VTLE - NYSE

Good day, ladies and gentlemen, and welcome to Vital Energy, Inc.’s Fourth Quarter and Full Year 2022 Earnings Conference Call. My name is Mandeep, 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.

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 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 fourth quarter 2022. The press release and presentation can be accessed on our website at www.vitalenergy.com. I’ll now turn the call over to Jason Pigott, President and Chief Executive Officer.

Thanks, Ron, and good morning, everyone. We appreciate you joining us this morning. We posted strong results in the fourth quarter and full year 2022 and build value on a foundation of recent oil-weighted acquisitions and the efficient development of our quality portfolio. For full year 2022, we had a strong year with the following highlights. We generated $220 million of free cash flow and $913 million of consolidated EBITDAX. We purchased $285 million of term debt and $37 million of common stock, reducing our leverage multiple 44% from 2.14x to 1.18x. We also grew production 19% compared to full year 2021. During the fourth quarter, we generated free cash flow almost $37 million, we sold nonoperated properties for $110 million, and we repurchased more than $100 million of face-value term debt and almost $11 million of common stock. Operationally, our oil and total production were above the high end of guidance. We showed continued capital discipline, with capital expenditures below expectations. We limited the production impact of severe weather in late 2022 that severely disrupted many Permian Basin operators. Now let’s talk about 2023. This is a challenging time for our industry, with oil and gas prices softening over the last few months, and service costs remaining high, resulting in lower margins and cash flow. History says that, too, will find an equilibrium, but this will take some time. We are focused today on what we can control. 2023 plan is designed to maximize free cash flow, with emphasis on developing our highest return assets and maintaining the strong balance sheet that we have worked so hard to achieve. ‘23 plan, excluding the recently announced Driftwood acquisition, is largely focused on our most productive acreage in North Howard County, where we are seeing strong oil production. Current commodity prices, our 2023 development plan, is expected to generate more than $70 million of free cash flow. Development drilling continues to bolster our inventory as we have maintained about 8 years of oil-weighted inventory, organically adding Wolfcamp D locations in Glasscock County that offset reductions in our Wolfcamp B inventory. For the past 3 years, we have observed growing industry activity in the Wolfcamp D around our Glasscock County acreage. These results, combined with our own previous drilling results, underpin the addition of 80 Wolfcamp D locations in Glasscock County. On Slide 6 of our earnings presentation, we plot industry activity in the Wolfcamp D around our leasehold and show the results from wells that we have developed with modern completions. Last week, we announced that we signed a purchase agreement for the acquisition of the assets of Driftwood Energy. This acquisition gives us a foothold in a prolific part of Upton County, adding about 30 high-margin oil-weighted locations and high-oil cut production. Our disciplined approach for creating scale was rewarded with this accretive transaction, and we are confident that it will generate material future value for Vital Energy. On Slide 8, we show the productivity of the acquired PDP wells. I believe the undeveloped locations will be competitive with portions of Howard County. We plan to develop this asset over the next several years without increasing activity levels. We have high confidence in our 2023 plan. Our team is executing extremely well today. We plan to maintain capital discipline and a steady pace of development that will allow us to capture synergies and capital efficiencies. Financially, we have prioritized free cash flow, high margins and maintaining a strong balance sheet. Now I’ll turn the call over to Bryan for a financial update.

Thank you, Jason. I’ll start with some comments around our capital budget. Our 2023 capital investments are expected to be between $625 million and $675 million. Prices have fallen over the last few months, and service costs have yet to adjust. We know this takes time, but we have factored in approximately 15% inflation over 2022 average levels. Capital expenditures are slightly front-end loaded in 2023, with around 55% of capital expected to be invested in the first half of the year. Currently utilizing a second completions crew, which we plan to release at the end of the first quarter, taking us down to 1 crew for the remainder of the year. We expect to operate 2 drilling rigs throughout the year, as continued efficiency gains and our drilling operations allow them to stay ahead of our completions crew. We announced last week our acquisition of Driftwood. We expect this transaction to close in early April, and it will add PDP production of approximately 3,400 BOE per day, 50% of which is oil, the last 9 months of the year. We will update our combined production guidance at the closing of the transaction. As part of the Driftwood purchase, we also received 4 DUCs in Upton County that will be worked into our completion schedule this year. So we do not currently anticipate the acquisition will add any capital to our 2023 projections. Finally, we expect a decrease in our RBL net draw from our current net draw of approximately $120 million. This mid-February amount includes 3 weeks of payables and no offsetting revenue for February, which will be received later this week. It also includes our semiannual interest payments from January and the Driftwood acquisition deposit. We expect quarter-end increases in net borrowings to reflect mainly the interest payments and the deposit. I will now turn the call over to Katie Hill, who joined us last year as Vice President, Operations.

Thank you, Bryan. In the fourth quarter, we returned to operating at our high performance expectations. Both oil and total production exceeded the high end of our guidance ranges, despite late December freeze events. Our outperformance was driven by improving uptime, upsizing to larger ESPs and increasing deployment of our production optimization technology. With upside ESPs, we unloaded wells more efficiently, brought new oil production online sooner and more quickly returned frac hit wells to previous production performance. Our winterization preparation delivered weather-resilient operations throughout the fourth quarter. We continued field-wide deployment of production optimization technology to improve bottom hole pressure drawdown and production uptime, and we began to realize the impact of our multiyear digital operations cultural transformation. This performance is also driving production volumes reflected in our guidance for first quarter 2023. Oil production for the year will continue to exhibit some volatility due to the timing and number of new wells. Based on our current development schedule, we anticipate daily production to peak in Q3 for the year. Increasing fluid production from our oil-weighted high-margin development plan will impact 2023 operating costs. The LOE guidance reflects an increase in total water production year-over-year, increase per-barrel water handling cost and additional electrical infrastructure development. This infrastructure will support continued efforts to electrify other operational components of our development plan, including our primary frac fleet and in-field compression. Operator, please open the line for questions.

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

Congrats on a strong year-end. For my first question, I wanted to focus on the bigger picture for Vital now that you’ve expanded into Upton and you’ve added organic inventory into Wolfcamp D. With what’s been announced to date and the potential you’ll likely have in the Wolfcamp C interval in the Deadwood area, could you comment on your degree of confidence in the 8 years you’ve outlined and share your thoughts on what’s the right depth of inventory to attain a fair peer multiple?

Great question. I’ll answer the first part, and then I’ll turn it over to Kyle to tell you a little bit more about what our development plans for the Driftwood area. For us, again, we’re -- we feel good about the 8 years that we’ve added. Again, when I started, we pretty much wiped the slate clean on inventory and have built the inventory we have today, both organically by testing new formations like the Wolfcamp D or the Wolfcamp B and Howard -- or sorry, the Middle Spraberry in Howard County as well as the acquisitions that we’ve done and we’ll continue to do. So for us, I think what we want to continue to do is build scale, continue to do acquisitions. The ideal acquisition for us is $400 million to $500 million. It will bring in 50 to 100 locations. It’s probably $250 million to $300 million in PDP. So those are the ideal things that we try to do that will -- again, if we can continue to do them 1 or 2 per year, we’ll eventually grow inventory. And we think more -- not extending our inventory to 10 years, but bringing in inventory that will start to feed a third rig and a half completion crew and, ultimately, 2 completion crews, which will give us stability when we bring in 12 wells a quarter, again, move production volumes up and down pretty significantly each quarter. But as we roll the dice more and are drilling 100 wells per year, that allow stability in the production forecast. It allows us to grow. So I think those are the things that will ultimately lead us to the higher multiples. Again, we’ve been doing it consistently. We didn’t do as much last year, but we had this one kind of in the works for a while and have a strong start for 2023. I’ll now turn to Kyle just to talk a little bit about the Driftwood.

Yes. So on Driftwood, we underwrote that acquisition with our inventory in the Wolfcamp B. There are 2 primary Wolfcamp B targets, the upper and the lower, and we used a conservative spacing assumption of 4 wells per targeted intervals, so 8 wells per section. So really, all the inventory that we’re talking about here, the 30 wells, is all in the Wolfcamp B. But as you mentioned, there are -- this is a stack pay environment. There are Wolfcamp C wells to our South, into our Northwest. We view that as an upside target that we’ll be looking at closely to add even future inventory beyond what we’ve already stated in our release.

Terrific. And as my follow-up, and perhaps for Katie, in light of your Q4 production performance and stronger-than-expected 2023 production guidance, could you expand on the impact technology is having on base production optimization and how differentiated your approach is relative to the industry?

Yes. Another great question, Derrick. I’ll take the first part of this and then turn it over to Katie to talk about the operations. When I started with the company, we really want to put in place this digital-first mindset. We took our existing IT infrastructure and pretty much scrapped it. We’ve taken everything to Amazon’s cloud and kind of run our data lake and a lot of our operations off of that. And what that does is allow us to use machine learning algorithms, AI to optimize our production. For example, 25,000 of our 35,000 barrels per day are on submersible pumps, and we’re using things like machine learning to change the frequency of the pumps, the pressure we hold on them to both extend life and get more production out of the well. So I think those are the things that we are doing that no one -- none of our peers are doing it, so we’re a leader in that respect. But I’ll turn it over to Katie, and she can tell you a little bit about what they’re doing to optimize how we run our routes every day.

Thanks, Jason, and good morning, Derrick. I think in 2022, I would categorize a lot of our operational focus as moving this technology from design into our demonstration phase. We achieved really repeatable success in implementing our dynamic routing and some of the base optimization technology that Jason talked about. These tools have helped us over-deliver on our production expectations, as you saw for Q4, primarily by reducing response times for our operators, increasing our production uptime and preventing subsurface failures, specifically on ESPs, although we’re excited to expand that to other artificial lift types. I would anticipate the technology continuing to evolve as we continue to deploy the technology across the assets, particularly focusing on different lift types as we move away from ESPs, depending on where we are in the area.

Our next question comes from the line of Gregg Brody from Bank of America.

Just a couple of questions for you. First, could you just give us an update on how you’re thinking about your long-term debt reduction plan? Has that changed at all as a result of the Driftwood acquisition?

This is Bryan. No, it hasn’t changed. I mean, our primary focus is debt reduction and achieving a debt leverage ratio of below 1x, and you’ll continue to see that be our focus. M&A obviously plays a part in our business, and so we just have to navigate around that. But our focus is getting that debt down below 1.0x, and that has been for a couple of years, and we’ll continue on that.

And I think you also had an implied debt target in there. Has that changed at all?

Yes. We had an implied debt target of approximately $700 million last year. I think that will change modestly with acquisitions. That one was targeting basically an EBITDA level at a $55 to $60 price environment. So as we update our projections for acquisitions, you’d probably see it change directionally along those same lines.

Got it. And then just the -- you have the [25] there, which -- curious how you’re thinking about them. Or sort of any refinancing your capital structure in general?

Yes. We’re looking at ways to continue to pay those down. We have the ability to call them under the revolver and pay them down with cash flow. So as the year progresses, we’ll evaluate everything. A lot of it will depend on the M&A markets and what success we have there, but we’re keeping an eye on all the markets.

Just last question for you. You commented on the increase in costs that you expect this year on the operating side. I see, for the guidance number you gave for first quarter, is that a fair number to assume for the year? Or does that -- will that change at all?

I think it’s directionally accurate for the year. We are excited to continue to grow in Howard County. And as we bring some of those oil-weighted, really, high-margin wells online, we’re increasing our total fluid production. So that operating cost reflects continuing to build out our water and electrical infrastructure to support Howard County development.

Yes. Katie is referring to LOE. On the capital side, again, we’re going to be more heavily weighted for the first quarter just because of that extra frac crew that’s running in the first quarter. And then capital will come down in future quarters as that crew is released.

Our final question comes from Nicholas Pope from Seaport Research.

I was hoping you could talk a little bit about -- I guess, 2 parts here. With the Driftwood asset, kind of curious how you think the returns kind of fit into the whole hierarchy of what you have in Howard and in Glasscock. And also just really the well cost, as you look at the new Driftwood assets, are we expecting the same kind of lateral length, same kind of size of wells as you look at -- and well costs down there in this Upton -- this new Upton asset compared to kind of what you have in hand in Howard and in Glasscock?

Yes, that’s a great question. On our deck that’s published online, we have a -- sorry, I’m on the wrong here. Slide 8, sorry, I got a new deck. On Slide 8, we have a production comparison of the wells from Driftwood versus Howard County, Western Glasscock. So the wells at Driftwood are very comparable on the production side to our wells in Central Howard County. And then what we’re working through now is just completion optimization and things like that. So I’ll turn it over to Kyle for a little more color kind of on how we’re thinking about that.

Yes. So I would say from a capital cost perspective, there’s a lot of similarity between our Howard County wells and what we’re modeling here for Upton and Reagan. You asked a question about lateral length, all of the inventory, the 30 wells that we’re talking about are all 10,000-foot laterals, so very similar to our base development plan that we have in Howard County and in Western Glasscock. So I would say a lot of similarity in the capital cost, not a material difference between the two.

And there’s -- from a geometry standpoint, there’s no problem being able to kind of -- I think you’ve been averaging 11,000 foot up in Howard. Are you all able to get the 10,000-plus type laterals with the kind of footprint that you have in Upton?

So in Upton, it really is 10,000 foot is kind of the base design and kind of what we’re planning on based upon the footprint. The reason that we’re averaging 11,000 up in Howard is because we often have 15,000-foot laterals that are kind of sprinkled into our development plan. But typically, we either drill 10s or 15s. Those are kind of our 2 types of designs that we typically drill. But in Upton, it is all 10,000-foot laterals.

That concludes today’s questions. I would now like to turn the call over to Ron Hagood for closing remarks.

I’d like to thank you for joining us this morning, and we appreciate your interest in Vital Energy. This concludes today’s call.