Greetings. Welcome to Vitesse Energy's 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.

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.

Thanks, Ben. And I want to thank Ben for his work in the quarter, communicating with analysts and with 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.

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 prices. 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, in which Vitesse owns an interest. 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.

Thanks, Dave.

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

Yes. Hi. This is Chris Baker on for Steve. Good morning, guys.

Hi, Chris.

Good morning.

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.

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 shopped around; we look at everything, Chris. And again, we would love to do a bigger deal, but we will not do a bigger deal unless it's supportive of or expansive to our dividend.

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.

Yes, Chris, last year we experienced a modest increase in drilling and completion costs, but this was not the case for all operators—about half saw this rise. Currently, we've noticed a decline in average drilling and completion costs compared to a year ago, which is a positive sign. We have a favorable view of the Independents; Grayson Mill and Kraken have performed exceptionally well with their wells. While their operations may not be considered part of the core region by some, their economic results are very promising. Additionally, Continental has been the most active operator lately, venturing beyond their usual drilling areas and achieving excellent outcomes. We believe that Continental's decision to go private has been beneficial, which makes us optimistic, Chris.

Great. Appreciate the color, guys.

Thanks, Chris.

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

Hi, everyone. Thank you for taking my questions, and congratulations on a steady quarter. The second half aligns with your commitments, demonstrating consistency, which is great to see. I want to continue discussing the earlier question regarding the developments you mentioned with Kraken and Continental moving beyond their traditional areas. Some other companies have reported that their Tier 2 wells are performing similarly to Tier 1 wells. I’d like to receive an update on the deeper, denser, wider strategy you previously succeeded with in the DJ Basin and are now implementing in the Williston. Can you provide details on how each aspect is performing? It seems like the deeper element may not be as relevant in this basin, so are you noticing more improvements in the denser or wider aspects, or across all areas? Any insights on well productivity and the factors driving it would be appreciated.

Yes, great question, Donovan. When my wife and I started our work map on our kitchen table, we believed that the Bakken would become deeper, denser, cheaper, and better. Initially, the Bakken was developed solely as the Bakken, but we anticipated that the Three Forks would eventually prove productive, which it did. In terms of density, we based our inventory decisions on economics for four Bakken wells per DSU. However, between 2010 and around 2017 or 2018, operators experimented with increasing the number of wells in each DSU, which didn’t always yield optimal economics. Consequently, they scaled back and focused on advancements in frac technology. The current standard is now six to eight wells per DSU, leading to significantly higher oil recovery from each DSU compared to the past decade. In terms of cost, as infrastructure has developed, wells have become more economical, which has indeed occurred. Our understanding of better recovery has improved continuously; the EURs in the Bakken are getting better almost daily. It's important to note that the Bakken is incredibly tight rock, and increasing recoveries by merely 2% or 3% can be highly beneficial economically. While technology has evolved slowly, we consistently observe better well performance over time, which encourages us to believe that frac technology will further enhance recoveries. We analyze not just Tier 2 and Tier 1 but also consider the economics of Tier 4 and Tier 5 areas. Sometimes, a Tier 4 area, based on EUR, may have lower drilling costs than some Tier 2 or Tier 1 locations, resulting in better economics. Therefore, it is essential to distinguish between Tier 1 and Tier 2 economics and Tier 4 or Tier 5. We are constantly adapting to changes in the field, and we are optimistic about the future. Sorry for the lengthy explanation, but that’s really central to what we do.

Okay, that's great. I want to discuss refracs a bit because they relate to the same thesis, especially regarding recovery rates. When you mention the significant improvement in economics from increasing recovery by just a few percentage points, I believe you're framing this by estimating the total oil available in a specific reservoir area. Often, in a shale play, the recovery can be less than 10%. If we consider increasing recovery from 10% to 12%, despite being just a 2% increase, it's actually a 20% rise in volume. Looking at older wells, the Bakken is now considered an older basin compared to newer developments like the Permian. It's likely to be one of the first shale basins to benefit from advances in technology. Do you have insights on the early wells that show a recovery of only around 6%? With all the technological advancements, could we revisit these wells and find that we were only accessing a third of the wellbore effectively? What potential do you see there? If you have recovery estimates, I would be interested in knowing what the initial recovery rates were compared to now and how much more could be recovered through refracs.

Right on. So Donovan, I don't think anyone really knows the initial recovery rate. However, we estimate that the initial recovery percentage is around 9% to 10%. I'm currently looking at a map in our conference room that shows all the wells we believe will be refracked, and the number of prospective wells is surprising. It's widespread across the basin. Keep in mind that the field was developed aggressively to maintain production from 2008 to 2012, making all those wells candidates for refracking. Additionally, wells from 2012 onward, when the industry transitioned from gels to slick water, are also prospective for refracking. We've experienced a threefold increase in the last six months of operators beginning to refrac wells. We believe refrac technology is quite new, and while we are uncertain if it will advance more rapidly than standard fracturing technology, we anticipate costs will decrease. One last point about refracs is that their economics are exceptional. They provide the best economic returns we see in the field. However, one downside for an operator is that refracking requires shutting in the rest of the drilling spacing unit, which initially reduces production. Therefore, determining the timing for refracs can be challenging. One operator has suggested refracking five wells in one drilling spacing unit, but we have not yet seen the results. I can't confirm if that approach is beneficial or not, but refracs are poised to offer significant economic opportunities in the Bakken.

Okay. And then just one last question to follow up on that. Is it your sense that the refrac potential is broadly uniform, meaning that entire vintages or years, like every well drilled from 2014 to 2017, could be approached this way at scale? Alternatively, it's possible that early well control wasn’t as strong and many companies weren’t using gamma-ray technology. They couldn’t determine in real time whether they were in the zone while drilling the lateral. Now, with improved well control, even if the initial readings were not ideal, it’s possible to analyze the results retrospectively. So, perhaps it's not uniformly effective; instead, it might feel more like a gamble, where you could look back and see that a significant number of early wells were not properly situated. This might lead to decisions to re-drill because the lateral may not be accurately positioned. Is the situation more tilted towards one of these scenarios than the other, or is it a mix, leaning more towards the case where refracs will begin in less uniform areas before expanding to more uniform regions?

Yes, that's a good question, and there's no definitive answer. Wells drilled between 2008 and 2011 were often not in the right zone, which you pointed out. I'm not sure if a well that is slightly out of zone can be refracked, and that hasn't been established yet. It's important to understand that the Bakken formation is quite interconnected, and when you refrack or frac a well in a designated spacing unit, the parent wells typically see an increase in production. So it’s a different scenario altogether. The location and intensity of the refrac need to be tailored for each spacing unit, considering the age of the well and the initial fracking technique used. Therefore, refracking a well often boosts production in the nearby wells, making it a unique situation. It's very compact.

Yes, I feel like we are experiencing unprecedented levels of data in this area. There are many engineers and a significant amount of sensing and fascinating analysis involved. I will leave it at that and take the rest of my questions offline or follow up with you. Congratulations on the quarter, and I agree with what you said about Ben; he has been doing great.

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

Thanks, Donovan.

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

Hi. Good morning, Bob. And I don't know if Brian is on, but – good morning. 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?

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 with what we're seeing in the Bakken. So wide open for the Permian, we have some organizational experience in the Permian, but 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 larger $100 million to $500 million deals flow. 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 priced such that they're not that attractive to us. Again, we're not looking for scale; we're greedy when it comes to looking for something that would bolster the dividend.

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?

Yeah. It's a little bit of that. That's true. And that's higher; the 40% to 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 the place. So yes, I think that's – your conclusion that the rigs are spreading out pretty well. Yes, we would agree with that.

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've got some inflation in there, but how do you see that for – maybe over the course of the rest of the year?

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.

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

Thank you, Lloyd.

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

Bob and Tim, thanks for the time.

Hi, Jeff.

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 constrained to organic free cash flow, or would you guys periodically use the balance sheet if you saw some good opportunities come across your desk?

We would definitely consider using the balance sheet, Jeff. However, we specialize in the Bakken, which means our expectations for the wellbore interests we acquire are quite high. Our approach is not limited by budget but rather by the available opportunities and the economics involved. If you notice an increase in our capital expenditures, that would be a positive sign. We would use our balance sheet if we identified an exceptional opportunity, but not just for the sake of growth. Did I address your question, Jeff? I can provide more detailed thoughts if needed.

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.

Great. I'm going to ask Dave to answer that one.

Okay. Jeff, this is Dave Macosko. 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.

A lot of that's depending on the seasons, right? There's seasonality in that first quarter. Obviously, as it gets warmer, things will get cheaper to operate.

Understood. Perfect. Very helpful. Thanks a lot, guys.

All right, thanks, Jeff. 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.

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