Vital Energy, Inc. (NYSE:VTLE) Q2 2023 Earnings Call Transcript

Vital Energy, Inc. (NYSE:VTLE) Q2 2023 Earnings Call Transcript August 12, 2023

Operator: Good day, ladies and gentlemen, and welcome to Vital Energy, Inc.’s Second Quarter 2023 Earnings Conference Call. My name is Justin, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. It is now my pleasure to introduce Mr. Ron Hagood, Vice President, Investor Relations. You may proceed, sir.

Ron Hagood : Thank you, and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer; Bryan Lemmerman, Senior Vice President and Chief Financial Officer; Katie Hill, Vice President, Operations; as well as additional members of our management team. During today’s call, we will be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts and assumptions are intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Our actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we’ll be making reference to non-GAAP financial measures.

Reconciliations to GAAP financial measures are included in the press release and presentation we issued yesterday detailing our financial and operating results for second quarter 2023. The press release and presentation can be accessed on our website at www.vitalenergy.com. Now I’ll turn the call over to Jason Pigott, President and Chief Executive Officer.

Jason Pigott: Thanks, Ron. Good morning, everyone. Thank you for joining us today. Financial and operating results in the first half of the year have been outstanding. We have strengthened our business through accretive acquisitions that extend our oil-weighted inventory and enhance oil production. As a result, production was again above the high end of guidance with oil setting a company record and capital investments were below the low end of guidance. We closed on 2 accretive oil-weighted acquisitions, are well positioned for the second half of 2023, and expect to maintain our momentum into 2024. As we think about our 2024 program, we remain focused on our core strategies, maintaining capital discipline, generating free cash flow, reducing debt and leverage, targeting accretive acquisitions, advancing sustainability, and integrating digital solutions.

For 2024, we are targeting relatively flat production compared to 2023, inclusive of volumes acquired this quarter. Importantly, we believe we can accomplish this at similar investment levels to full year 2023 and grow free cash flow versus full year 2023, enabling continued debt reduction. Our expected 2024 budget benefits from planned development in our recently acquired acreage in Upton County and Delaware Basin, reinforcing our strategy of acquiring and quickly developing high-return oil-weighted acreage across the Permian Basin. Today, over 90% of our production comes from properties we acquired over the last 4 years, proud of what the organization has accomplished thus far in 2023, and are focused on continuing to execute our strategy and build additional shareholder value.

I will now turn the call over to Katie for additional details on our strong operational performance.

Katie Hill : Thank you, Jason. I’d like to start this morning by recognizing the great work our operations and supply chain teams are doing to optimize well productivity, drive capital efficiencies, lower costs and integrate new acquisitions. These teams have been instrumental in continuing our outperformance throughout the first half of the year. In the second quarter, we delivered higher-than-expected production volumes driven primarily by outperformance on the base and accelerated oil production from new wells. During the quarter, we reduced mechanical downtime and frac impact on base production. Additionally, process improvements and the adoption of digital solutions have improved uptime performance on both our compression and artificial lift assets.

As Jason mentioned, we set a company record in the second quarter for oil production. Following the close of our Driftwood and Forge acquisitions, we have subsequently hit a new oil production record early in the third quarter. We anticipate the average for the quarter will be the highest average oil production rate for us in our history. We have hit the ground running on both new assets, already completing a 4-well package in Upton County and a 2-well package in the Delaware. In our updated production guidance, the midpoint of fourth quarter oil production is lower than the third quarter midpoint. This is a reflection of our planned development schedule and how we are optimizing to minimize future parent-child impacts. Currently we are drilling a 20-well package in Western Glasscock where completions operations are expected to start at the beginning of the fourth quarter and complete in early March of 2024.

For the result, there is a 3-month period where very few wells will be brought online, which is reflected in our fourth quarter production range. Production is expected to remain relatively flat in the first quarter of 2024 before increasing in the second and third quarters as we fully bring on the 20-well Glasscock package. In the second quarter, capital expenditures were below expectations as we maintain our efficiency gains, including in the newly acquired leasehold. We are also benefiting from moderating inflationary pressures for services, especially in the OCTG market. We are seeing prices come down for both high-spec drilling rigs and completion services. By converting both of our Midland drilling rates to high line power, we further improve cost efficiency and reduce operating emissions during the drilling phase.

Our 2024 outlook is underpinned by our operational success. As we apply our operating platform to our recently acquired leasehold, we plan to continue optimizing well productivity and improve operational efficiencies. Our team has done a fantastic job mitigating cost pressures in 2023 and we are optimistic we can find additional savings in 2024, although our current outlook does not factor in additional cost reductions beyond what we’ve achieved to date. I’ll now turn the call over to Bryan to provide a financial update.

Bryan Lemmerman : Thank you, Katie. Operational performance and efficient integration of the recently acquired Driftwood and Forge assets is driving our strong outlook for the remainder of 2023 and full year 2024. We are again increasing production guidance for full year 2023, further incorporating improvements in our base production and excellent performance from new development and also lowered capital expectations for the year, decreasing the midpoint of the range from $700 million to $680 million and bringing the high end of the range down by $30 million, a result of moderating inflationary expectations for the second half of the year and exceptional performance from our operational teams. As Jason mentioned, our initial outlook for 2024 envisions fairly similar activity levels on a net basis, maintained full year 2023 production levels even after increasing production associated with both acquisitions.

Resulting free cash flow over the next 18 months is expected to be around $265 million, supported by a relatively robust hedge book. We will continue to look for opportunities to strengthen our hedge book to lock in free cash flow that will be directed to paying down the RBL. In the second quarter, the company recorded income of $222 million related to the reduction of the valuation allowance against our gross deferred tax asset. As the company is currently structured and at current commodity prices, we expect our $1.2 billion NOL will offset income for another 2 to 3 years, resulting in us being a federal taxpayer around 2026 at the earliest. I will now turn the call back to Jason for closing comments.

Jason Pigott: Thank you, Bryan. In closing, this was another strong quarter for us. I can’t say enough about how our teams have worked together to transform the company, integrate our acquisitions, control costs and deliver a strong first half of the year. Operator, we will now open up the call for questions.

Q&A Session

Operator: [Operator Instructions] Your first question comes from the line of Derrick Whitfield from Stifel.

Derrick Whitfield : Congrats on another solid quarter.

Jason Pigott: Thanks, Derrick.

Derrick Whitfield : My first question, I wanted to focus on your second half ’23 guidance and 2024 outlook. In light of your lighter TIL schedule in Q3 and Q4 and the larger package as well as you’re referencing in Q1 of 2024, how should we think about the shape of your production profile through the first half of 2024?

Jason Pigott: Yes, it’s a good question. Again, on Slide 9 of our deck out there, we do have the TIL schedule and we’re coming off, again, ’23 TILs for our operated areas. Additionally, prior to us taking over Forge, they were running 3 rigs and we were running just 1 rig. So those 2 things will cause production to kind of dip into the fourth quarter. I guess, as Katie mentioned on the call, we’re going to hit a record for the third quarter, but the lack of TILs coming in fourth quarter and early first quarter of ’24 will kind of drive this dip in production. Additionally, we have a large 20-well package that we’re completing — drilling and completing in Western Glasscock, which is much larger than we typically do. Typically, our packages are more like 12 wells at a time.

So that’s also going to defer again production coming online or the ramp into 2024. So you should see a dip for 4Q, fairly flat for 1Q of ’24, and then production will start rising as these wells are all coming online.

Derrick Whitfield : Great. And for my follow-up, I wanted to confirm your base optimization work is not factored into your guidance and also ask Katie, if she could offer her thoughts on how long it would take to integrate the optimization process into the Driftwood and Forge acquisitions?

Katie Hill : So I would say most of our base optimization work on the Midland Basin has been included in the go-forward forecast. We are probably 3 to 6 months from having the hardware platform deployed on the Delaware asset upon which we’ll be able to leverage all the AI work that we’ve done. So I’d expect to start to pull that into 2024 for new acquisitions. So pretty excited to be able to deploy that platform in that area.

Derrick Whitfield : And one last, if I could. With respect to Forge, could you share your broad thoughts on areas of upside relative to your initial assessment now that you have the asset in-house?

Katie Hill : Yes. So the beginning has gone really well. We’re about a month into the transition, and it’s been great getting to work with that team in the new asset. I think some of the opportunities that we’ve identified already are primarily related to our scale and purchasing power for both new capital activity and operating expense. We’ll be able to drive down costs, we also, as I mentioned, have really a strong AI platform that we’re excited to deploy over the next probably 6 to 18 months. So I think we’ll see improvement on both base production optimization and then our overall cost structure in the area.

Jason Pigott: Yes. As we mentioned in the release, I think, again, we’re going to accelerate bringing the frac crew and so I think when you have 1 crew working for a longer period of time, you get more consistency there, which will also provide some opportunities to get our completion costs down.

Derrick Whitfield : That’s great. Thanks for your time and responses.

Operator: Your next question comes from the line of Zach Parham from JPMorgan.

Zachary Parham : I guess, first, just on your activity levels in 2024. Most of your activity in ’23 is in Howard County, can you give us some color on how your activity will be split in ’24. I know you mentioned the 20 well package in Western Glasscock that’s planned for the first half of the year. But can you just give us some detail on how those 70 to 75 turn-in-lines will be spread across your asset base next year?

Kyle Coldiron : Yes, this is Kyle Coldiron, I can take that. So I guess at the end of ’23, we revisit Howard County and have 2 sections that we’re going to develop there before returning to Western Glasscock. And we kind of bounce back and forth between Howard County and Western Glasscock in the first half of the year. And then towards the back half of the year is when we go and essentially start developing our Driftwood assets down in the Southern Midland Basin. So kind of looking at our schedule here, I’d say we’ve got probably 1/4 of the development would be in Howard County. 1/4 of it would be in our South Midland Basin and then the remainder would be in Western Glasscock.

Jason Pigott: We also got in parallel a rig running full time in the Delaware. One rig is dedicated to the Delaware Basin right now.

Kyle Coldiron : Right.

Zachary Parham : Got it. So is that roughly a dozen turn-in-lines next year in the Delaware?

Kyle Coldiron : Yes. One rig running full time in the Delaware is anywhere between 12 and 14 wells a year.

Zachary Parham : Got it. And just my follow-up on operating costs. LOE has been around $7 per BOE in the first half of the year and the guidance for 3Q is at $7, but it’s expected to move closer to $8 in 4Q just based on the second half guidance. Can you give us some color on how you expect LOE to trend in ’24, maybe what’s a good run rate we should be using when we’re thinking about modeling that?

Katie Hill : This is Katie. As we think about LOE through the remainder of ’23 and going into ’24, we expect total spend to stay relatively flat, but the dollar per BOE will moderate with production. We’re hitting again, a Q3 production record for the company. And with that, we’ll see increased water volumes and you see total spend go up a little bit. And then as we go into Q4 and Q1, the decline in total BOE and flattening into 2024 will drive dollar per BOE up. We expect total year next year to look very similar to this year as you average it across the 4 quarters.

Operator: Your next question comes from the line of Gregg Brody from Bank of America.

Gregg Brody : I think it’s Gregg Brody, if you weren’t sure. Just can you talk a little bit about sort of the M&A landscape, how you’re thinking about that today. Obviously, you’ve just completed 2 transactions. Curious if you think you’ll be active for the rest of this year? Or you’ll be on the sidelines as you digest the most recent acquisitions?

Jason Pigott: Yes. We’ve really built this company and the team to scale. As Katie mentioned, they’ve already done a large amount of work to get the assets integrated, Driftwood is pretty much fully integrated. So I don’t think having to take a break just because of the teams is really an issue for us. It’s really more the opportunities and when they come available where we’ve been successful this year, we pivoted to doing smaller deals that are more digestible kind of in that $250 million to $500 million range. And again, when they’re available, we look at and evaluate them. Our focus has been on in doing accretive acquisitions that build inventory for us in oilier parts of the basin, we moved to the Delaware because we see more opportunities potentially over there.

So we’ll continue to look at them. I think our strategy shift, again, to doing these smaller acquisitions works for us, are a little bit less competitive than some of the larger opportunities where you get companies coming even from outside the basin to bid on these, and this has been working for us for this year so far. The assets are virtually integrated. Again, we’ve got things like telecommunications that we need to upgrade, but that wouldn’t prohibit us from doing something else. But again, we want to do things that are smart. If you look at the company since 2019, we’ve been able to grow oil almost 55%, and that’s kind of on the heels of doing these acquisitions where we bring wells that we acquired to the front of the rig schedule, they’ve got better returns and help us grow our oil production over time.

So we expect to continue to do deals kind of like we’ve done so far this year.

Gregg Brody : And you obviously have moved into the Delaware more recently. Is it fair to say you’re probably — you’re focused in the Permian? Or are you still possibly thinking about going outside the Permian for opportunities?

Jason Pigott: Yes. We’ve said Texas oil, which, again, Permian, Eagle Ford are primarily the things that we look at. So — and everything on — again, we’re looking hard at would be in the Permian Basin where we can — we’ve got an existing footprint. We can expand from itself to kind of look at where our acquisitions have done. We’ve gone from Eastern Midland Basin to the North and Howard and then kind of along with Southern perimeter through the Midland and into the Delaware Basin. So just places where we’re comfortable operating. But that’s the focus would be the Permian for now. There are not as many privates available. They’ve been getting gobbled up. So again, at some point, we may need to pivot. But today, it’s Permian oil is the primary focus.

Gregg Brody : And then just you highlighted the free cash flow generation you expect through next year, which obviously helps your liquidity picture. But I’m curious how you do think about your liquidity and sort of the refinancing of sort of your ’25s and just what’s the right amount of credit not to have on your revolver. Can you just walk us through what’s your — how you’re thinking about that in the context of you have the ’25 maturity is 18 months away?

Bryan Lemmerman : Sure. We have a lot of different options to take care of the 2025s, including refinancing and all of those we’re looking at every day and looking for the best long-term outcome of the company. In the short term, if we needed to, we can put it on the revolver using our borrowing base, along with the free cash flow to pay them off. But we hope to do something better than that. As far as a long-term RBL balance, we’ve generally said that having 12 to 18 months of free cash flow on the revolver is a level at which we’d like or be okay with that way we have a location or a place to put free cash flow without having to inefficiently call bonds, so that’s generally how we think about it. So the RBL balance is a little high right now relative to where we would like to have them.

Gregg Brody : And just my last question. So the partnership with Northern Oil and Gas with this most recent acquisition. Can you just remind us if there’s — if they have any outs on their drilling obligation with respect to but how you plan to approach this. And historically, they typically had an out. But I know this is a little bit different from them. I’m just curious how committed is that capital to support what you want to do?

Bryan Lemmerman : Yes. So I’m not sure which ones of transactions you’re referring to them in the past. But for our transaction, they are a straight heads up working interest partner. So they are no different than any other working interest partner we have in every other well that we drill.

Gregg Brody : Got it, and they can consent or non-consent on wells that they choose not to, if they choose to?

Bryan Lemmerman : Yes, as a working interest partner, they can consent or non-consent.

Gregg Brody : How much of your — when you think about that partnership, did you identify your inventory and sort of how long they would be at a program that made sense, in a sense they would be there alongside you? Or is that — are you — I guess how much planning have you done there?

Bryan Lemmerman : Well, so I think I would expect these wells are — they’re at the front of our inventory schedule. If for whatever reason they non-consented, we would drill them 100%. So this is different than the transactions they may have done with other people, and I’m not extremely familiar with them, so I don’t want to comment on these, but — on those. But this does not resemble a drilling commitment or a drilling fund or anything like that. This is a straight up 100% working interest partnership. They bought into the asset in the exact same manner we did, the only difference is that we’re the operator.

Gregg Brody : I think that’s similar to what they have in the past. So, okay. Thank you.

Operator: Last question comes from the line of Nicholas Pope from Seaport Research.

Nicholas Pope : I was hoping you could compare across Northern Midland, Southern Midland Glasscock and Delaware, where your expectations are for well costs. And I don’t know if that’s on per foot basis or total drilling and complete, whatever you’re kind of comfortable with. But it’s — if you look at the aggregate, trying to understand like how that’s going to look across those different areas right now?

Katie Hill : Sure. Our well costs are generally trending with bottom hole pressure in the area. So you’ll see a little bit higher costs as we move south in the Midland Basin. And as we move over into the Delaware, a little bit higher cost than our Howard County development in 2023.

Nicholas Pope : Is there not that big of a spread between like the Delaware versus Midland in terms of where costs are or expectations there?

Katie Hill : Generally, no. So I think one of the opportunities that we have in the Delaware Basin compared to historical spend in that area that we’ll have a little bit better scale compared to the previous operator. So I think we expect to be able to deliver those wells at a little bit lower capital than the previous program that they were running in the area. We’re continuing to apply both our previous Delaware experience that we have across the operations team and what we’ve learned in the Midland Basin in that area as we’re working through the development plan.

Jason Pigott: I think like, again, Howard County well would be $7,600, $7,700 per square foot versus $1,250 or so for a Delaware well right now. But again, as Katie said, lots of opportunity to improve. We haven’t drilled our fully our first wells yet. We’ve completed them. But again, I think there’s good opportunity there.

Nicholas Pope : Got it. That’s very helpful. And looking at the outlook for the remainder of 2023, you gave a little clarity on the LOE component of operating costs. Looking at just the transportation and marketing, is that — should we expect things to be fairly stable in that $1.20, how are you thinking about that progressing through this year and into ’24.

Benjamin Klein : Yes. This is Ben Klein. The transportation and marketing arrangements we have in place are reflected on that line item are related to crude transportation. That’s a fixed quantity of crude oil that we transport on Gray Oak Pipeline. And so absolute dollars should be relatively flat period-over-period. Your unit cost is obviously going to fluctuate with total production.

Operator: There are no further questions at this time. Mr. Hagood, I turn the call over back to you.

Ron Hagood : Well, thank you for joining us this morning. We appreciate your interest in Vital Energy, and this concludes this morning’s call.

Operator: This concludes today’s conference call. Thank you for joining. You may now disconnect.