Vitesse Energy Q1 2023 Earnings Call Transcript

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May 9, 2023

There are 8 speakers on the call.

Operator

Greetings, and 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.

Operator

Thank you. You may begin.

Speaker 1

Good morning and thank you for joining. Today, we will be discussing our financial and operating results for the Q1 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 Vitess' Chairman and CEO, Bob Garrity our President, Brian Cree and CFO, Dave Macosko. Our agenda for today's call is as follows.

Speaker 1

Bob will provide opening remarks on the quarter. After Bob, Dave will review our Q1 2023 financial results. After 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.

Speaker 1

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 Garrity.

Speaker 2

Thanks, Ben. And I want to thank Ben for his work in the quarter, Communicating with analysts and new investors and prospective investors. He's done a great job. He understands the model Ann represents Vitess very well. So thanks, Ben.

Speaker 2

So good morning, everybody, and thanks for participating. The Q1 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 1st quarterly dividend of $0.50 a share, Modestly increased our production and reduced debt. TES 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 2nd 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.

Speaker 2

The conversion of undeveloped inventory to producing wells It's key to our business model. Organic drilling coupled with near term development acquisitions in the Q1 We'll continue to support our cash flow profile. So I'm going to turn this over to Dave McCosko, Brian Cree, which Huv is our President and will normally have prepared remarks. He's actually in North Dakota This week and hopefully will join us in the Q and A, but he won't have formal remarks. So now to Dave McCosko and congrats to Dave and his accounting staff for A terrific reporting session in the K and in the queue.

Speaker 2

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

Speaker 3

Thanks, Bob, and good morning, everyone. I'll give a quick overview of our financial performance for the Q1 of 2023. We reported a GAAP net loss of $47,800,000 reflecting $77,400,000 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 $44,100,000 related to a change in corporate tax status as we move from an LLC to a C Corp. An acceleration of $26,800,000 of non cash equity based compensation expense and $6,500,000 of transaction costs that were included in our G and A expense.

Speaker 3

All spin related costs have now been run through our income statement. Adjusted net income for the quarter was $15,600,000 using our statutory income tax rate of 23.4%. Adjusted EBITDA was $40,100,000 an increase of 6% over the prior quarter. Our Q1 production was up 20% from the Q1 of 2022, totaling 11,524 BOE per day, With oil representing 67 percent of production and 87 percent of our total revenue. Total revenue, including the effects of our realized hedges, Was $59,000,000 compared to $52,000,000 for the Q1 of 2022, despite a 20% drop in WTI oil prices And a 42% drop in gas price.

Speaker 3

Lease operating expense in the Q1 increased 17% Compared to the Q1 of 2022 on a per BOE basis, as we saw many operators allocate more capital to workovers on existing wells. Cash G and A of $10,900,000 again included $6,500,000 of spin related costs. Capital spending for Q1 2023 was slightly above maintenance levels as we spent $22,700,000 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 $5,000,000 drawn on our credit facility, down $8,000,000 from $53,000,000 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 $265,000,000 to $245,000,000 Due to lower commodity prices, our elected commitments of $170,000,000 did not change.

Speaker 3

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 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 With that, I'll turn the call over to the operator for Q and A. Thank

Operator

you. At this time, we will be conducting a question and answer session. And our first question is from Steve Richardson with Evercore

Speaker 4

This is Chris Baker on for Steve. Good morning, guys. Hi, Chris. Bob, our first question is for you. Just hoping you could talk about the M and 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?

Speaker 2

Chris, we've been doing this for 10 years and there is 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 chopped around. We look at everything, Chris.

Speaker 2

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.

Speaker 4

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 Services cost side of the equation would be great. Thanks.

Speaker 2

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 Independence, 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.

Speaker 2

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 going private has been a good move. So we're happy about that, Chris.

Operator

Our next question is from Donovan Shafer with Northland Capital Markets. Please proceed with your question.

Speaker 5

Hey, guys. Thanks for taking the questions and congratulations on the boring quarter. Essentially, just Being in line with what you're saying doing 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.

Speaker 5

So that's good. I want to stay stick with this theme Just on kind of what the last questioner was asking about was like the step out here you mentioned Kraken and Continental Moving kind of outside the core, there were some other companies reported last week, talked about, yeah, 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 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?

Speaker 2

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.

Speaker 2

That came to be. So, it was deeper. Denser, we bought most of our inventory based on economics for 4 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.

Speaker 2

So They've backed off of that heavy number and relied on improvements in frac technology. So anywhere from 6 to 8 wells for DSU is now the standard and we're recovering 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 We'd become more economic. That has happened. Better.

Speaker 2

The EURs in the Bakken Almost on a daily 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 Percent, then that is highly economic. So technology develops slowly, But it continues to evolve. And every day, we see better wells than we saw before.

Speaker 2

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. Well, the drilling costs 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 have to differentiate between Tier 1 and Tier 2 Economics And Tier 4 or Tier 5 Economics.

Speaker 2

So we do this all the time. The field is Constantly changing and we think for the better. So, Donovan, sorry about the long answer, but that's really core to what we do.

Speaker 5

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 at a couple of percentage points, I think correct me if I'm wrong on this, I have to go back to my petroleum engineering days. But you're framing that probably in terms of like Okay, what's the total oil in place in this sort of cube?

Speaker 5

You kind of model out some cube of reservoir area. And a lot of times, you're only recovering something less than in a share play maybe 10% or potentially less. And so you're talking about going from picking numbers like a 10% going to a 12%, Yes, it'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 probably now a point or 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 do you have a sense of like Yes, 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 track designs and everything and Being able to go back and say, well, we were really only in zone for a third of the wellbore, a third of the lateral and the Other 2 thirds of the lateral weren't even landed properly.

Speaker 5

Can you give us a sense of What potentials 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?

Speaker 2

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 at our conference room right now That has identified all wells that we believe will be refracked.

Speaker 2

Ed, it is shocking how many wells are prospective to be refracked. And it's all over the basin. Remember, the field was developed maniacally to hold it by production From 2,008 to 2012, all of those wells are prospective to be refracked. From 2012 until they moved from gel to slickwater, all of those wells are perspective to be refracked. We've seen a threefold increase in the last 6 months in operators starting to refrac wells.

Speaker 2

We believe that that refrac technology It's really new. And there 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.

Speaker 2

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 refracing 5 wells in 1 DSU. We have not seen the results from that. I can't say if that's a good thing or a bad thing.

Speaker 2

But refracs will be a Wildly economic future in the Bakken.

Speaker 5

Okay. And then just one last question follow-up on that. Is it with the refracs, is your sense that it's kind of like a broad based Uniform potential in this what I mean by that is, you can imagine a case where sort of entire vintages or entire years, say Every well drilled from 2014 to 2017 or something was done at 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.

Speaker 5

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 can now put a gamma ray And so today you know, am I in zone or am I not in real time as you're drilling the lateral. And 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. So maybe you're not it's not wide in the 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, 1 in 6 of those dice rolls early on It's badly out of zone.

Speaker 5

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?

Speaker 2

Yes, it's a good question and there's no Perfect answer for that. Wells drilled between 2,008 2011 often were 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.

Speaker 2

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 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 frac technique. So again, When you refrac a well, you often increase production in these surrounding wells.

Speaker 2

So it's a different beast. It's very tight.

Speaker 5

Yes. And I can kind of feel like almost like unprecedented levels of data for going back into an area like this. So there's a lot of engineers, a lot of number crunching, a lot of 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.

Speaker 5

But, yes, congratulations on the quarter. And I will second what you said about Ben. He's been doing great.

Speaker 2

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

Operator

Thank you.

Speaker 6

I don't know if Brian is on, but good morning. I'd love to go back to The M and A market for just a second. And I'm kind of wondering whether you said Kind of the deal flows 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

Speaker 2

well. Yes. So, good questions. Questions we ponder every day. We would definitely go out of basin.

Speaker 2

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 perspective. 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.

Speaker 2

We think that's perspective. We do not see a lot of deal flow in the Eagle Ford. We do have a fair position in the 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 2 or 3 days of well proposals A day in the Permian.

Speaker 2

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 in 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 $100,000,000 to $500,000,000 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.

Speaker 2

Again, we're not looking for Scale, we're greedy as it comes to looking for something that would bolster the dividend.

Speaker 6

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?

Speaker 2

Yes, 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 a third. About 1 third.

Speaker 2

About 1 third of all the rigs And that's because we're like a Bakken ETF, 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.

Speaker 6

Okay, awesome. And I have one more. You just talked 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 over maybe over the course of the rest of the year?

Speaker 2

Yes, it's very lumpy, Lloyd. I would love to say that we're going to be able to replicate what we did in the Q1 each of the quarters, but we can't. 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.

Speaker 2

But I got to tell you, we are very excited about the CapEx that we had in the Q1. 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

Speaker 5

We need that CapEx.

Speaker 6

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

Speaker 2

Thank you, Lloyd.

Operator

Thank you. Our next question is from Jeff Grampp with Sunstein School Partners. Please proceed with your question.

Speaker 7

Hi, Bob and team. Thanks for the time. Hi, Jeff. Good morning. Still thoughtful question for you, Bob.

Speaker 7

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?

Speaker 7

Or would you guys periodically Use the balance sheet, if you saw some good opportunities come across your desk.

Speaker 2

Yes, 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 interest we buy are pretty high. We buy whatever we can.

Speaker 2

It's not limited by budget. It's limited by opportunity and economics. So, philosophically, we'd 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?

Speaker 2

I can be more philosophical if you want.

Speaker 7

No, that was perfect. I appreciate it. And 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?

Speaker 7

Is Q1 a bit of an aberration on the high side or any commentary there would be helpful?

Speaker 2

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

Speaker 3

Okay. Hey, Jeff. This is Dave McCosko. I think what we saw is A lot of work over activity in Q1. I think going forward, we'll see that level off.

Speaker 3

We'll be sitting right in that $8.50 to $9 per BOE

Speaker 2

A lot of that's depending on the seasons, right?

Speaker 3

There's seasonality in that first Obviously, as it gets warmer, things will get cheaper to operate.

Speaker 7

Understood. Perfect. Very helpful. Thanks for the time, guys.

Speaker 2

All right. Thanks, Jeff. Well, that's it for now. We really appreciate You guys listening in and please reach out to Ben if you've got any further questions and We are going to go back to being boring. So thanks everybody.

Speaker 2

Bye bye.

Operator

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

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