Vital Energy, Inc. (VTLE) on Q1 2022 Results - Earnings Call Transcript
Operator: Good day, ladies and gentlemen, and welcome to the Laredo Petroleum Incorporated, First Quarter 2022, Earnings Conference Call. My name is Amanda and I will be your 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 Mr. Ronald Hagood, Vice President, Investor Relations. You may proceed, sir.
Ronald Hagood: Thank you and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer. Karen Chandler, Senior Vice President and Chief Operations Officer. And Bryan Lemmerman, Senior Vice President and Chief Financial 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, forecast, 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 will be making reference to non-GAAP financial measures, reconciliations to GAAP financial measures are included in the press release and presentation we issued yesterday that detail our financial and operating results for first quarter 2022. The press release and presentation can be accessed on our website at www.laredopetro.com. I will turn the call over to Jason Pigott, President and Chief Executive Officer.
Jason Pigott: Thank you, Ron. Good morning. And thank you for joining us today for a discussion of our first quarter results. We performed extremely well in the first quarter, continuing the momentum we generated in 2021. First, total oil and total production and capital were in line with guidance as our teams continue to execute our investments in Howard and Western Glasscock Counties. Second, we generated free cash flow of $23 million and consolidated EBITDA tax of $222 million. Third, we reduced leverage from 2.1 times debt-to-EBITDA at the end of the year, to 1.9 times at the end of the first quarter. We also continue to move forward on our initiative to achieve responsibly sourced gas and oil designation for a portion of our production, which was awarded in April. Laredo now has 31,500 BOE per day, attributed to a gold rating, which is required for oil to be considered responsibly sourced. We're the first Permian operator to receive TrustWell certifications. In addition to delivering on our projections in the first quarter, we have positioned ourselves to further deliver on our value creation strategy for the remainder of 2022. We materially increased liquidity as the value of our asset support a 38% increase in our elected commitment as part of the RBL redetermination. We worked with our service partners to lock in 85% of expected drilling, completions, equipment, and facility spend for the remainder of the year. And we anticipate achieving our leverage target of 1.0 times by the first quarter of 2023 at current commodity prices. These successes support the objectives of our near-term strategy to utilize free cash flow to pay down $300 million of debt in 2022, equivalent to approximately $17 per share on our current outstanding share count. This amount of debt repayment we achieve a leverage target of 1.5 times by early third quarter and 1.0 times for the first quarter 2023. Our commitment to leverage reduction supports the opportunity to institute our program to return cash to shareholders by early 2023. Buy prices have been exceptionally strong and the industry is experiencing significant inflationary headwinds. We continue to drive efficiencies to offset the inflationary pressures and secure a longer-term pricing where we can. Work of the team has enabled us to maintain our projection of greater than $300 million of free cash flow in 2022, despite increasing our capital budget to approximately $550 million and seeing our operating cost increased by approximately $1 per BOE. We remain intensely focused on executing on our strategy to accelerate value creation for our shareholders and delivering our objectives in 2022. We'll now have Karen provide an operations update.
Karen Chandler: Thank you, Jason. As you can see from our first-quarter results our operating teams performed very well again this quarter. Our production, capital expenditures and number of wells completed and turned in line are all in-line with guidance. We did see a couple of days of weather disruptions early in the quarter. But the overall impact was relatively small, decreasing in quarterly oil production by about 150 barrels of oil per day. We continue to see solid well performance for both our base and new production in Howard and Western Glasscock Counties. We are especially encouraged with the production from the two middle Spraberry appraisal wells, completed late last year in the North Howard area. The performance of these two wells strongly supports the assumptions we made when adding Middle Spraberry locations to our Howard County inventory. Based on the strong performance of these two wells and their strong economics, we've included eight Middle Spraberry wells into our 2022 development plan. These wells will be incorporated into our current activity levels of two rigs and one frac crew, and are not being added as additional activity. We're simply adding wells to currently planned well packages in North Howard to benefit from the efficiencies inherent in larger packages. There are no changes to our stock or completion counts for the year. During the first quarter, LOE was higher than we anticipated, reflecting both inflation and additional costs associated with integration of our recently acquired properties. A majority of the increase was associated with artificial lift and fallback management on newer wells in Howard and Western Glasscock Counties. These included higher generator and fuel costs associated with running our USPS on New Wells and Howard County using additional fullback crews on older Sabalo batteries with limited automation and higher compression in fuel gas costs for running gas-lift on new wells in Western Glasscock. Other cost pressures impacting lowes include higher rates for compression and VRU rentals, workover rigs, diesel and power. We're currently working to manage costs associated with power by switching to LNG generator systems in Howard County and reallocating facilities and artificial lift the high-line power as soon as it is available in our operating areas. We also expect to see cost benefits from the work we are doing to retrofit older batteries and consolidate production to new Laredo built facilities in the acquisition areas. With our cost mitigation efforts, we expect to hold total LOE expense relatively flat for the remainder of the year. This is reflected in our second quarter, 2022 LOE guidance of $5.35 for BOE, flat to first-quarter. Capital expenditures for the first quarter were $171 million in-line with guidance, reflecting the work the supply chain team has done to lock in as much pricing and supply require goods and services as possible. As we continue to mitigate inflationary pressures impacting the industry, we have locked in second half pricing for about 85% of our operated capital expenditures for the remainder of the year, including completion services, tubulars, and sand. This will significantly reduce uncertainty in the remainder of our 2022 capital expenditures and ensures we have access to equipment and crews necessary to execute on our development program. We have adjusted our 2022 capital budget to $550 million up about 6%. This updated capital budget fully incorporates the inflation that we have seen today. Contracted set get half pricing and expected inflation on any areas that are not yet fully locked in for the remainder of year. Importantly, with the strength of commodity prices and our strong margins, even with the 6% increase in our capital budget, our cash flow forecast for the year remains unchanged. I will now turn the call over to Bryan for a financial update.
Bryan Lemmerman: Thank you, Karen. During the first quarter, we continued to make progress on our overarching financial goal of generating free cash flow, reducing leverage, and ultimately positioning the company to return cash to shareholders in early 2023. As Karen described, inflationary pressures have been impacting the industry and have pushed our operating expenses and capital expenditures above our original expectations for 2022. We are fortunate that commodity price strength and efficiencies at the field level have fully offset these inflationary pressures, as our free cash flow outlook for the year remains unchanged, at greater than $300 million in the current price environment. Our investments this year by design, were front-end loaded so we expect our free cash flow to increase significantly throughout the remainder of the year as quarterly capital investment levels moderate. Our primary focus for the use of our free cash flow remains debt reduction. Previously stated leverage goal of 1.5 times net debt to EBITDA should be achieved during the third quarter. And at current commodity prices, we expect that ratio to decrease rapidly and to be at one-times by the end of the first quarter of 2023. Our plan is still to utilize our free cash flow to reduce debt by $300 million by year-end 2022. Our recently redetermined RBL demonstrates our bank group's confidence in our ability to deliver on our goals. Besides increasing our borrowing base to $1.25 billion and our elected commitment to 1 billion, they built in additional flexibility for us to determine how we pay down debt. Through the end of this year, as long as our net debt to EBITDA x-ratio is below 2.5 times, we have the flexibility to utilize $250 million of our elected commitment to purchase or call term debt. Structure provides us with maximum flexibility to determine the best course for repaying debt as we generate cash throughout the rest of this year. As we achieve our debt repayment and leverage goals, we expect to be in a position to return capital to shareholders in early 2023. With that, I will now turn the call over to Jason for closing comments.
Jason Pigott: Results in the first quarter are a reflection of our accomplishments over the past three years. The outstanding returns on our wells in Howard and Western Glasscock counties powered our free cash flow generation in deleveraging. The remainder of 2022 will further accelerate this trend as we pursue our goals of $300 million in debt reduction, and leverage at or below 1.0 times by the first quarter of 2023. We believe paying down debt throughout 2020, deliver substantial value for our shareholders and positions us to begin substantially returning capital to shareholders in early 2023. Operator, please open the line for questions.
Operator: Thank you. [Operator Instructions]. Please standby will be compile the a roster. Our first question is from Derrick Whitfield from Stifel. Your line is now open.
Derrick Whitfield: Thanks, and good morning, all. With my first question, I wanted to focus on your 2022 plan and your confidence in executing against it. In consideration of the operating environment in tightness and services, supply and labor, have there been or do you expect any business impacts beyond inflation?
Jason Pigott: Great question, Derrick. I think we -- again, feel really confident with locking in the capital where we did right now. Again, it was a factor, there were an uncertainty for the future. Again, block again those completion services, and some of the other items is going to be good for us as far as the other factors. I'm really excited about the wells that we've got coming online in Howard County. We've got our first 15,000 foot wells coming online. We've been trying some new stimulation techniques that appear to be doing well. Those wells are just really early in their flowback, so we look forward to talk more about it and -- probably the next quarter. But I feel really good about where the company is right now, and I think the steps we took on the capital front mitigate a lot of the risks that we would face for the remainder of the year.
Operator: Our next question is from the line of John Daniel with Daniel Energy Partner. Your line is now open.
John Daniel: Thanks for letting me -- the dump oil service guy ask a couple of questions. I appreciate it. I guess this one will be for Karen. Can you just walk us through what the opportunity set is and impacts on production could be with just a push to greater workover activity?
Karen Chandler: Yes. So it's clearly as the commodity price has moved around, we keep a really close eye on what we're doing from a workover standpoint on all of our operations. We've talked about it in the past. We really look at it on an ongoing basis in any environment to make sure that what we talk about is no well left behind, that we're looking at each individual well and making the right economic decision for that well. As commodity prices have moved around, it really hasn't impacted our workover activity as much as you might expect, just because we had that ongoing program in place.
John Daniel: Okay. When you look at like the new well completion designs today versus maybe four to five years ago, just doing that out. Do you -- is there a material uplift at all when you go back to ended the sort of original horizontal wells that were drilled. And when do you do that?
Karen Chandler: In general, we had done very little work over activity in recent horizontal wells, so -- I mean recent in the last four -- wells that have been drilled in the last four or five years. That's very unusual activity for us. There have been a few instances but it's on something operational that's very different from the standard well that we've completed.
John Daniel: Okay. Great. And then just one -- final one from me, when -- as you all look up the '23 and I know we're still a ways away, at what point do you start reaching out to your contractors just to negotiate pricing or lock that in? Is that too early?
Karen Chandler: Yes. So as we've talked about long -- As we were talking about in the last call locking in second half, I really think it's a call on a service-by-service basis. What we've been doing is in a very rigorous way, the supply chain team has been evaluating both the industry and us specifically, as far as services and what our expectations are with cost trends, and then also availability of services. I mean, Jason pointed out that locking in second half, we believe really gives us a lot more certainty, really reduces risk on cost, but it also gives us more certainty and reduces risk around service availability. So on a case-by-case basis depending on services, our goal was definitely to get 2022 as locked up as possible to give us certainty around the capital budget that we're executing on. There are services that we've started to talk about 2023, but I think it's just a case-by-case basis as we see those services and expectations change.
John Daniel: Okay. Thank you all.
Bryan Lemmerman: Just getting understanding of oil versus so much volatility in oil price. You don't want to be in a situation where you've locked in services at a high price and then oil dropped. So I think we'll just, as we get closer to next year, won't be bad.
John Daniel: Fair enough. Thank you very much.
Operator: Our next question is from the line of Jordan Stuart with GoldenTree, your line is open.
Jordan Stuart: Hey guys, thanks for taking the question. Just first would love to get an update on the Eastern acreage block. Obviously with the moving gas prices we'd assume these continue to look more and more attractive, but just any more color you guys could provide on that inventory.
Jason Pigott: Yeah. It's the gas prices are definitely helping out there. When we look at economics the -- they -- the Howard County is so good that they still fall behind that sequentially. So our economic priority is the Howard County Western Glasscock, and then the -- the core assets. But they again, they do look better with higher gas prices, Western Gas -- Glasscock is also a little bit gas here than Howard is -- it's supported as well. But we really -- we really tried to drill our best economics first. And right now, that's Howard County and we're I'd say we're -- we're drilling some really good wells out there right now.
Jordan Stuart: And then maybe just in terms of M&A, just curious, the opportunity set that's out there. If you guys are kind of continuing to explore additional opportunities, obviously, the bid-ask is kind of wide according to others, but just curious to get more color on that front. How you're thinking about and how any deal could potentially be financed.
Jason Pigott: I'll just start with the opportunity set and then Bryan can speak on how we might finance it, but we continue to want to grow and achieved scale as a company. We also want to deliver at the same time. So anything that we would look at has to deliver us in line with what we're doing today. A lot of the packages that are out there that we've looked at have been a little bit more PDP heavy, so those don't really fit. What we're looking at as a company, we want to continue to build up robust inventory of wells with kind of lower break evens that can survive downturns. That's the priority for us and they're just haven't been a lot of those on the market right now. With respect to financing I'll turn it over to Bryan.
Bryan Lemmerman: I think Jason hit on the fact that it would still need to be deleveraging along the same lines that we are projecting today. As we look at those opportunities, you're right that the bid-ask are quite wide right now. Then I think the type of assets that are out there year-to-date haven't been what we're looking for. But anything that we do would -- it would be financed in a way that we would still achieve our debt, our leverage reduction goals, materially on the same timeline that we've laid out here today. So that's how we look at it. As Jason said, debt reductions are primary, and then you get to return the capital at some point, and the wildcard is when you find an opportunity on the acquisition side to do, it needs to not derail those goals. So that's how we're approaching it this year.
Jordan Stuart: Awesome. That's helpful. And then last one for me. It sounds like you guys have done a great job walking in your budget for the second half of the year, even though there's this, I guess 15% variable. Just curious to dig in a little bit more. Is there any potential for that 550 number to be biased higher at any point or we feel pretty good about that number now?
Karen Chandler: Yes. So what we've incorporated in here again is service cost. As we've seen inflation we've locked those in. So, what's remaining -- the 85% is activity forward for the year. So, with the activity that's been completed today, we're over 90% kind of locked in on the service side. So what's in the remaining primarily are areas around chemicals and diesel, very difficult to lock those in. And clearly there could be some float in those components. So areas that even though we haven't fully locked in, that we think that we believe directionally where market may go we've incorporated that into the budget, so we feel really good about this budget. We think it's very tight. It still will be impacted by changes in, for example, diesel being the most impactful if we're seeing significant changes there. Clearly that could go into the positive or to the negative depending on what commodity prices are dealing. The only other add that I would make to that is the activity levels in this budget are exactly the same as in the original budget. We do not plan on increasing activity, we talked about kind of what the rest of the outlook looks like. It's based on our two rigs, one frac crew. We do focus on maintaining that activity with only having the two weeks and the oil crew running. So if we see continued performance improvement, activity being pulled into the year, there may be a little bit of that as we continue through the year and really work on getting our performance improvement into the drilling completions program.
Jordan Stuart: Awesome. That makes sense. I guess, just in terms of the inflation assumption, obviously, harder to lock in the cans and diesel pricing, it sounds like. But what are the underlying assumption? Is it 10%, 15%? Just how are you guys thinking about that just so I could have a ballpark?
Karen Chandler: Yes. On services, I'll give you one additional examples. So out of the 2 rigs that were running right now, we will be contracting the second rig. One of the 2 rigs, we're working on contract for second half of the year. And that's in the 15%, but we do feel like we had a very clear line of sight overall on what pricing would be and have that incorporated. We feel for running this budget. So any areas like that that we have some line-of-sight on, we have incorporate into the budget. With diesel for example, it's going to be where the market goes.
Jordan Stuart: Awesome. Thanks for the time guys.
Jason Pigott: Thank you.
Operator: Our next question is from Joseph Mackay, Wells Fargo. Your line is now open.
Joseph Mackay: Hey, guys, thanks for taking my questions. Sorry. I hopped out a little bit, so I need to apologize. This was covered. But was just wondering if you could talk about in terms of the Howard County well performance and just the impact given where I went to actual shook out in Q2 guidance, just what your expectations are for the trajectory of volumes through the balance of the year?
Jason Pigott: [Indiscernible]. So in terms of well performance in Howard County, we are still really encouraged by what we're seeing from our Howard County North acreage. Both of Wolfcamp at lower Spraberry really are performing well for us up there and we've been especially encouraged by our to Middle Spraberry wells, which we've highlighted in the deck. Those has really surprised us to the upside relative for our expectations. And as a result, we've added eight of those wells to our development program in 2020. And hurricane central, we're still seeing consistent behavior in terms of the wider spacing packages outperforming. And so we've thought we've got this spacing kind of locked down there in a way that's attractive for us and so we're going to continue on that.
Joseph Mackay: Thank you. That's very helpful. My other questions were asked, so I'll turn it back over to you.
Jason Pigott: Thank you, Joseph.
Operator: Our next question is from Nicholas Pope from Seaport Research. Your line is now open.
Nicholas Pope: Morning, everyone.
Jason Pigott: Good morning.
Nicholas Pope: I was hoping you could talk a little bit on these longer laterals here. You're focusing on your -- you mentioned that 15,000 foot laterals, it's going to be coming soon. Should we think about those as like pure scale up in terms of costs and performance. And I guess really maybe you can talk a little bit about like what. I guess the drive is for these longer laterals, is there a limit that you guys think you can push towards or is it purely geometry of acreage?
Karen Chandler: Yeah, I've talked a little bit about cost and performance. So, we are drilling the first 15,000-foot laterals [Indiscernible] that we've done in some timeline, but as a company, we've actually drove the number wells at those lateral links. As we transition to more the North Howard area, we're integrating in more 15,000 foot laterals into the program. One of the well packages that we brought on this quarter, we -- well, first quarter, included the first 16,000 foot lateral. So from an operation standpoint, everything is done smooth. We're just finishing up operations, completion operations on the second set, 15,000 foot laterals for the year. There's certainly cost savings on a per foot basis, so that's really the driver for drilling the longer laterals, and we're seeing that work into our overall program on a cost basis based on the capital numbers that are -- that have been provided. Then from a production standpoint, we're assuming that we'll see comparable performance on a per foot basis and getting the first initially [Indiscernible] on the first 15,000-foot laterals. From the standpoint of how far can you go, some operators are pushing further than 15. We do not think that the technical limit, overall, it's really dependent on how the acreage position lays out as much as anything. I will give an example there in Central Howard, we went into operations with primarily conducted the laterals because the acreage is laid out perfectly for that. As we move to North Howard, it's a little bit blockier and it's given us opportunities to extend those lateral links, and so 15 again is a good layout for the development from that standpoint.
Nicholas Pope: I appreciate that's very helpful. Additionally, could you talk about -- I think the fourth quarter you guys had a handful of wells in Glasscock County. Obviously, it's not -- it's not the focus this year, the drilling program. As you get more data on the Wolfcamp D and some of these newer formations that you're targeting, where do you think that sits kind of in the hierarchy of wells of kind of the total company. Like how do you -- how is performance betting on some -- I know you have the slides here, but where do you think these Wolfcamp D maybe specifically slots into the hierarchy?
Jason Pigott: It's kind of like where -- where if you look at our -- we've gotten in the slide deck where we're drilling. So we're going to the Northern Howard area. It's again, it's got the -- the best economics in the company. A lot of that again is Spraberry performance is much stronger in the north. So the whole package just has great economics all around. And as we mentioned, we're even that for one in some of these Middle Spraberry wells because they performed so well. So we'll -- we'll drill up Howard County and then we go to Western Glasscock and we will co-develop it with the Wolfcamp D and all the other formations down there. So that's kind of our -- our plan is to fully drill up North Howard. Sometimes we've got some lease obligations and we may need to go down and -- and put a few wells down here and there and this causes us to move around, but the priority is drill Northern Howard then go to Western Glasscock.
Nicholas Pope: Got it. That makes sense.
Jason Pigott: The performance is good. We have updated in our slide deck, so those wells are performing as expected, excited about the Wolfcamp D. It's just the economics in Northern Howard are so good that it's hard to do anything else but those.
Nicholas Pope: Got it, sir. I appreciate the time. Thanks, everyone.
Jason Pigott: All right. Thank you.
Operator: We have a follow-up from the line of Derrick Whitfield from Stifel. Your line is now open.
Derrick Whitfield: Thanks, and apologies for being disconnected earlier. Have you guys touched on project canary in Q&A?
Jason Pigott: We got David Ferris, our Chief Sustainability Officer here to talk a little bit about it though.
Derrick Whitfield: Hi, [Indiscernible].
David Ferris: Hi, Derrick. [Indiscernible] go ahead?
Derrick Whitfield: I was just going to ask if certainly, I'm not asking you to take a position on whether a methane fee will pass in legislation. Could you speak to the benefits of the certification and if you think it will improve downstream offtake options and potentially realizations based on your industry discussions?
David Ferris: Sure. And good question. I think the approach that we're taking is, this is the right thing to do to meet our 2025 emissions reductions targets that we've put out there. So understanding the emissions on locations, mitigating those emissions events in line with trying to reduce our overall emissions, that's just the right thing to do and we're focused on that in particular. We do think that there is and have seen historically opportunities in the gas market for small premiums to be paid. You're seeing certain industries, certain countries be more interested in acquiring certified responsibly sourced gas. So we think from a gas perspective that market is a bit more mature and there i -- there are opportunities there. From the oil side, that market -- we're seeing that emerge. We are the first Permian operator to certify our production and -- so we're -- believe we're on the leading edge of that right now. And so we are seeing early indication of interest on additional opportunities on the low side for small premiums as well.
Derrick Whitfield: That's terrific. And thanks for your time and that's all from me, guys.
David Ferris: Thanks, Derrick.
Jason Pigott: Thank you, Derrick.
Operator: Thank you, I would now like to turn the call back over to Mr. Ronald Hagood for closing remarks.
Ronald Hagood: Thank you for joining us for our update call today. We appreciate your interest in Laredo. This now concludes our call. Have a great morning.
Operator: This concludes today's conference call. Thank you for participating. You may now disconnect.
