Vitesse Energy Q3 2026 Earnings Call Transcript

Vitesse Energy reported its third-quarter financial results on Tuesday. Below is the transcript of the company's third-quarter earnings conference call.

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Summary

Vitesse Energy announced a fourth-quarter dividend of 43.75 cents per share, extending its record of 16 consecutive quarterly payouts since its spin-off in 2023.

The company successfully completed the Denver-Julesburg Basin acquisition in September, adding cash flow and expanding its asset base.

Third-quarter average daily production was 16,824 barrels of oil equivalent, with oil comprising 60%, and the company expects a full quarter of DJ Basin production contribution in the fourth quarter.

Third-quarter adjusted EBITDA was $39.3 million, while the GAAP net loss was $36.4 million, driven by non-cash unrealized losses on derivative instruments.

Net debt-to-EBITDA ratio rose to 1.3 times due to the DJ Basin acquisition, but is expected to decline with the full-quarter contribution in the fourth quarter.

Vitesse has hedged approximately 64% of its 2026 oil production and extended hedging coverage through 2030.

Revised 2026 guidance calls for average daily production of 16,600 to 17,200 barrels of oil equivalent, with capital expenditures between $80 million and $90 million.

The company is achieving operational improvements through extended lateral lengths and accelerated well turn-in-lines, supporting its 2027 production outlook.

Management maintains a positive outlook on sustaining and potentially increasing the dividend while effectively managing leverage.

Full Transcript

Operator

Good day, and welcome to the Vitesse Energy Q3 2026 earnings conference call. All participants are currently in listen-only mode. Following the formal presentation, there will be a question-and-answer session. Please note, this conference is being recorded. I will now turn the conference over to Ben Messier, Vice President of Finance and Corporate Development at Vitesse. Thank you. You may begin.

Ben Messier

Good morning, everyone, and thank you for joining. Today we'll discuss our third quarter 2026 results. Our earnings release and 10-Q were issued after market close yesterday, and an updated investor presentation is available on the Vitesse website. Joining me today are Jamie Benard, President and Chief Executive Officer, and Jimmy Henderson, Chief Financial Officer. Before we begin, please note that this call may contain estimates, forecasts, and other forward-looking statements within the meaning of federal securities laws. Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. These risks and uncertainties could cause actual results to differ materially from current expectations. Please refer to the risk factors discussed in our earnings release and filings with the SEC for additional information.

Additionally, today's discussion may reference non-GAAP financial measures. For reconciliations of historical non-GAAP financial measures to the most directly comparable GAAP measures, please refer to our 10-Q and earnings release. I will now turn the call over to Vitesse's President and Chief Executive Officer, Jamie Benard.

Jamie B. Benard

Thanks Ben. Good morning, everyone, and thank you for joining today's call. First, we're pleased to report that the Board declared a fourth-quarter cash dividend of 43.75 cents per share, or $1.75 annualized. This marks the 16th consecutive quarterly dividend since our spin-off in January 2023, without interruption. This is a direct result of a business model built around durability and discipline. The headline for Vitesse in the third quarter was the successful completion of the Denver-Julesburg Basin acquisition in September, a transaction that expands our footprint in the DJ Basin alongside a strong operating partner and adds meaningful cash flow at an accretive valuation. This is a classic example of our strategy in action: consistent, disciplined capital allocation, and the DJ Basin transaction embodies the same underwriting rigor as every transaction we've done before it. Our underwriting discipline remains rigorous.

We underwrite every well and every acquisition at or below strip prices, and we only deploy capital when returns meet our thresholds. The result is a portfolio of 8,732 producing wells managed by 33 full-time employees, or roughly 265 producing wells per team member. That's up 64% since 2022, and the benefits of scale, AI deployment, and continuous improvement in internal processes are permeating the organization.

Turning to our development activity, as of September 30, we had 6.5 net wells in the drilling or completion phase and an additional 13.0 net permitted locations to develop. During the third quarter, our operating partners spud 2.0 net wells and turned 2.0 net wells to production. That's a modest improvement from 1.8 net wells spud and 1.7 net wells turned to production in the second quarter. We expect fourth-quarter turn-in-line activity to accelerate, which supports our revised production guidance and preliminary 2027 outlook.

Over recent quarters, Vitesse has held an interest in roughly half of the drilling rigs operating in the Williston Basin, and with the Williston rig count now up to 38 as of yesterday, we are well positioned as basin activity increases. The continued transition to extended lateral lengths across our acreage remains an important structural driver of capital efficiency. Year-to-date, 70% of the AFEs we have agreed to are for three-mile or longer laterals. These extended laterals flatten our corporate base decline rate and reduce the maintenance capital required to hold production flat. This directly supports the dividend. Our operating partners are also improving efficiency.

In their October update, North Dakota regulators reported that well cycle times are improving across the state, even as average completed lateral lengths reached a record 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 period between when we fund our share of a well and when that well begins generating cash flow. I'll now turn the call over to Chief Financial Officer Jimmy Henderson to cover the financial results.

James Henderson

Alright, thanks Jamie, and thanks everyone for joining this morning. I just want to highlight a few key items in the third-quarter financial results. As always, please refer to the earnings release and 10-Q we filed last night for additional detail. Third-quarter average daily production was 16,824 barrels of oil equivalent, with oil comprising 60%. As Jamie mentioned, our DJ Basin acquisition closed in mid-September, so the asset contributed very little during the quarter. We expect to realize a full quarter of DJ production beginning in the fourth quarter, and we expect fourth-quarter turn-in-line activity to accelerate. Consistent with our guidance, oil represented 92% of oil and gas revenue for the quarter, which reflects the quality and oil weighting of our asset base.

Adjusted EBITDA for the quarter was $39.3 million, and adjusted net income was $2.5 million, versus a GAAP net loss of $36.4 million. That GAAP net loss is entirely attributable to a $46.6 million non-cash unrealized loss on commodity derivative instruments. This had no impact on operating cash flow or free cash flow for the quarter. Of course, if prices remain above our hedge levels, these contracts will settle in cash over time, but those settlements are offset by the higher prices we receive on the underlying barrels.

Free cash flow for the quarter was $9.4 million, after development capital expenditures of $26.9 million. Total cash capital expenditures for the quarter were $53 million, which includes the $25.9 million closing payment for the DJ Basin acquisition, which is now reflected on the balance sheet. Total debt at quarter-end was $190.5 million, and net debt to last twelve months adjusted EBITDA was 1.3 times. I want to address this 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 likewise closed in September and was funded through draws on our revolving credit facility. But the ongoing cash flow from that asset has not yet had time to be reflected in EBITDA. More importantly, on a forward-looking basis, incorporating a full quarter of DJ Basin cash flow and the acceleration of fourth-quarter turn-in-lines, leverage sits right at our 1 times target and is declining at current strip prices.

In October, we amended our revolving credit agreement, expanding the elected commitment and borrowing base from $275 million to $290 million. This expansion brings our total liquidity to approximately $100 million. Again, our simple capital structure protects the dividend and keeps the balance sheet ready to seize opportunities. On the hedging front, based on the midpoint of our revised guidance, we have hedged approximately 64% of our remaining 2026 oil production and approximately 57% of our remaining natural gas production. Our oil hedge portfolio now extends through 2030, with swaps in place at a weighted average price of approximately $68 per barrel. That visibility underpins our confidence in sustaining the quarterly dividend and managing leverage through the cycle. The remaining 36% of 2026 oil production is unhedged and will participate fully in the current price environment.

Finally, we revised our full-year 2026 guidance to reflect the DJ Basin acquisition and drilling and completion activity for the remainder of the year. We narrowed our annual production guidance range and raised the midpoint to 16,600 to 17,200 barrels of oil equivalent per day, with drilling and completion capital expenditures of $80 million to $90 million, reflecting the higher expected activity levels in the fourth quarter, as well as another quarter of actual results. Oil as a percentage of annual production remains unchanged at 60% to 62%.

I would also note that the $80 million to $90 million capital expenditure guidance reflects drilling and completion capital only and excludes acquisition capital, which we evaluate and fund on a deal-by-deal basis. With that, let me turn the call back over to the operator for Q&A. Thank you.

Operator

Thank you. We will now begin the 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 your line is in the question queue. If you would like to remove your question from the queue, you may press star-two. Participants using speaker equipment may need to pick up the handset before pressing the star key. One moment please while we poll for questions.

Our first question comes from Jeff Gramp of Northland Capital Markets. Please go ahead.

Jeff Gramp

Good morning, everyone. Thanks for the time. Jamie, you mentioned accelerating turn-in-lines in the fourth quarter, and it sounds like maybe even a preliminary preview of 2027. On 2027, I know it's early, but is there any preliminary view on production trajectory, CapEx trends, or anything else?

Jamie B. Benard

Yeah, certainly. As I mentioned in my remarks, it's preliminary, but both the crystal ball and our models show that with higher commodity prices, it incentivizes operators to put capital in the ground earlier. You're seeing a modest increase in rig counts, so I think the industry is being appropriately disciplined in response to the geopolitical situation overseas. For our part, we expect Vitesse's production to be flat to modestly up next year.

Jeff Gramp

Jamie, just to confirm, is that relative to the annual guide, or relative to pro forma production today? Just want to confirm the base.

Jamie B. Benard

Yes, sir. Sorry, I wasn't clear. That's correct.

Jeff Gramp

Okay, thank you. Alright, and then a follow-up on the extended lateral trend. One benefit you've highlighted is obviously lower decline rates and overall capital efficiency improvement. But have you guys internally studied how much the corporate decline rate has benefited from this increased weighting of long laterals, versus where it was a year or two ago, or what that means for maintenance CapEx requirements for the business?

Ben Messier

Hi Jeff, it's Ben. Yeah, we have. We've incorporated the benefit of extended laterals into our corporate model, and based on our current forecast, you can expect maintenance capital to decline roughly 10% over the next three to four years. Obviously, that impact comes both from the benefit of extended laterals and from the aging of our overall production base, given that we've done fewer recent development acquisitions over the past year than we did in prior years, when we spent nearly $30 million in that area.

So I think all of that is reflected in our outlook, and given the early results we're seeing from three-mile and four-mile laterals, and what our operating partners have publicly stated regarding EUR per foot on those laterals, you can expect maintenance capital to be lower.

Jeff Gramp

Got it. Ben, great detail. Thanks for the time. Thanks everyone.

Ben Messier

Thanks Jeff.

Operator

Our next question comes from Poe Fratt of Alliance Global Partners. Please go ahead.

Poe Fratt

Hey, good morning. Can you talk about the cost side? It looks like costs have ticked up over the last couple of quarters or so, and I noticed LOE was around $12.40 in the third quarter. How should we think about that number over the next few quarters?

Jamie B. Benard

Yeah, Poe, it's Jamie. I'll take that. Good question. This is something we're highly focused on. During July and August of the third quarter, we had a couple of back-to-back mechanical failures on our operated assets. So production — the barrels of oil equivalent number — declined, and then we brought in 24-hour workover rigs, which are more expensive, to restore that production as quickly as possible within the quarter. So the short answer to your question is, going forward, I would expect LOE — the dollars per barrel of oil equivalent — to trend back down to prior levels.

And within our non-operated asset portfolio, wells that might have been lower priority in a different commodity environment in the past are now clearly being accelerated by our operators to get as many barrels to sales as possible.

Poe Fratt

Okay, that's helpful. On the G&A side —

Jamie B. Benard

Poe, are you still there?

Poe Fratt

Yes, I was just trying to get a sense of G&A trends.

James Henderson

Okay. Hey Poe, it's Jimmy. On G&A, I think all else equal, it could be down year-over-year next year. But, as Jamie mentioned earlier, the ability to scale this asset, this business, with the existing team adds a lot of leverage to the model, and that's our focus. We'll continue to do acquisitions that we can integrate quickly, like this DJ asset, where we added no headcount and very little work on the integration side.

So that will continue to be an advantage for us going forward.

Poe Fratt

So, Jimmy, do you have a rough number for how much the DJ acquisition added in the third quarter?

James Henderson

Oh, very little. Yeah. How much did the acquisition itself add? Actually, virtually nothing. Yeah.

Poe Fratt

On the production side, you said it came online for a month, but I was just wondering.

James Henderson

Oh, how much production did it add? Just a few hundred barrels of oil equivalent.

Poe Fratt

Okay. And then you talked about 2027 production being flat to modestly up. CapEx — is there any CapEx target out there right now? I know it's always a work in progress, but —

Jamie B. Benard

Yeah, Paul, it is indeed a work in progress. But I would say it will be similar to this year, again, assuming commodity prices, strip prices, stay where they are today.

Poe Fratt

And one more, a bit of a bigger-picture question, if I can. One aspect that came with the Lucero acquisition and Jamie's addition was operating experience, so has the timeline changed at all for operating wells? Can you give a rough sense of when you might consider operating wells?

Jamie B. Benard

We currently operate 60 wells in the Williston Basin. That's been ongoing since the Lucero transaction closed. What we're doing is taking a deep dive into our acreage positions — like the common theme across the basin — on where we can extend laterals. So we're looking at our acreage positions, seeing if we can — looking at offset operators, having discussions with them about cooperation, etc. — on extending laterals. Really, we want to optimize, as we do, our operated capital competing with our non-operated capital, with the core being overall returns.

So. But as has been the consistent narrative, this is another lever for us. So we're digging in, we've brought in some operating expertise, and we expect to have clarity on future development by the first quarter.

Poe Fratt

Yeah, sorry, that's what I meant — drilling wells on an operated basis. Great, thanks very much.

Operator

As a reminder, if you would like to ask a question, please press star-one on your telephone keypad. Our next question comes from Noel Parks of Tuohy Brothers. Please go ahead.

Noel Parks

Hi, good morning. I was just wondering, with the basin rig count ticking up a bit, if rig counts continue to rise from here, is service capacity adequate?

Jamie B. Benard

Are you speaking from a drilling perspective?

Noel Parks

Yes, exactly.

Jamie B. Benard

Yeah. We've seen a modest increase, but so far there's been no shortage of drilling capacity. I think there are some macro cost drivers — things like diesel — but as far as the larger operators being able to contract rigs for one- or two-year terms, that's clearly advantageous. The smaller operators are operating more in the spot market, which doesn't mean there's a shortage, it just means sometimes you're more subject to their schedule than your own, if that makes sense.

Noel Parks

Absolutely. And one other thing, not exactly in Vitesse's space, but we saw a mineral rights deal come to market, spun out of an operator. I was just wondering, in this very dynamic commodity environment, what valuation trends are you seeing right now — are they stable, drifting up, or weakening?

Ben Messier

Hi Noel, it's Ben. I think valuations move with strip prices. That seems to be how most people underwrite the first few years of production on an acquisition. And then I think people's assumptions vary for year three and beyond. People typically hold it at a long-term level of $70 or $75. But obviously, the most important variable in the value of any oil and gas asset is usually strip prices. So you still see PDP values higher than PUD values, and it really depends on the basin. For example, if you look at the Permian, PUD value there is probably higher than in the Powder River Basin, which has more forward optionality in terms of stacked pay. But generally speaking, I think valuations move with strip. So EBITDA multiples stay the same, free cash flow yields stay the same, but the dollars per net acre, the dollars per well location, the dollars per barrel of oil equivalent per day increase with higher price tags.

So it depends on which metric you're looking at. We view returns as the most important metric. We try to do deals that are both accretive to NAV per share and accretive to distributable cash flow, so that it either supports the dividend or allows us to raise dividend coverage. That's the matrix we evaluate acquisitions on. But we underwrite at strip because we can hedge, and that's why we're hedged out to 2030 currently, because we closed the DJ Basin acquisition in September and hedged 85% of the PDP from that transaction out to 2030.

Noel Parks

Great. On the hedging side, the Middle East conflict has persisted for most of the year, and it's only recently that we've started to see further-dated strip — like months 13 to 24 — really firm up, which acknowledges the possibility of longer-term supply disruption impacting pricing. I was just wondering, given that's happened, are you doing anything differently in hedging that period?

Ben Messier

Well, when evaluating hedges on the underlying assets, we consider the price level at which the dividend is covered by distributable cash flow. So if 2028 and 2029 become more attractive and look like they can protect dividend coverage, we're more likely to hedge there. So as prices have moved up, you may have noticed we've hedged further out on the curve than at any time since going public. A big reason is that we lowered the dividend earlier this year, so the WTI breakeven is a bit lower, and we can now hedge above that level, even extending into 2028 and 2029.

So we've added some hedges in 2028 and 2029 over the past week and a half, beyond the DJ Basin acquisition. So stay tuned, and as long as prices remain constructive, we'll remain active there.

Noel Parks

Great. Thanks very much.

Operator

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

Jamie B. Benard

Thank you, everyone, for joining today's call. I want to leave you with this. Vitesse remains extremely committed to returning capital to shareholders through our durable, disciplined capital allocation, accretive growth, and a strong and conservative balance sheet. That will not change. If you have any additional questions, please feel free to reach out directly to Ben Messier. We look forward to seeing everyone at the Southwest IDEAS Conference in Dallas on November 18th, or on our next quarterly earnings call. Thank you.

Operator

This concludes today's conference call. You may now disconnect. Thank you for participating.

Disclaimer: This transcript is for reference purposes only. While we strive for accuracy, automated transcription may contain errors or omissions. For official company statements and financial information, please refer to the company's SEC filings and official press releases. Statements by company participants and analysts reflect their views as of the date of this call and are subject to change without notice.