Team has done a great job of getting the cost down. Part of it is just operating in these new areas.

Katie Hill: 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 said.

Katie Hill: Hi, good morning, Neal. We're continuing to drive cost down really both through operating efficiency and through a softening in the service market. We've already reduced Delaware cost by about 12% per well since closing on the vacuitions. And we have line of sight on an additional 5% in that area. Strategically, we tend to stagger our long-term contract 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.

Katie Hill: 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 his opening comments, without a guidance change. Great work across the team. You know, we're excited to continue to get these Delaware assets integrated and to continue to work off down.

Neal Dingmann: Thank you both for the time.

Zach Quarham: Our next question comes to the line of Zach Quarham with JP Morgan. Please go ahead. Thanks for taking about questions. I wanted to follow up on the horseshoe wells.

Zach Quarham: 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 lava rolls versus normal two mile development. Look at the horseshoe wells. We've lumped everything into what is in that sub $50 break even bucket on slide five of the deck. What we highlighted is that you we've gone from 275 wells with sub $50 break evens to 395 wells with sub $50 break evens.

Zach Quarham: Those horseshoe shaped wells are evenly distributed amongst our we call our skyline or what are our return as well as we sort and rank them. So they're evenly distributed in there. The Delaware basins with the higher productivity and the lower capital cost are also distributed there.

Jason Poggett: 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 well as quickly as we can. There are going to be wells that we co-develop that maybe have a lower lower return. What we're really excited about is we've extended that inventory of sub $50 break even as I mentioned to 395 wells. We drill roughly 90 wells per year.

Jason Poggett: That's what we forecast for next year. So we've extended that that life of sub $50 break even wells that's almost four years now over the last couple of years. So the team is really putting this new technique and technology to reduce our break evens and and testing new zones and targets to bring in wells that have lower break evens as well. So they're doing a great job.

Jason Poggett: That'll we'll have more color on it as we get to the budget for 2025.

Jason Poggett: Hey Jason, 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, but can you give us your initial thoughts on, you know, what do 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 will. Yeah, a 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.

Jason Poggett: So I don't know that we have a great idea of what the runway will be in the future. They've continued to reduce the cost on every single well they've drilled. We also, one of the things I've 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 and new zones that we heavily risked down the production just because they were the first wells of that time for us.

Jason Poggett: 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 current guidance 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 it's 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 they're going to their first tries.

Jason Poggett: It seems to do 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 costs just because they're drilled in isolation.

Zach Quarham: Thanks for the detail.

Paul Diamond: Our next question comes from the line of Paul Diamond with the city. Please go ahead.

Jason Poggett: Good morning, all thanks for taking the call. Just a quick one following up on the Barnett. So outside of the economics, were you thoughts on kind of the opportunity to set there from the notion of locations or additional inventory ads? We're really excited about it. It's very early. We've got, like I mentioned, we've bought 17,000 acres. These wells are being developed at three to four wells per section. That's one of the thing the industry is working through is what is the right spacing, which will ultimately drive well count.

Jason Poggett: And that acreage is not 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 glass coct position. So there's additional potential underneath areas like that. But because it's so competitive right now, we're kind of keeping our information tight, but it is something that I think SM came out with a report on some of their wells.

Jason Poggett: There's some good excitement. These are not like the Barnett well, on the Dallas area. They're oily wells with low water yield, so it can be a great opportunity for us in the future to add low cost inventory.

Jason Poggett: And you're stood thanks for clarity and just one quick one on slide five you talk about kind of that cadence of wells per rigs per year. And with the additional rig being added in in fourth quarter with point and probably being kept in a low rate basis. You expect any kind of shift in those numbers or is that kind of operational split between Midland Delaware and just that rig, you know, that rated that pretty sticky.

Jason Poggett: You should expect some movement there with the efficiency gains teams are the teams are working that kind of as we speak. As we mentioned, we've got great opportunities with things like the horseshoe shape wells that have low break evens. Delaware wells as we've highlighted in the past with wider spacing. They've been outperforming by 45% Katie inner team are continuing to reduce the cost out there as we get more experience drilling and completing in that area.

Jason Poggett: So the economics are definitely positive for both the Midland area and the Delaware and the Delaware you get. And a little bit more expensive wells, but higher productivity and 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 the been both cost savings and higher production, but we'll have better guidance for you in February. Understood.

Paul Diamond: I appreciate your time.

Noah Hungness: Our next question comes from the line of Noah hungness with Bank of America, please go ahead. Morning all, I just wanted to ask here again on the you laterals, how what kind of runway do you think you guys have for improving the cycle times and reducing those costs just given their relatively newer than a more standard, you know, two mile lateral. If you look on slide six at the bottom, one of the things we did break out this time was the cost and how that saves you money versus drilling.

Katie Hill: Two individual short ladder wells, but I'll talk I'll turn it over to Katie should give you a little more color on efficiency games and hello to work before. Hi, good morning Noah, when I think about the horseshoe wells, I would consider those to be an alternative well designed 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.

Katie Hill: But generally speaking, the horseshoe laterals would see the same type of efficiency and service cost improvement that we would expect with a straight conventional design. Well, I guess I was wondering too, as you guys start to really implement these out of at a larger scale, do you think you'll be able to take any learning to improve the cycle times for these you laterals. 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 is as we continue to test this design and alternative zones, we've already proven that we can execute in the Delaware and the midland.

Katie Hill: It's a 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 designed. I wouldn't just limit it to how we're thinking about the horseshoe application. We're definitely going to be in performance improvement opportunities. When we were drilling the Alice in Pat, every single well was getting faster. So the more we do it, we'll continue to get cost down and improve our break evens. Gotcha. I really appreciate that.

Noah Hungness: And then that's my second question.

Katie Hill: Katie edges hoping you could kind of expand a little bit on your conversations with the service providers.

Katie Hill: As you guys are negotiations with kind of contracts now, could you kind of talk about how those conversations are today and how that's changed versus maybe a month ago? Yeah. Market right now is experiencing consolidation, as you know, the opportunity for us is we're able to grab high specs, techno, you know, technically advanced rigs and Brat 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 a commodity market.

Noah Hungness: That was good. Really appreciate it guys.

Unknown Executive: Thank you.

Chan Abba: Our next question comes from the line of Chan Abba with Wolf Research. Please go ahead. A good morning and thank you for taking our questions. Jason, you know, it sounds like the focus here really is on your access that you have in hand and also on reducing the powerings under your revolver. Over probably the next year.

Jason Poggett: 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? For us, we're really 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 the low break even in where they were added today.

Jason Poggett: So I see just 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 that the Simal Frack. We can pump lower fluid loadings in some of our wells to continue to get capital costs down. The L.O.E. Front. We're looking at infrastructure projects work over expenses, chemical expenses that will continue to prove our L.O.E.

Jason Poggett: 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 L.O.E, 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.

Jason Poggett: That is going to be the higher focus for us really in the next year. So it's just improving cash flow attacking it on the capital front the L.O.E. 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. The landscape I don't see is many opportunities where inventory can jump ahead of what we've got today which is our requirement for any future asset.

Jason Poggett: We're really excited about point because it's in our backyard and had low break even 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. I appreciate it.

Jason Poggett: And just a really quick follow-up for your hedge, 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 the commodity volatility? 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. 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 that they've been at that $75 range.

Jason Poggett: You saw the big jump in our hedge 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 going to hire ultimately at a higher hedge position than we would normally be in, but I wouldn't hesitate to add the other hedges if we see oil spikes and put on additional layers of that $75 range. Thank you very much for taking our questions. Thank you.

Unknown Executive: That concludes our Q&A session.

Ronald Hagood: I will now turn the conference back over to Mr. Ron Hagood for closing remarks. 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.

Q2 2024 Vital Energy Inc Earnings Call

Request a DemoDemo

VTLE

Vital Energy

Earnings