Vitesse Energy (VTS) 2026年第三季財報電話會議：DJ 盆地交易與調升財測指引

Vitesse Energy (NYSE: VTS) 公布 2026 年第三季每日產量為 16,824 桶油當量 (BOE)，調整後 EBITDA 為 3,930 萬美元。9 月完成的 DJ 盆地收購案對本季貢獻有限，但預計將在第四季提供完整的單季產量與現金流。

重點摘要

• 第三季平均每日產量為 16,824 BOE，其中原油占總產量的 60%。
• 調整後 EBITDA 為 3,930 萬美元，調整後淨利為 250 萬美元，自由現金流為 940 萬美元。
• GAAP 淨虧損 3,640 萬美元，完全歸因於商品衍生性商品 4,660 萬美元的非現金未實現虧損。
• 董事會宣布發放每股 0.4375 美元的季度現金股利，折合年化股利為 1.75 美元。這是 Vitesse Energy 自 2023 年 1 月分拆上市以來，連續第 16 個季度發放股利。
• 管理層將 2026 年全年產量指引修訂為每日 16,600 至 17,200 BOE，鑽井與完井資本支出指引修訂為 8,000 萬至 9,000 萬美元。
• 季末總債務為 1.905 億美元，相當於過去 12 個月調整後 EBITDA 的 1.3 倍。管理層表示，在納入 DJ 盆地現金流及預期的第四季新增產量後，前瞻槓桿率約為 1 倍。

關鍵財務數據

業務與營運表現

Vitesse 於 9 月中旬完成 DJ 盆地收購案。因此，該交易對第三季產量和財務業績的貢獻有限。管理層預計自第四季起將呈現 DJ 盆地整季的產量貢獻。

截至季末，該公司擁有 8,732 口生產井的權益，由 33 名全職員工支援。這相當於每位員工負責約 265 口生產井，自 2022 年以來成長了 64%。管理層將此改善歸因於規模效益、人工智慧及內部流程升級。

截至 9 月 30 日，Vitesse 擁有 6.5 口正在鑽井或完井的淨井，以及另外 13.0 個已獲許可的淨井位置。營運夥伴在第三季開鑽了 2.0 口淨井，並有 2.0 口淨井投入生產；相比之下，第二季開鑽 1.8 口淨井，1.7 口淨井投入生產。

延伸水平井段（Extended laterals）仍是資本效率的核心驅動力。2026 年批准的資本支出授權（AFE）中，約有 70% 涉及水平井段達 3 英哩或更長的油井。管理層表示，這些油井應能平緩公司的基礎產量遞減率，並減少維持生產所需的資金。

Vitesse 還在威利斯頓盆地（Williston Basin）營運 60 口油井。公司正評估其租地面積，並探討與鄰近營運商合作的可能，以尋找更長水平井段的機會。管理層預計在第一季對未來的自營開發項目有更明確的方向。

管理層指引

Vitesse 將 2026 年全年產量指引修訂為每日 16,600 至 17,200 BOE，原油預計將保持在總產量的 60% 至 62%。管理層預計第四季投入生產的油井進度將加速。

鑽井與完井資本支出指引設定為 8,000 萬至 9,000 萬美元。此範圍不包含收購資金，後者由公司單獨評估與籌措。

展望 2027 年，管理層的初步預測為相較於 2026 年年度指引呈持平至溫和成長。若當前期貨價格保持不變，資本支出預計將與 2026 年水準相當。

管理層亦表示，根據目前對延伸水平井段的預測及現有生產基底的老化趨勢，未來三到四年維持性資本支出可能會下降約 10%。

風險與關注焦點

• 在透過循環信貸額度為 DJ 盆地收購案進行融資後，槓桿率上升至過去 12 個月調整後 EBITDA 的 1.3 倍。管理層預計隨著收購資產的現金流反映在業績中，該比率將朝 1 倍的目標靠攏。
• 在 7 月和 8 月自營資產發生機械故障後，租賃營運費用（LOE）有所增加。Vitesse 採用了成本較高的 24 小時修井團隊來恢復生產。管理層預計每 BOE 成本將回落至先前水準。
• 若商品價格持續高於避險水準，衍生性商品合約隨著時間推移將需要現金結算，不過管理層指出，這些支付將可被標的資產實體產量較高的實現價格所抵銷。
• 初步的 2027 年產量與資本展望取決於當前的期貨價格和營運商的活動狀況。

分析師問答亮點

管理層表示，較長的水平井段應能在三到四年內支援維持性資本支出減少約 10%。更快的鑽井與完井週期也縮短了 Vitesse 支付油井分攤款項至獲得生產現金流之間的時間。

在成本方面，管理層將第三季租賃營運費用的增加歸因於暫時性因素，與機械故障及加速修井作業有關。公司亦預計一般與行政費用（G&A）將同比有所下降，同時強調收購案可在僅增加極少員額的情況下完成整合。

Vitesse 指出，儘管活動略有增加，但並未出現鑽井產能嚴重短缺的情況。大型營運商受惠於長期鑽機合約，而小型營運商在現貨市場上可能面臨較大的排程風險。

管理層表示，收購估值通常隨期貨價格波動。Vitesse 在評估交易時，會優先考量報酬率、每股淨資產價值（NAV）增值以及可分配現金流增值。

根據修訂後指引的中位數，2026 年剩餘原油產量的約 64% 及天然氣剩餘產量的 57% 已進行避險。原油避險投資組合延伸至 2030 年，加權平均價格約為每桶 68 美元。Vitesse 還對 DJ 盆地收購案至 2030 年止 85% 的已開發生產中證實儲量（PDP）進行了避險，並於近期新增了 2028 年和 2029 年的避險部位。

完整法說會逐字稿

完整財報電話會議逐字稿

管理層陳述

Operator

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 of Finance and Corporate Development at Vitesse, Ben Messier. Thank you. You may begin.

Ben Messier

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. 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, Jamie 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 to non-GAAP financial measures. For a 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.

Jamie Benard

Thanks, Ben. Good morning, everyone, and thanks for joining today's call. First, we're pleased to report that 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 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 Julesburg Basin acquisition in September, which expands our position in the DJ alongside a strong operating partner and adds meaningful cash flow and an [indiscernible] revaluation.

It's a prime example of our strategy in action, a consistent, disciplined deployment of capital in 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 are lower, and we only invest capital when the return is clear 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 pervaded 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 wells 3 miles or longer. These extended laterals flatten our corporate baseline decline, and reduce the maintenance 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.

James Henderson

All right. Thanks, Jamie, and thanks, everybody, for joining us 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 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 [ 2% ] 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 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 1.3x. 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 listing basis, incorporating a full quarter of DJ Basin cash flows and the 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 commitment 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 hedge 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 participate 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 find 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

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

分析師問答

Jeffrey Grampp

Jamie, you mentioned an acceleration in wells turned to sales in Q4, and it sounds like maybe we're looking into a sneak peak 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?

Jamie Benard

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 is stayed appropriately disciplined as we navigate the geopolitical situation overseas. And as far as we're looking at a flat to modest increase in production for Vitesse next year.

Jeffrey Grampp

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

Jamie Benard

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

Jeffrey Grampp

Okay. And for my follow-up, on the longer lateral trends there, 1 benefit that you guys have highlighted is obviously the lower decline rate 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 long 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?

Ben Messier

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 [indiscernible] 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 year, 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.

Operator

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

Charles Fratt

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 it going over the next couple of quarters?

Jamie Benard

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 there's ongoing throughout our non-op portfolio as wells that may have in a different commodity environment than a lower priority to bring back on are obviously being expedited by our operators to get as many barrels into sales as possible.

Charles Fratt

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

Jamie Benard

Poe, are you there?

Charles Fratt

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

James Henderson

Okay. Poe, this is Jamie. 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 is 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 were brought in with no additional head count and very little from an integration standpoint. So that will continue to be an advantage for us going forward.

Charles Fratt

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

James Henderson

Very little. Yes. How much the acquisition Delta, really, nothing because we...

Charles Fratt

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

James Henderson

How much production it added, just [indiscernible].

Charles Fratt

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.

Jamie Benard

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 strip holding true to what it is today.

Charles Fratt

And then if I may, just 1 sort of high level. One of the things about Lucero acquisition and then bringing Jamie on is 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?

Jamie Benard

So we are currently operating 60 wells in the Williston Basin. So that's been going on since Lucero close. 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 operating 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.

Charles Fratt

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

Operator

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

Noel Parks

I was wondering, do you -- with the rig count matching up a bit in the basin. Is service capacity good adequate in the event account -- rig count keeps rising from here?

James Henderson

Are you talking about a drilling perspective?

Noel Parks

Yes, exactly.

James Henderson

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.

Noel Parks

Absolutely. And to understand, not exactly the same space as the test, but we are seeing a royalty deal coming to market 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 you see valuation trends going right now, sort of steady creeping up, weakening?

Ben Messier

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, we'll 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, you look at the Permian, they'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 the strip prices. So EBITDA multiples remain constant, free cash flow yield remain 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 is 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 it strip because we can hedge it and that's why we're currently hedged through 2030 as we close that DJ Basin acquisition in September and hedged 85% of the PDP through 2030 on that deal.

Noel Parks

Great. And just related with hedging. We've -- with the conflict in 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 long-term supply disruption effects on pricing. And I just wondered, is that having happened. Any shifts in -- or anything you might do a little bit differently looking at hedging for that period?

Ben Messier

Well, when evaluating hedging our base asset, we consider sort of the price at which our dividend is funded by distributable cash flow. Sort of 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 in the curve than we have been in the rest of the time were 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.

Operator

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

Jamie Benard

Thanks, everyone, and thanks for joining today. I want to leave you all with this message. The test 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 to you all at the Southwest IDEAS Conference in Dallas on November 18 or on our next quarterly earnings call. Thanks, everyone.

Operator

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