Greetings, welcome to the 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, 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 market close. You can access our earnings release and presentation on our investor relations website, and our Form 10-Q was 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. I wanna thank Ben for his work in the quarter, communicating with analysts and in new investors and prospective investors. He's done a great job. He understands the model and represents Vitesse very well. Thanks, Ben. 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, modestly 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. I'm gonna turn this over to Dave Macosko. Brian Cree, who is our president and will normally have prepared remarks, is actually in North Dakota this week and hopefully will join us in the Q&A, but he won't have formal remarks. Now to Dave Macosko, and congrats to Dave and his accounting staff for a terrific reporting session in the K and in the Q. Dave, with that pat on the back, go for it, buddy. Thanks, Bob. 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 one-time or non-recurring in nature associated with the spin-off. These charges include, again, a one-time non-cash income tax expense of $44.1 million related to a change in corporate tax status as we moved 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 70% 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 six and a half 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 - $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 operation standpoint, we had 7.2 net wells that were either drilling or in the completing 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. I'll turn the call over to the operator for Q&A. Thanks, Dave. Thank you. At this time, we'll be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we pull for questions. Thank you. Our first question is from Steve Richardson with Evercore ISI. Please proceed with your question. Yeah. Hi, this is Chris Baker on for Steve. Good morning, guys. Hi, Chris. Good morning. Bob, our first question is for you. I'm 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. you know, Chris Baker, we've been doing this for 10 years. There's a certain rhythm to the deal flow. I can't say that it's more or less than it has been over the last two years. We have a vibrant flow of near-term drilling, especially in the Bakken. I can't say it's substantially higher than it has been in the past. There are some bigger deals being chopped around. We look at everything, Chris Baker. Again, 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. That's great. Thanks. You know, 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. Yeah. 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, we're actually seeing lower average drilling completion costs now than we did a year ago. 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 formerly call the core, but their economics are very attractive. One other quick thing is Continental is the most active operator up there, they have stepped out of where they have traditionally drilled and have gotten very good results. We think Continental going private's been a good move. We're happy about that, 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. Hey, guys. Thanks for taking the questions. You know, congratulations on the boring quarter essentially, just, you know, being in line with what, you know, saying, doing what you say you're gonna do and just kinda being in line with that and consistent on all that. That's great. I mean, I know that's kinda your intention, so that's good. I want to stay, stick with this theme, just, you know, on kind of with the last question I was asking about was like the step-outs here, you mentioned Kraken and Continental moving, kinda outside the core. There were some other companies, reported last week, you know, talked about, yeah, Tier 2 wells performing more like Tier 1 wells. I'd like to see if we can just get an update on You've got the deeper, I'm gonna get the words wrong, but I think you call it like deeper, denser, wider, like the deeper, denser, wider thesis that, you know, you guys in a prior company you succeeded on in the DJ Basin and now you're trying to do that in the Williston. Can you kinda isolate each one? Because, you know, it seems like deeper maybe isn't quite as relevant in this kind of basin, but, you know, 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 in what you're seeing in terms of like well productivity and what's driving it? Yeah, great question, Donovan. 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. 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. They backed off of that heavy number and relied on improvements in frack technology. 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, you know, 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 basis, get better. You gotta remember, the Bakken is such an incredibly tight rock. If you can increase your recoveries by just 2% or 3%, then that is highly economic. Technology develops slowly, but it continues to evolve. Every day, we see better wells than we saw before. We're very encouraged that over the course of time, frack technology will continue to improve recoveries. We look 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, well, the drilling costs in that area by that operator is lower than some of the stuff in Tier 2 or Tier 1 locations, and therefore, that economics are actually better. You have to differentiate between Tier 1 Tier 2 economics and Tier 4 or Tier 5 economics. We do this all the time. The field is constantly changing, and we think for the better. Donovan, I'm sorry about the long answer, but that's really core to what we do. Okay. No, that's great. Then, kind of, following up on that, I wanna talk about refracs a little bit because I think, you know, you can argue that that would tie into the same kind of thesis, and you talked about recovery rates. When you talk about, you know, the huge improvement in economics from just improving that a couple percentage points, I think, you know, correct me if I'm wrong on this, I have to go back to my petroleum engineering days. You know, you're framing that probably in terms of like figuring out, okay, what's the total oil in place in this sort of cube? Yes. You know. Yes. model out some cube of a reservoir area. A lot of times, you know, you're only recovering something less than, you know, in a shale play, maybe 10% or potentially less. You're talking about, you know, going from, just picking numbers, like a 10% going to a 12%. That's more of like a, even though it's 2% on those terms, it's a 20%, you know, increase in the volume. When you look at the old wells, you know, the Bakken's an old basin now, kind of at this point, certainly compared to, you know, the shale type development in places like the Permian. It's, you know, probably now a point or it's gonna 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. Do you have a sense of like, you know, some of the early wells being able to go back and say, "Gosh, you know, we think this was really only a 6% recovery, and given all the changes that we've done, you know, with technology and frac designs and everything," and being able to go back and say, "Well, we were really only, you know, in zone for a 1/3 of the wellbore, you know, 1/3 of the lateral and the other 2/3 of the lateral weren't even, you know, landed properly." You know, can you give us a sense of what potentials you're seeing there? 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, you know, the implied amount you could come back and recover with refracs. Right on. Donovan, I don't think anybody, in fact, I'm sure no one really knows the initial recovery rate. You know, in our shop, we do ascribe to that, 9%-10% in initial recovery percentage. 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 refract. It is shocking how many wells are prospective to be refract, 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 prospective to be refract. From 2012 until they moved from gel to slickwater, all of those wells are prospective to be refract. We've seen a threefold increase in the last six months in operators starting to refract wells. We believe that refract technology is really new. We're not sure if the refract technology is going to improve faster than standard fracturing technology, but the cost will certainly come down. The last thing I'll say about refracs is, look, the economics of a refract are extraordinary. They're the best economics we have out in the field. One of the negatives for an operator to refract is that you really need to shut in the rest of the DSU, so your production in that DSU will initially go down. 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, refracs will be a wildly economic future in the Bakken. Okay. just one last question to follow up on that. With the refracs, is your sense that it's kind of a, like, a broad-based, uniform potential in this? what I mean by that is. Yeah. You can imagine a case where sort of entire vintages or entire years, you know, say every Yes. Every well drilled from, you know, 2014 to 2017 or something was done at this way, at this scale, and so that entire, you know, that whole bundle of DSUs or whatever, that'd be one perspective. Another perspective would be, well, you know, you didn't have as good well control early on. I don't think as many companies were doing, like, the gamma ray. You know, you can now put a gamma ray. Yep. Detector on the back of the bit. You know, today, you know, am I in zone or am I not, in real time as you're drilling the lateral? You know, that 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 actually go back and actually come up with those conclusions after the fact now. Maybe you're not it's not widely uniform. It's maybe, you know, kind of rolling the dice each time, and it's more like you could go back and look and say, "Oh, you know, one in six of those dice rolls early on is badly out of zone. Maybe we'd even re-drill it, 'cause we just don't even think this thing, this lateral is even there or even really," you know. That type of thing versus this much broader, just uniform everywhere. Is it more one, more the other? Maybe a mix of both, it's more the latter case where refracs will start first before migrating to more uniform? It's a good question. There's no perfect answer for that. Wells drilled between 2008 and 2011 often were out of zone. You're absolutely right about that. Whether or not you can go in and refract 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 gotta remember that the Bakken is such a closed unit that in the Bakken, we have a halo effect. When you refrac or frack a well in a DSU, the parent wells actually have their production increased. Again, it is a different basin. I think that, you know, where you refrac, 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 frack technique. Again, you know, when you refrac a well, you often increase production in the surrounding wells. It's a different beast. It's very tight. Yeah. You know, I can kind of feel like almost like unprecedented levels of data for going back into an area like this. There's a lot of engineers, a lot of number crunching. Just a lot of fascinating analysis stuff that goes into it. Okay, well I'm going to leave it at that. I'll take the rest of my questions offline or follow up with you guys. Yeah. Great. Congratulations on the quarter. I will second what you said about Ben. He's been doing great. Thanks. I'll reaffirm what you said is we try very hard to be boring, thanks for that comment. Thanks, Donovan. Thank you. Our next question is from Lloyd Byrne with Jefferies. Please proceed with your question. Hey, good morning, Bob. I don't know if Brian's on, but good morning. I'd love to go back to the M&A market for just a second, I'm kinda 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. Maybe on the back of that, whether you'd ever go out of basin going forward as well. Yeah. 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 mudrocks, 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, have done extremely well there, but we don't think that that is something that's we're able to get much scale with. We look at two or three days of well, well proposals a day in the Permian. It can't really compete to what we're seeing in the Bakken. Wide open for the Permian. We have some organizational experience in the Permian, but it right now the bread and butter in the Bakken is still the best we see. 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 priced 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. That makes sense. I just also wanna go back to the 42% of rigs operating on the acreage. I know it was mentioned earlier, can you just tell me whether that's higher or lower than in the past? That seems like an awful high run rate for the inventory. 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. 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 a third. About one third. About one third of all the rigs running in the Bakken are on our acreage. You know, that's because we're like a Bakken ETF, right? We have acreage all over everywhere. So, yeah, I think that's a, you know. Your conclusion that the rigs are spreading out, pretty good. Yeah, we would agree with that. Okay, awesome. 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, how do you see that for over maybe over the course of the rest of the year? Yeah. It's very lumpy, Lloyd. I would love to say that we're gonna be able to replicate what we did in the first quarter each of the quarters, but we can't. You know, we're not in control of that. That is a negative being a non-op. You know, if we have similar CapEx in Q2, maybe we will, you know, change our guidance, but at this point it's too premature. I gotta tell you, we are very excited about the CapEx that we had in the first quarter. Again, more CapEx is a very good sign for us 'cause we're very disciplined in what we drill. Remember the lag between CapEx and production is roughly a year, less than that on refracs. you know, we hold that CapEx. That's great. I appreciate all the commentary on the Bakken productivity. It's interesting. 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. Hi, Bob and team. Thanks for the time. Hi, Jeff. Kind of a Morning. Full thoughtful 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, you know, use the balance sheet if you saw some good opportunities come across your desk? Yeah, we would use the balance sheet, Jeff, no doubt about it. Again, you know, we're specialists, especially in the Bakken. Our hurdle rates for the wellbore interests we buy are pretty high. You know, we buy whatever we can. It's not limited by budget, it's limited by opportunity and economics. Philosophically, we'd you know, 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. No, that was perfect. Okay. I appreciate it. Just a smaller housekeeping 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 gonna ask Dave to answer that one. Okay. Hey, Jeff, this is Dave Macosko. I think what we saw is, you know, 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-$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. Yeah. Understood. Perfect. Very helpful. Thanks for the time, guys. All right. Thanks, Jeff. Well, that's it for now. We really appreciate you guys listening in. Please reach out to Ben if you've got any further questions. We're gonna go back to being boring. Thanks, everybody. Bye-bye. Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.