Vitesse Energy, Inc. (VTS) Q3 2026 Earnings Report, Transcript and Summary

Greetings. Welcome to the Vitesse Energy Third Quarter 2026 Earnings Call. [Operator Instructions] Please note this conference is being recorded. I will now turn the conference over to the Vice President, Finance and Corporate Development at Vitesse, Ben Messier. Thank you. You may begin.

Good morning, everyone, and thanks for joining. Today, we will be discussing our third quarter 2026 results. Our earnings release was issued and our 10-Q was filed yesterday after market close. The updated investor presentation can be found on the Vitesse website. I'm joined this morning by our President and CEO, Jamie Benard; and our CFO, Jimmy Henderson. Before we begin, please be reminded that this call may contain estimates, projections and other forward-looking statements within the meaning of the federal securities laws. Forward-looking statements are subject to several risks and uncertainties, many of which are beyond our control. These risks and uncertainties can cause actual results to differ materially from our current expectations. Please review our earnings release and risk factors discussed in our filings with the SEC for additional information. In addition, today's discussion may reference non-GAAP financial measures. For reconciliation of historical non-GAAP financial measures to the most directly comparable GAAP measure, please reference our 10-Q and earnings release. Now I will turn the call over to Vitesse's President and CEO, Jamie Benard.

Thanks, Ben. Good morning, everyone, and thanks for joining today's call. First, we're pleased to report our Board declared a fourth quarter cash dividend of $0.4375 per share or $1.75 annualized. That marks the 16th consecutive quarterly dividend since the January 2023 spin-off without a single interruption. This is the direct output of a business model built around durability and discipline. The third quarter headline for Vitesse was the successful closing of the Denver-Julesburg Basin acquisition in September, which expands our position in the DJ alongside a strong operating partner and adds meaningful cash flow at an accretive valuation. It's a prime example of our strategy in action, a consistent, disciplined deployment of capital and the DJ Basin deal reflects the same underwriting rigor applied to every transaction before it. Our underwriting discipline remains tight. We underwrite every well and every acquisition at strip pricing or lower, and we only invest capital when the returns clear our thresholds. The result is a portfolio of 8,732 productive wells managed by a team of 33 full-time employees, approximately 265 productive wells per team member. That's a 64% increase since 2022 as the benefits of scale, deployment of artificial intelligence and continued improvement of internal processes pervade the organization. Turning to our development activity. As of September 30, we had 6.5 net wells in the drilling or completion phase and another 13.0 net permitted locations ready for development. During the third quarter, our operating partners began drilling 2.0 net wells and turned 2.0 net wells to production. That's a modest improvement from the 1.8 net wells spud and 1.7 net wells turned to production in the second quarter. We expect an acceleration of wells turned to production in the fourth quarter, which supports our revised production guidance and preliminary outlook for 2027. With Vitesse holding an interest in roughly half of the drilling rigs in the Williston in recent quarters and the Williston rig count increasing to 38 as of yesterday, we're well positioned to benefit as activity in the basin builds. The ongoing transition toward extended laterals across our acreage remains an important structural driver of capital efficiency. So far this year, 70% of the AFEs we've consented to are for wells 3 miles or longer. These extended laterals flatten our corporate baseline decline and reduce the maintenance capital required to hold production flat. That directly supports the dividend. Our operating partners are getting more efficient as well. In their October update, North Dakota regulators reported that well cycle times across the state are improving even as the average completed lateral length reached an all-time high of nearly 14,000 feet in the third quarter, roughly 20% above the 2025 average. That matters for a nonoperator. Faster cycle times shorten the time between when we fund our share of a well and when that well begins generating cash flow. I'll now turn it over to our CFO, Jimmy Henderson, to walk through the financial results.

All right. Thanks, Jamie, and thanks, everybody, for joining this morning. I just want to highlight a few key items from our third quarter financial results. As always, refer to our earnings release and our 10-Q, both of which were filed last night for any further details. So production for the third quarter averaged 16,824 BOE per day with a 60% oil cut. As Jamie noted, our DJ Basin acquisition closed mid-September, so this quarter includes very limited contribution from that asset. We expect a full quarter of DJ production beginning in the fourth quarter and anticipate some acceleration of wells turned to production in Q4, consistent with our guidance. Oil represented 92% of our oil and natural gas revenue in the quarter, which reflects the quality and oil weighting of our asset base. For the quarter, adjusted EBITDA was $39.3 million and adjusted net income was $2.5 million, while our GAAP net loss was $36.4 million. This GAAP net loss is entirely attributable to $46.6 million noncash unrealized loss on commodity derivative instruments. It had no impact on our operating cash flows or our free cash flow for the quarter. Of course, if prices remain above our hedged levels, these contracts will settle in cash over time, but the settlements are offset by higher prices we receive on the underlying barrels. Free cash flow for the quarter was $9.4 million after $26.9 million of development capital expenditures. Net of divestitures, total cash capital expenditures were $53 million for the quarter, which includes $25.9 million of the closing payment for the DJ Basin acquisition. Now on the balance sheet, we ended the quarter with total debt of $190.5 million, resulting in net debt to trailing 12-month adjusted EBITDA ratio of 1.3x. I want to address that directly because I know it's above our stated target of 1x. The increase in leverage is primarily the result of the DJ Basin acquisition, which again closed in September and was funded by the drawing on our revolver. But the ongoing cash flows from the asset have not yet had time to work through the EBITDA. More importantly, on a forward-looking basis, incorporating a full quarter of DJ Basin cash flows and acceleration of wells being turned to production in Q4, leverage is right at 1x target and declining at current strip prices. In October, we amended our revolving credit facility, expanding our elected commitments and borrowing base from $275 million to $290 million. That expansion brings our total liquidity to approximately $100 million. Again, our simple capital structure keeps the dividend protected and the balance sheet ready to act on opportunities. On hedging, based on the midpoint of our revised guidance, we had approximately 64% of the remaining 2026 oil production hedged and approximately 57% of the remaining 2026 natural gas production hedged. Our oil hedge book now extends into 2030, with swaps in place at a weighted average price of approximately $68 per barrel. That visibility supports our confidence in maintaining the quarterly dividend and managing leverage through the cycle. The remaining 36% of our 2026 oil production is unhedged and participates fully in the current price environment. Finally, we revised our 2026 annual guidance to reflect the DJ Basin acquisition and drilling completion activity for the remainder of the year. We narrowed the range and increased the midpoint of guidance for annual production to 16,600 to 17,200 BOE per day and drilling completion CapEx of $80 million to $90 million, reflecting the higher activity level anticipated in the fourth quarter in addition to another quarter of actual results. Oil as a percentage of annual production remains unchanged at 60% to 62%. I'd also note that the capital expenditure guidance of $80 million to $90 million reflects drilling and completion CapEx spending only and does not include acquisition capital, which we evaluate and fund separately on a deal-by-deal basis. With that, let me turn the call back over to the operator for Q&A. Thank you.

[Operator Instructions] Our first question is from Jeff Grampp with Northland Capital Markets.

Jamie, you mentioned an acceleration in wells turned to sales in Q4, and it sounds like maybe looking into a sneak peek in '27. Curious with respect to '27, I know it's early, but any kind of preliminary views on kind of production trajectory, capital spending trends or anything else you care to comment on?

Yes, sure. Like I said in my comments, it's preliminary, but the crystal ball is showing us and our modeling is showing us that with the inflated commodity prices, it's incentivized operators to put capital on the ground perhaps sooner rather than later. You saw the modest increase in drilling rigs. So I think the industry has stayed appropriately disciplined as we navigate the geopolitical situation overseas. And as far as you -- we're looking at a flat to modest increase in production for Vitesse next year.

Just to clarify, Jamie, is that relative to the guide to the annual guide to kind of pro forma production today? I just want to confirm the baseline there.

Yes, sir. Sorry for not clarifying that. That's exactly right.

Okay. And for my follow-up, on the longer lateral trends there, one benefit that you guys have highlighted is obviously the lower decline rates in addition to just the overall capital efficiency improvements. But have you guys looked at anything internally on like how much does the corporate decline rate benefit from that increased weighting to these longer laterals versus what the decline rate may have been a year or 2 ago or how that maybe impacts what maintenance CapEx requirements are for the business?

Jeff, it's Ben. Yes, we have looked at it. We have the benefit of extended laterals in our corporate model, and you would expect maintenance CapEx over time to decline 10% or so over the next 3 or 4 years based on the projections we currently have. Obviously, the impact of that is both from the benefit of the extended laterals, but also the aging of our overall production as we have made fewer near-term development acquisitions in the last year than we made in previous years where we spent close to $30 million on that. So I think all of that is showing up in our outlook, and you would expect maintenance CapEx to lower given the preliminary results we're seeing from 3- and 4-mile laterals and what our operating partners are saying publicly about the expected EUR per foot of those laterals.

Our next question is from Poe Fratt with Alliance Global Partners.

Just could you address the cost side? It looks like costs have gone up over the last 2 quarters or so. And I was just looking at third quarter LOE at like $12.40. Where should we look at that going over the next couple of quarters?

Yes. Poe, this is Jamie. I'll take that one. And good question. That's something we've been highly focused on. So in July and August of the third quarter on our operated asset, we had some mechanical failures that seem to come back to back to back. So the production, the BOE number dropped. And then what we went to, we went to a 24-hour workover rig crew, which is more costly to bring those barrels back on as soon as possible in the quarter. So the short answer to your question is, looking forward, I would anticipate the LOE, the dollars per BOE, to come back down to where they were previously. And that's ongoing throughout our non-op portfolio as wells that may have in a different commodity environment, been a lower priority to bring back on are obviously being expedited by our operators to get as many barrels into sales as possible.

Great. That's helpful. And on the G&A side?

Poe, are you there?

Yes. I was just wondering about G&A trends.

Okay. Poe, this is Jimmy. Yes, I think on G&A that I think all things considered are held constant. I think we'd probably see some decrease as we go from year-to-year next year. But as Jamie spoke early on, the ability to scale up this asset, this business with existing team adds a lot of leverage to the model, and that's our focus. And we'll continue to do acquisitions that we can assimilate quickly just like this DJ asset that we brought in with no additional headcount and very little from an integration standpoint. So that will continue to be an advantage for us going forward.

And then, Jimmy, do you have a ballpark number of how much the DJ acquisition added in the third quarter?

Very little. Yes. How much the acquisition itself added? Really nothing because we...

Yes, the production. You said it was on for a month, but I was just wondering.

How much production it added? Just a few hundred BOE per day.

Okay. And then you talked about sort of flat to slightly up for production in '27. CapEx, any sort of targets for CapEx at this point in time? I know it's always a work in progress, but...

Yes. Exactly, Poe. It's work in progress, but I would say it's going to be similar to what this year is turning out to be. Again, commodity prices, the strip holding true to what it is today.

And then if I may, just one sort of high level. One of the things about Lucero acquisition and then bringing Jamie on is the operated experience. And has the time line to start operating wells changed at all? Can you just sort of frame it out as far as when you might look at operating wells?

So we are currently operating 60 wells in the Williston Basin. So that's been going on since Lucero closed. What we are doing is we're taking a deep dive looking at our acreage position as it relates to just like the common theme is across the basin is where can we extend laterals. So we're looking at our acreage position, whether we can -- whether looking at offset operators, discussing with them collaboration, et cetera, on extended laterals. And really, we want to optimize just like we do. Our operated capital dollars are competing the same as our non-op capital dollars. It's overall returns. So -- but as the narrative has been consistently, it's another lever that we have. So we're taking a deep dive in. We've brought on some operated expertise, and we expect to be really having some clarity there on go-forward development here in the first quarter.

Yes. Sorry, that's what I meant, drilling on an operated basis.

[Operator Instructions] Our next question is from Noel Parks with Tuohy Brothers.

I was just wondering, do you -- with the rig count marching up a bit in the basin, is service capacity good, adequate in the event the rig count keeps rising from here, would you say?

Are you talking about a drilling perspective?

Yes, exactly.

Yes. So we've seen the uptick has been modest. But thus far, there hasn't been any shortage of drilling capacity. I think that there's some macroeconomic drivers, costs such as diesel and things like that, that are -- but as far as a shortage of capacity for the larger operators that can sign up a rig for a 1-year contract, 2-year contract, obviously, that's advantageous. The smaller operators are more playing the spot market, which doesn't mean a shortage. It just becomes -- you're more subject to their schedule than your own at times, if that makes sense.

Absolutely. The other thing, not exactly the same space as Vitesse, but we are seeing a royalty deal coming to market, a spin-off from an operator. And just wondering, in deals with kind of this very dynamic backdrop we've had on the commodity side, where are you seeing valuation trends going right now, sort of steady, creeping up, weakening?

Noel, this is Ben. I think valuations move with strip prices. That seems to be how most people are underwriting at least the first few years of production on acquisitions. And then I think it varies what people use as assumptions in years 3 and beyond. Oftentimes, people will hold it flat at a long-term 70 or 75. But obviously, the most important variable in value of any oil and gas asset is typically strip prices. So you're still seeing more value being put on PDP than undeveloped, really depending on the basin. I mean if you look at the Permian, you're probably going to get more undeveloped value there than you would in, say, the Powder River Basin, where there's a little more optionality down the road on the stacked pay. But in general, I would say that valuations move with strip prices. So EBITDA multiples remain constant, free cash flow yield remains constant, but dollars per net acre, dollar per location, dollar per BOE per day of production increase at a higher price deck. So it just depends on what metric you're viewing it as. We take rate of return as the most important metric. We try to do deals that are both accretive to our NAV per share and also accretive to our distributable cash flow so that it either supports the dividend or allows us to increase the coverage on the dividend. And so that's sort of the matrix that we look at acquisitions through. But we underwrite at strip because we can hedge it, and that's why we're currently hedged through 2030 as we closed that DJ Basin acquisition in September and hedged 85% of the PDP through 2030 on that deal.

Great. And just related with hedging, we've -- with the conflict in the Middle East having gone on now much of the year, we've only just recently started to see sort of the further out strip, say, sort of months 13 to 24, really strengthen, acknowledging the likelihood of long-term supply disruption effects on pricing. And I just wondered with that having happened, any shifts in -- anything you might do a little bit differently looking at hedging for that period?

Well, when evaluating hedging our base asset, we consider sort of the price at which our dividend is funded by distributable cash flow. So to the extent that 2028 and '29 become more attractive and look like it can -- like we can protect coverage of the dividend, we're more likely to hedge. And so with prices up, you've noticed we're hedged further out on the curve than we have been the rest of the time we're public. And a big reason for that is we reduced the dividend earlier this year. So the breakeven WTI price is a little bit lower, and we can now hedge above that level even out into 2028 and 2029. So we've added some hedges beyond the DJ Basin acquisition within the last 1.5 weeks in 2028 and 2029. So continue to look for us to be active there as prices remain constructive.

There are no further questions at this time. I would like to turn the floor back over to Jamie Benard for closing comments.

Thanks, everyone, and thanks for joining today. I want to leave you all with this message. Vitesse remains extremely committed to returning capital to stockholders through our durable, disciplined capital allocation, accretive growth and strong and conservative balance sheet. That will remain unchanged. If you have any additional questions, please don't hesitate to reach out to Ben Messier directly. We look forward to connecting with you all at the Southwest IDEAS Conference in Dallas on November 18 or on our next quarterly earnings call. Thanks, everyone.

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