Vital Energy Q2 2023 Earnings Call Transcript

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August 9, 2023

There are 10 speakers on the call.

Operator

Good day, ladies and gentlemen, and welcome to Vital Energy Inc. 2nd Quarter 2023 Earnings Conference Call. My name is Dustin, 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.

Operator

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.

Speaker 1

Thank you and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer Brian Limmerman, 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 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.

Speaker 1

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, detailing our financial and operating results for 2nd The press release and presentation can be accessed on our website at www.idaleenergy.com. Now I'll turn the call over

Speaker 2

to Jason Pigott, President and Chief Executive Officer. 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.

Speaker 2

We have strengthened our business through accretive acquisitions that extend our oil weighted 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 twenty twenty three 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 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.

Speaker 2

Proud of what the organization has accomplished thus far in 2023 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.

Speaker 3

Thank you, Jason. I'd like to start this morning by recognizing the great work our operations and supply 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.

Speaker 3

Additionally, process improvements and the adoption of additional solutions have improved uptime performance on both our compression and artificial lift assets. As Jason mentioned, we set a company record in the 2nd 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 Q3. 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.

Speaker 3

In our updated production guidance, the midpoint of 4th quarter oil production is lower than the 3rd quarter midpoint. This is a reflection of our planned development schedule and how we are Currently drilling a 20 well package in Western Glasscock where completions operations are It's expected to start at the beginning of Q4 and complete in early March of 2024. As a result, there is a 3 month period where very few wells will be brought online, which is reflected in our 4th quarter production range. Production is expected to remain relatively flat in the Q1 of 2024 before increasing in the second and third quarters as we fully bring on the 20 wells bond stock package. In the second quarter, capital expenditures were below expectations as We maintain our efficiency gains including in the newly acquired leasehold.

Speaker 3

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 rigs to Highline Power, we further improved cost efficiency and reduced 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 lease We plan to continue optimizing well productivity and improve operational efficiencies.

Speaker 3

Our team has done a fantastic job mitigating cost pressures in 2023 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 today. I'll now turn the call over to Brian to provide a financial update.

Speaker 4

Thank you, Katie. Operational performance An efficient integration of the recently acquired Driftwood and Forge assets is driving our strong outlook for the remainder of 2023 full year of 2024. We are again increasing production guidance for full year 2023, further incorporating improvements in our base an excellent performance from new development. We also lowered capital expectations for the year, decreasing the midpoint of the range from $1,380,000,000 and bringing the high end of the range down by $30,000,000 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, maintaining full year 2023 production levels even after increasing production associated with both acquisitions.

Speaker 4

Resulting free cash flow over the next 18 months is expected to be around 2 $65,000,000 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 Q2, the company recorded income of $222,000,000 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 $1,200,000,000 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.

Speaker 2

Thank you, Ryan. 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.

Operator

Thank you. All right. Your first question comes from the line of Derrick Whitfield from Stifel. Your line is open.

Speaker 5

Thanks and good morning, Jason and team and congrats on another solid quarter.

Speaker 2

Thanks, Derek. Good morning.

Speaker 5

For my first question, I wanted to focus on your second half guidance and 2024 outlook in light of your lighter Till schedule in Q3 and Q4 and the larger package of wells you're referencing in Q1 of 2024, how should we think about the shape of your production profile through the first half of twenty twenty four?

Speaker 2

Yes, it's a good question. Again on Slide 9 of our deck out there, we do have the Till schedule and we're coming off again 23 Tills for our operated areas. Additionally, prior to us taking over Forage, they were running 3 rigs and we were running we were running just 1 rig. So Those two things will cause production to kind of dip into the 4th quarter. I guess as Katie mentioned on the call, we're going to hit a record for the 3rd quarter, but the lack of tills Additionally, we have a large 20 well package that we're completing are drilling and completing in Western Glasscock, which is much larger than we typically do.

Speaker 2

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 20 24, so 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. Great. And for my follow-up,

Speaker 5

I wanted to confirm your base optimization work is not factored into your guidance. And Also ask Kate if she could offer her thoughts on how long it would take to integrate the optimization process into the Driftwood and Forge acquisitions.

Speaker 3

Hi. Good morning, Derek. 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 On which we'll be able to leverage all the AI work that we've done. So I'd expect to start to pull that in to 2024 for new acquisitions.

Speaker 3

So pretty excited to be able to deploy that platform in that area.

Speaker 5

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?

Speaker 3

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 will 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.

Speaker 3

So I think we'll see improvement on both base production optimization and then our overall cost structure in the area.

Speaker 2

Yes. As we mentioned in the release, I think again we're going to accelerate bringing the frac crew in. So I think when you have one 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.

Speaker 5

That's great. Thanks for your time and responses.

Speaker 2

Thanks, Derek.

Operator

Thank you. Your next question comes from the line of Zach Parm from JPMorgan. Your line is open.

Speaker 6

Good morning. Thanks for taking my questions. I guess first Just on your activity levels in 2024, most of your activity in 'twenty three 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.

Speaker 6

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?

Speaker 7

Yes, this is Kyle Coldiron. I can take that. So in 2024, I guess at the end of 'twenty three, we revisit Howard County and have 2 sections that we're going to develop there before returning to Western Glasscock. And we kind of balance 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 Our Driftwood assets down in the Southern Midland Basin. So kind of looking at our schedule here, I'd say we've got probably Quarter of the development would be in Howard County, quarter of it would be in our South Midland Basin and then the remainder would be in Western Glasscock.

Speaker 2

We also got in parallel the rig running full time in the one rig is dedicated to the Delaware Basin right now.

Speaker 5

Right.

Speaker 6

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

Speaker 7

Yes. 1 rig Running full time in the Delaware is anywhere between 12 14 wells a year.

Speaker 6

Got it. Thanks for that color. 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 3Qs 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 2024? Maybe what's a good run rate we should be using when we're thinking about modeling that?

Speaker 3

Yes. Hi, good morning, Zach. This is Katie. As we think about LOE through the remainder of 2023 and going into 2024, we expect total spend to stay relatively flat, That 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.

Speaker 3

And then as we go into Q4 and Q1, the decline in total BOE and flattening into

Operator

Thank you. Your next question comes from the line of Greg Crotty from Bank of America. Your line is open.

Speaker 8

Hey, good morning, guys. I think it's Greg Brody, if he weren't sure. Just can you talk a little bit about sort of the M and 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?

Speaker 2

Yes. We've really built this company and the team to scale. As Katy 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, it's really an issue for us.

Speaker 2

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 $250,000,000 to $500,000,000 range. And again, when they're available, we look at them and evaluate them. Our focus has been on And doing accretive acquisitions that build inventory for us in oilier parts The basin we moved to the Delaware because we see more opportunities potentially over there. So we'll continue to look at them.

Speaker 2

I think our strategy shift Again, to doing these smaller acquisitions works for us are a little bit less competitive. So then some of the larger Where you get companies coming even from outside the basins a bit on these. This has been working for us for this year so far. The assets are virtually integrated. Again, we got things like telecommunications that we need to upgrade, but that wouldn't prohibit us from doing something else.

Speaker 2

But again, we want to do things that are smart. If you look at the company since 2019, I mean, we've been able to grow oil almost 5% and that's kind of on the heels of doing these acquisitions where we bring wells that we acquire to the front of the rig schedule. They've got better returns and help us grow our oil production over time. So expect to continue to do deals kind of like we've done so far this year.

Speaker 8

And you obviously have moved into Delaware more recently. Is it fair to say you're probably you're focused In the Permian, are you still possibly thinking about going outside the Permian for opportunities?

Speaker 2

Yes. We've said Texas Oil, which again Permian, Eagle Ford are primarily the things that we look at. 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 it. So if you kind of look at Where our acquisitions have done, we've gone from Eastern Midland Basin to the North in Howard and then kind of along the Southern perimeter through the Midland and into the Delaware Basin.

Speaker 2

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.

Speaker 8

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 Just sort of your 25s and just what's the right amount of credit amount 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?

Speaker 4

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 months 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 and efficiently call bonds.

Speaker 4

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 that.

Speaker 8

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 is if they have any outs On their joint obligation, with respect to with how you plan to approach this and historically They typically had it 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?

Speaker 4

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.

Speaker 8

Got it. And they can consent or non consent on wells if they choose not to, if they choose to?

Speaker 4

Yes. As a working interest partner, they can consent to non consent.

Speaker 8

How much of your When you think about that partnership, did you identify your inventory and sort of how long they would be? What would A program that made sense and a sense of sense they would be there alongside you or is that are you I guess how much planning have you done there?

Speaker 4

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. I'm not extremely familiar with them, so I don't want to comment on these, but on those. But this doesn't this does not resemble Drilling commitment or a drilling fund or anything like that.

Speaker 4

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.

Speaker 8

Got it. I think that's similar to what they had in the past. So okay. Thanks for the time.

Operator

Thank you. Thank you. Last question comes from the line of Nicholas Pope from Seaport Research. Your line is open.

Speaker 9

Good morning, everyone.

Speaker 2

Good morning, Nick.

Speaker 9

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

Speaker 3

Good morning. Our well costs are generally trending with Bottom hole pressure in the area, so you'll see a little bit higher cost 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.

Speaker 9

Is there not that big of a spread between Like the Delaware versus Midland in terms of where your costs are at, where expectations are?

Speaker 3

Generally, no. So I think one of the opportunities that we have in the Delaware Basin compared to historical spend in that area is that we'll have a little bit better Gail, compared to the previous operator, so I think we expect to be able to deliver as well 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

Speaker 2

I think like again Howard County well would be $76,000 $7,700 per square foot versus 12.50 or so for Delaware well right now. But again, as Katy said, lots of opportunity to improve. We haven't drilled Fully our first wells yet. We've completed them, but again, I think there's good opportunity there.

Speaker 9

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

Speaker 7

Yes, this is Ben Klein. The transportation and marketing arrangements we have in place That are reflected on that line item are related to crude transportation. That's a fixed quantity of crude oil

Speaker 5

that we transport on Gray Oak Pipeline.

Speaker 7

And so, I 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.

Speaker 9

All right. That's all I had. Thanks, everyone.

Operator

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

Speaker 1

Well, thank you for joining us this morning. We appreciate your

Operator

This concludes today's conference call. Thank you for joining. You may now disconnect.

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