Vitesse Energy, Inc. (NYSE:VTS) Q1 2023 Earnings Call Transcript

Vitesse Energy, Inc. (NYSE:VTS) Q1 2023 Earnings Call Transcript May 12, 2023

Operator: Greetings. Welcome to Vitesse Energy First Quarter 2023 Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. Please note that this conference is being recorded. I will now turn the conference over to Ben Messier, Director of Investor Relations. Thank you. You may begin.

Ben Messier: Good morning, and thank you for joining. Today, we will be discussing our financial and operating results for the first quarter of 2023 which we released yesterday after the market closed. You can access our earnings release and presentation on our Investor Relations website and our Form 10-Q as filed with the SEC yesterday. I’m joined here this morning with Vitesse’s Chairman and CEO, Bob Gerrity; our President; Brian Cree; and CFO, Dave Macosko. Our agenda for today’s call is as follows. Bob will provide opening remarks on the quarter. After Bob, Dave will review our Q1 2023 financial results. After the conclusion of our prepared remarks, the executive team will be available to answer questions. Before we begin, let’s cover our safe harbor language.

Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to the risks and uncertainties, some of which are beyond our control that could cause actual results to be materially different from the expectations contemplated by these forward-looking statements. Those risks include, among others, matters that we have described in our earnings release. We disclaim any obligation to update these forward-looking statements, except as may be required by applicable securities laws. During our conference call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA and adjusted net income.

Reconciliations of these measures to the closest GAAP measures can be found in the earnings release that we issued yesterday. Now, I will turn the call over to our Chairman and CEO, Bob Gerrity.

Bob Gerrity: Thanks, Ben. And I want to thank Ben for his work in the quarter, communicating with analysts and in new investors and prospective investors. You’ve done a great job. He understands the model and represents Vitesse very well. So thanks, Ben. So good morning, everybody, and thanks for participating. The first quarter of 2023 went according to plan. We completed our spin-off from Jefferies, acquired Vitesse Oil and now operate as a fully integrated independent public company. We paid our first quarterly dividend of $0.50 a share, mostly increased our production and reduced debt. Vitesse is focused on returning capital to its stockholders, paying the quarterly dividend is at the top of our returns based capital allocation strategy.

As such, we have declared our second quarterly dividend of $0.50 a share to be paid in June 2023. Our asset generates significant cash flow and includes a deep inventory of more than 20 years of economic drilling locations. The conversion of undeveloped inventory to producing wells is key to our business model. Organic drilling, coupled with near-term development acquisitions in the first quarter, will continue to support our cash flow profile. So I’m going to turn this over to Dave Macosko, Brian Cree, who is our President and will normally have prepared remarks, he is actually in North Dakota this week, and hopefully, will join us in the Q&A, but he won’t have formal remarks. So now to Dave Macosko, and congrats to Dave and his accounting staff for a terrific reporting session in the K and in the Q.

So Dave, with that, pat on the back, go for it, buddy.

Dave Macosko: Thanks, Bob, and good morning, everyone. I’ll give a quick overview of our financial performance for the first quarter of 2023. We reported a GAAP net loss of $47.8 million, reflecting $77.4 million of charges all of which are onetime or nonrecurring in nature associated with the spin-off. These charges include again, a one-time noncash income tax expense of $44.1 million related to a change in corporate tax status as we move from an LLC to a C-corp. An acceleration of $26.8 million of non-cash equity-based compensation expense and $6.5 million of transaction costs that were included in our G&A expense. All spin-related costs have now been run through our income statement. Adjusted net income for the quarter was $15.6 million using our statutory income tax rate of 23.4%.

Adjusted EBITDA was $40.1 million, an increase of 6% over the prior quarter. Our first quarter production was up 20% from the first quarter of 2022 totaling 11,524 Boe per day, with oil representing 67% of production and 87% of our total revenue. Total revenue, including the effects of our realized hedges, was $59 million compared to $52 million for the first quarter of 2022 despite a 20% drop in WTI oil prices and a 42% drop in gas price. Lease operating expense in the first quarter increased 17% compared to the first quarter of 2022 on a per Boe basis as we saw many operators allocate more capital to workovers on existing wells. Cash G&A of $10.9 million, again included $6.5 million of spin-related costs. Capital spending for Q1 2023 was slightly above maintenance levels as we spent $22.7 million on development CapEx due to an acceleration of development activity from one of our operators.

At the end of the first quarter, we had $45 million drawn on our credit facility, down $8 million from $53 million at the time of our spin-off. We recently completed our spring borrowing base redetermination, which resulted in a decrease of our borrowing base from $265 million to $245 million due to lower commodity prices. Our elected commitments of $170 million did not change. We still have substantial liquidity available on our credit facility, even with the slight borrowing base reduction. As a reminder, Wells Fargo Bank is the administrator of our credit facility. From an operations standpoint, we had 7.2 net wells that were either drilling or in the completion phase and another 10 wells that have been permitted for development by our operators as of March 31.

At the end of last week, there were 42 rigs drilling in the Williston Basin, with more than 50% of the rigs on acreage, which Vitesse owns an interest in. With respect to guidance, we reaffirm our previously issued 2023 annual guidance. With that, I’ll turn the call over to the operator for Q&A.

Bob Gerrity: Thanks, Dave.

Q&A Session

Operator: Thank you. At this time, we will be conducting a question-and-answer session. And our first question is from Steve Richardson with Evercore ISI. Please proceed with your question.

Q – Unidentified Analyst: Yes. Hi. This is Chris Baker on for Steve. Good morning, guys.

A – Dave Macosko: Hi, Chris.

A – Bob Gerrity: Good morning.

Q – Unidentified Analyst: Bob, our first question is for you. Just hoping you could talk about the M&A landscape, what you’re currently seeing in terms of the opportunity set, I guess, both on the small-scale side as well as larger deals.

A – Bob Gerrity: Yes Chris, we’ve been doing this for 10 years, and there’s a certain rhythm to the deal flow. And I can’t say that it’s more or less than it has been over the last couple of years. We have a vibrant flow of near-term drilling, especially in the Bakken. But I can’t say it’s substantially higher than it has been in the past. There are some bigger deals being – are being chopped around, we look at everything, Chris. And again, we will not do — we’d love to do a bigger deal — but we’ll not do a bigger deal unless it’s supportive or expansive to our dividend.

Q – Unidentified Analyst: That’s great. Thanks. And just as a follow-up, great to see Vitesse having some significant exposure to rigs running in the Bakken. Anything you can share in terms of operator behavior and maybe any leading-edge trends you’re seeing on the oilfield service cost side of the equation would be great. Thanks.

A – Bob Gerrity: Yes. Chris, last year, we did see a single-digit rise in drilling and completion costs, not from every operator, but from about half of the operators. We’ve seen that now come back off and we’re actually seeing lower average drilling completion costs now than we did a year ago. So that trend is encouraging. We do like the Independents, Grayson Mill and Kraken have done a very good job in the wells that they’ve drilled. Again, they’re a little bit outside of what people formally call the core, but their economics are very attractive. So nothing — sorry, one other quick thing is Continental is the most active operator up there, and they have stepped out of where they have traditionally drilled and have gotten very good results. So we think Continental go and private has been a good move. So we’re happy about that, Chris.

Q – Unidentified Analyst: Great. Appreciate the color, guys.

A – Bob Gerrity: Thanks, Chris.

Operator: Thank you. Our next question is from Donovan Schafer with Northland Capital Markets. Please proceed with your question.

Donovan Schafer: Hi, guys. Thanks for taking my questions. And congratulations on the boring quarter, essentially to second half In line with what you know say and do what you say you’re going to do and just kind of being in line with that and consistent on all that. So, that’s great. I mean I know that’s kind of your intention. So, that’s good. I want to stay — stick with this theme just on kind of what the last question I was asking about like the step-outs you mentioned Kraken and Continental moving kind of outside the core. There are some other companies reported last week, talked about, yes, like Tier 2 wells performing more like Tier 1 wells. So, I’d like to see if we can just get an update on — you’ve got the deeper — I’m going to get the words wrong, but I think you call it like deeper, denser, wider, like the deeper, denser, wider thesis that you guys in a prior company, you succeeded on in the DJ Basin and now you’re trying to do that in the Williston.

Are we seeing — can you kind of isolate each one because it seems like deeper maybe isn’t quite as relevant in this kind of basin. But is it more — are you seeing more improvements on the denser side or the wider side or all of it? Just kind of any granularity and incremental nuggets and what you’re seeing in terms of like well productivity and what’s driving it?

Bob Gerrity: Yes, great question, Donovan. So, the original thesis when my wife and I started with our work map on our kitchen table, was that the Bakken would get deeper, denser, cheaper, better, expanded. And what that means is deeper, originally, the Bakken was just developed as the Bakken. We thought that the Three Forks would be productive at some point. That came to be, so it was deeper. Denser, we bought most of our inventory based on economics for four Bakken wells only per DSU. Now, since 2010 up to about 2017 to 2018, operators experimented with putting a lot of more wells into each DSU. That didn’t necessarily result in the best economics. So, they backed off of that heavy number and relied on improvements in frac technology.

So, anywhere from six to eight wells per DSU is now the standard. And we’re recovering a tremendous amount more oil out of each DSU than we were over the last 10 years. The cheaper is that the wells would — as infrastructure would be built out, the wells would become more economic, that has happened. Better, the EURs in the Bakken, almost on a daily basin — basis, get better. You got to remember the Bakken is such an incredibly, incredibly tight rock. If you can increase your recoveries by just 2% or 3% then that is highly economic. So, technology developed slowly, but it continues to evolve and every day, we see better wells than we saw before. So, we’re very encouraged that over the course of time, frac technology will continue to improve recoveries.

We don’t — we look at Tier 2 to Tier 1, but what we really look at is the economics. Sometimes, if you take a look at, what would be considered a Tier 4 area, for that Tier 4 is considered just on an, EUR basis. While the drilling cost in that area by that operator is lower than some of the stuff in the Tier 2 or Tier 1 locations. And therefore, that economics are actually better. So you got — you have to differentiate between Tier 1 and Tier 2 economics and Tier 4 or Tier 5 economics. So we do this all the time. The field is constantly changing. And we think for the better. So, Donovan, I’m sorry about the long answer, but that’s really core to what we do.

Donovan Schafer: Okay. No, that’s great. And then kind of following up on that, I want to talk about refracs a little bit, because I think, you can argue that, that would tie into the same kind of thesis and you talked about recovery rates. So when you talk about the huge improvement in economics from just improving that a couple of percentage points, I think you’re correct me if I’m wrong on this, I have to go back to my petroleum engineering base. But you’re framing that probably in terms of like figuring out, okay, what the total oil in place in this sort of cubes you kind of model out some cube of reservoir area. And a lot of times, you’re only recovering something less than in a shale play maybe 10% or potentially less.

And so you’re talking about going from picking numbers like a 10% going to 12%, that’s more of like — even though it’s 2% — on those terms, it’s a 20% increase in the volume. So — when you look at the old wells, the Bakken is an old basin now kind of at this point, certainly compared to the shale type development in places like the Permian — so it’s pro now — it’s going to hit — it’s going to be one of the earlier basins, shale basins versus others where it starts to become sensible with all the advances in technology — so you — do you have a sense of like some of the early wells being able to go back and say, gosh, we think this is really only a 6% recovery. And given all the changes that we’ve done with technology and frac designs and everything and being able to go back and say, “Well, we were really only in zone for third of the wellbore, third of the lateral and the other two-thirds of the lateral weren’t even landed properly.

Can you give us a sense of what potential you’re seeing there? And actually, I mean, if you do know the recovery numbers, I actually would be really curious where you think they were in the beginning and where they are today and what — the implied amount you could come back and recover with refracs?

Bob Gerrity: Right on. So Donovan, I don’t think anybody — in fact, I’m sure no one really knows the initial recovery rate. But in our shop, we do ascribe to that 9% to 10% in initial recovery percentage. So that’s — it’s not far off. I’m looking at a map in our conference room right now that has identified all wells that we believe will be refracked and it is shocking how many wells are perspective to be refracked. And it’s all over the basin. Remember, the field was developed maniacally to hold it by production in — from 2008 to 2012, all of those wells are perspective to be refracked. From 2012 until they move from gels to slick water, all of those wells are perspective to be refracked. We’ve seen a threefold increase in the last six months and operators starting to refrac wells.

We believe that, that refrac technology is really new. And they’re — it’s — we’re not sure if the refrac technology is going to improve faster than standard fracturing technology, but the cost will certainly come down. I will — the last thing I’ll say about refracs is, look, the economics of a refrac are extraordinary. They’re the best economics we have out in the field. One of the negatives for an operator to refrac is that you really need to shut in the rest of the DSU. So your production in that DSU will initially go down. So the timing of refracs is very difficult to ascertain. There is one operator that has proposed refracking five wells in one DSU. We have not seen the results from that. I can’t say if that’s a good thing or a bad thing, but refracs will be a wildly economic future in the Bakken.

Donovan Schafer: Okay. And then just one last question to follow up on that. Is it — with the refrac is your sense that it’s kind of like a broad-based uniform potential, what I mean by that is, you can imagine in case where sort of entire vintages or entire years, say, every well drilled from 2014 to in 2017 or something it was done this way, at the scale. And so that entire — that whole bundle of DSUs or whatever, that would be one perspective. Another perspective, would be, well, you didn’t have as good a well control early on. I don’t think as many companies were doing like the gamma-ray you cannot put a gamma-ray inspector on the back of the bit. And so today, you know, am I in zone or am I not in real time as you’re drilling the lateral.

And it wasn’t the case before, but now you have so much well control, even if you didn’t get that reading the first time, you could probably go back and actually come up with those conclusions, after the fact now. So maybe you’re not — it’s not widely uniform, it’s maybe kind of rolling the dice each time and it’s more like you can go back and look and say, oh, one in six of those dice rolls early on is badly out of zone. And so maybe we’d even re-drill it because we just don’t even think this thing, this lateral is even there or even really that type of thing versus this much broader just uniform everywhere? Is it more one, more the other, maybe a mix of both, and it’s more the latter case where refracs will start first before migrating to more uniform?

Bob Gerrity : Yes. It’s a good question, and there’s no perfect answer for that. Wells drilled between 2008 and 2011, often we’re out of zone. So you’re absolutely right about that. Whether or not you can go in and refrac that well, that is mildly out of zone or not? I don’t know. And that I don’t think has been proven yet. You got to remember that the Bakken is such a closed unit that — in the Bakken, we have a halo effect. When you refrac or frac a well in a DSU, the parent wells actually have their production increased. So again, it is a different basin. And I think that the, you know, where you refract, the intensity you refrac, it all needs to be worked out and it needs to be bespoke to each different DSU, both as you said, by vintage and by an initial frac technique. So again, when you refrac well, you often increased production in the surrounding wells. So it’s a different beast. It’s very tight.

Donovan Schafer: Yes. And — I can, kind of, feel like almost like unprecedented levels of data for going back into an area like this. So a lot of engineers, a lot of sensing, a lot of fascinating analysis stuff that goes into it. Okay. Well, I’m going to leave at that. I’ll take the rest of my questions off-line or follow up with you guys. But – yeah, congratulations on the quarter. And I will second what you said about Ben. He’s been doing great.

Bob Gerrity: Thanks. And I’ll reaffirm what you said is, we try very hard to be boring. So thanks for that comment.

Ben Messier: Thanks, Donovan.

Operator: Thank you. Our next question is from Lloyd Byrne with Jefferies. Please proceed with your question.

Lloyd Byrne: Hi. Good morning, Bob. And I don’t know if Brian is on, but – good morning. The I’d love to go back to the M&A market for just a second. And I’m kind of wondering whether you said, kind of, the deal flow is the same, but whether with the lack of capital out there for the space, you get more opportunities going forward? And then maybe on the back of that, whether you’d ever go out of basin going forward as well?

Bob Gerrity: Yes. So good questions. Questions we ponder every day. We would definitely go out of basin. We’ve got a little interest in the Powder River Basin, mostly in the mud rocks, which we’ve done well with. We think the Powder is prospective. It’s just too expensive now for us to do anything meaningful there. We managed some assets for Jefferies in the Eagle Ford. We like the Eagle Ford very much. We think that’s prospective. We do not see a lot of deal flow in the Eagle Ford. We do have a fair position in DJ. Love the DJ and have done extremely well there, but we don’t think that, that is something that we’re able to get much scale with. We look at two or three days of well proposals a day in the Permian. And it can’t really compete to what we’re seeing in the Bakken.

So wide open for the Permian, we have some organizational experience the Permian, but it — right now, the bread and butter in the Bakken is still the best we see. So that’s going outside of the basin. We have seen on the larger $100 million — $500 million deals. We have seen more flow. And I would love to do one of those deals if it would be supportive of our dividend. Most of those deals are right now, price so that they’re not that attractive to us. Again, we’re not looking for scale, we’re greedy as it comes to looking for something that would bolster the dividend.

Lloyd Byrne: That makes sense. I just also want to go back to the 42% of rigs operating on the acreage. I know it was mentioned earlier. But can you just tell me whether that’s higher or lower than in the past? And then that seems like an awful high run rate for the inventory and just does that tell us about the inventory quality? Is it because it’s pushing out into Tier 2 and Tier 3 acreage?

Bob Gerrity: Yeah. It’s a little bit of that. That’s true. And that’s higher, the 40%, 50% of rigs running on our acreage. That’s higher than normal but it’s not that out of line. We average about Dave, about one-third. About one-third of all the rigs running in the Bakken on our acreage. And that’s because we’re like a Bakken EPF, right? We got well we have acreage all over everywhere. So yes, I think that’s — your conclusion that the rigs are spreading out pretty good. Yes, we would agree with that.

Lloyd Byrne: Okay. Awesome. And I have one more. Can you just talk about the CapEx run rate going forward. I mean, as you get the refracs and you got some inflation in there, — but how do you see that for — maybe over the course of the rest of the year?

Bob Gerrity: Yeah. It’s very lumpy, Lloyd. I would love to say that we’re going to be able to replicate what we did in the first quarter, each of the quarters, but we can’t — it’s — we’re not in control of that. That is a negative being the non-op. And if we have similar CapEx in Q2, maybe we will change our guidance. But at this point, it’s too premature. But I got to tell you, we are very excited about the CapEx that we had in the first quarter. And again, more CapEx is a very good sign for us because we’re very disciplined in what we drill. And remember the lag between CapEx and production is roughly a year, less than that on refracs, but we know that gap.

Lloyd Byrne: That’s great. And I appreciate all the commentary on the Bakken productivity. It’s interesting. So thank you very much.

Bob Gerrity: Thank you, Lloyd.

Operator: Thank you. Our next question is from Jeff Grampp with Alliance Global Partners. Please proceed with your question.

Jeff Grampp: Bob and Tim thanks for the time.

Bob Gerrity: Hi, Jeff.

Jeff Grampp: Good morning. Philosophical question for you, Bob. Obviously, you guys have a super clean balance sheet. You’re returning a lot of capital to shareholders through the dividend oil prices are being a bit volatile here in the near term. How are you guys thinking about allocating capital to ground game opportunities? Is that kind of constraint to organic free cash flow, or would you guys periodically use the balance sheet if you saw some good opportunities come across your desk?

Bob Gerrity: Yeah. We would use the balance sheet, Jeff. No doubt about it. But again, we do — we’re specialists, especially in the Bakken. So our hurdle rates for the wellbore interests we buy are pretty high. So we probably whatever we can. It’s not limited by budget. It’s limited by opportunity and economics. So philosophically, we — if you see our CapEx go up — that’s a good thing. We would use our balance sheet, if we saw an extraordinary opportunity, but not just to grow. Did that answer your question, Jeff? I can be more philosophical if you want.

Jeff Grampp: No. That was perfect. I appreciate it. And just a smaller housekeeper on the modeling side. You mentioned LOE was a bit elevated due to some workovers, any sense of where that kind of levels out or how we should think about LOE going forward? Is Q1 a bit of an aberration on the high side, or any commentary there would be helpful.

Bob Gerrity: Great. I’m going to ask Dave to answer that one.

Dave Macosko: Okay. Jeff, this is Dave Masco. I think what we saw is a lot of workover activity in Q1. I think going forward, we’ll see that level off. We’ll be sitting right in that $8.50 to $9 per BOE range of LOE going forward.

Brian Cree: A lot of that’s depending on the seasons, right? There’s seasonality in that first quarter. Obviously, as it gets warm or things will get cheaper to operate.

Jeff Grampp: Understood. Perfect. Very helpful. Thanks a lot guys.

Bob Gerrity: All right, thanks, Jeff.

Bob Gerrity: All right. Thanks, Jeff. Well, that’s it for now. We really appreciate you guys listening again, and please reach out to Ben, if you’ve got any further questions, and we’re going to go back to being boring. So thanks, everybody. Bye-bye.

Operator: Thank you. This concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation.