VTS Q3 2026 earnings call transcript, November 3, 2026

Welcome to the Vitesse Energy third quarter 2026 earnings call. At this time, all participants are in listen-only mode.

A question and answer session will follow the formal presentation. 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. Our quarter 2026 results. Our earnings release was issued and our 10Q was filed yesterday after market closed. Updated investor presentation can be found on the Vitesse website. I'm joined this morning by our President and CEO, Jamie Bernard, 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 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 VTS's President and CEO, Jamie Bernard. 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 43.75 cents per share or $1.75 annualized. That marks the 16th consecutive quarterly dividend since the January 2023 spinoff 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 Joulesburg Basin acquisition in September, which expands our position in the DJ alongside a strong operating partner and adds meaningful cash flow and an accretive valuation. It's a prime example of our strategy in oxygen, 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 continual improvement of internal processes pervade the organization. Turning to our development activity. As of September 30th, 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 FITES 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 three 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 non-operator. 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. Thanks for- Thank you, everybody, for joining this morning. I just want to highlight a few key items from our third quarter financial results, as always referred to our earnings release and our 10Q, 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 a quarter, which reflects the quality and oil weighting of our asset base. Over 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 non-cash, 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 hedge 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 1.3 times. I want to address that directly because I know it's above our stated target of 1 times. 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 the acceleration... of wells being turned to production in Q4, leverages right at one times target and declining at current strip prices. In October, we amended our revolving credit facility, expanding our elected commitments in 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. 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 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 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. Back over to the operator for Q&A. Thank you.

Thank you. We will now be conducting a question and answer session. If you'd like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star 2 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.

Hi, 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, you know, 10% or so over the next three or four 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 three and four milaterals and what our operating partners are saying publicly about the expected EUR. Per foot of those laterals. Got it. Great details, man. I appreciate the time. Thank you, guys.

Yeah, thanks, Jeff.

Our next question is from OFRAT with Alliance Global Partners. Please proceed with your question.

Yeah, exactly, POE. It's a 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 are the strip holding true to what it is today. And then if I may, just one sort of high level, you know, one of the things about Lucero acquisition and then bringing Jamie on is that, you know, operated experience. And, you know, has the timeline to start operating wells changed at all? Can you just sort of frame it out? As far as when you might, you know, 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, collaborating. Et cetera, on extended laterals. And really, we want to optimize just like we do. You know, 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, you know, really having some clarity there on go forward development. here in the first quarter.

Yeah, sorry, that's what I meant, drilling, you know, an operated basis. Great. Thank you so much. Yes, sir.

Once again, if you'd like to ask a question, please press star 1 on your telephone keypad.

Uh, hedge 85% of the PDP through 2030 on that deal. Great. And just, um, related with hedging, uh, we've, you know, 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 outstrip, say sort of months, 13 to 24, really strengthen, acknowledging the likelihood of, of long-term supply disruption effects on pricing. And, uh, just wondered was, was that, um, having happened any, any shifts in, um, or anything you might do a little bit differently, uh, looking at hedging for, for that period? Well, you know, when evaluating hedging, our base asset, we consider, um, sort of the, the price at which our dividend is funded by distributable cashflow, um, sort of the extent that 2028 and 29 become more attractive and look like it. Like we can protect coverage of the dividend, uh, we're more likely to hedge. And so with prices up, you know, like 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, you know, we reduced the dividend earlier this year. So the, you know, 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, uh, within the last. Week and a half, um, in 2028 and 2029. So, um, continue to look for us to be, you know, active there as, as prices remain constructive. Great. Thanks a lot. There are no further questions at this time. I would like to turn the floor back over to Jamie Bernard for closing comments. Thanks everyone. And thanks for joining today. Um, I want to leave.

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