维特斯能源 (VTS) 2026年第三季度业绩电话会：DJ盆地交易与上调业绩指引

Vitesse Energy（纽约证券交易所代码：VTS）公布2026财年第三季度日均产量为16,824桶油当量（BOE），调整后EBITDA为3930万美元。9月份完成的DJ盆地资产收购在三季度贡献有限，但预计将在第四季度提供完整的整季产量和现金流。

核心要点

• 三季度日均产量为16,824桶油当量，其中原油占总产量的60%。
• 调整后EBITDA为3930万美元，调整后净利润为250万美元，自由现金流为940万美元。
• GAAP净亏损为3640万美元，完全归因于大宗商品衍生品产生的4660万美元非现金未实现亏损。
• 董事会宣布派发每股0.4375美元的季度现金股息，按年化计算为1.75美元。这是自2023年1月分拆以来，Vitesse Energy连续第16个季度派发股息。
• 管理层将2026财年产量指引调整为每日16,600至17,200桶油当量，并将钻井和完井资本支出指引调整为8000万至9000万美元。
• 截至季度末，总债务为1.905亿美元，相当于过去12个月调整后EBITDA的1.3倍。管理层表示，在纳入DJ盆地现金流及第四季度预期新增产量后，前瞻性杠杆率约为1倍。

关键财务数据

业务与经营业绩

Vitesse于9月中旬完成了DJ盆地资产的收购。因此，该交易对三季度产量和财务业绩的贡献有限。管理层预计从第四季度开始将获得DJ盆地完整的整季度产量。

截至季度末，该公司持有8,732口生产井的权益，由33名全职员工提供运营支持。这相当于每名员工对应约265口生产井，自2022年以来增长了64%。管理层将这一提升归因于规模效应、人工智能以及内部流程改进。

截至9月30日，Vitesse有6.5口净井处于钻井或完井阶段，另有13.0个净获批井位。运营合作伙伴在三季度开钻了2.0口净井，并将2.0口净井投产；相比之下，二季度开钻了1.8口净井，投产了1.7口净井。

超长水平井段（Extended laterals）仍是提升资本效率的关键驱动因素。2026财年批准的资本支出授权（AFE）中，约有70%涉及水平段长度达3英里或更长的水平井。管理层表示，这些井应能平缓公司的基础递减率，并减少维持产量所需的资本。

Vitesse还在威利斯顿盆地（Williston Basin）运营60口油井。该公司正在评估其租赁地块以及与相邻运营商的潜在合作，以寻找更长水平段的开发机会。管理层预计在第一季度将对未来的自主运营开发有更清晰的规划。

管理层业绩指引

Vitesse将2026财年全年产量指引调整为每日16,600至17,200桶油当量，预计原油仍占总产量的60%至62%。管理层预计第四季度投产井数量将加速增长。

钻井和完井资本支出指引设定为8000万至9000万美元。该区间不包括收购资本，公司对收购资本进行独立评估和资金融通。

对于2027财年，管理层的初步展望是相较于2026财年年度指引持平至小幅增长。如果当前远期曲线价格保持不变，预计资本支出将与2026财年水平相当。

管理层还表示，基于目前对超长水平井的预测以及现有生产基地的老化情况，未来三到四年内维持性资本支出可能会下降约10%。

风险与关注焦点

• 在通过循环信贷额度为DJ盆地收购提供资金后，杠杆率上升至过去12个月调整后EBITDA的1.3倍。管理层预计，随着被收购资产的现金流并入业绩，该比率将向1倍的目标靠拢。
• 7月和8月自主运营资产发生机械故障后，租赁运营费用有所增加。Vitesse雇用了成本较高的24小时修井作业队来恢复生产。管理层预计每桶油当量的成本将回落至此前水平。
• 如果大宗商品价格保持在套期保值水平之上，衍生品合约随着时间推移将需要进行现金结算，但管理层指出，这些支出将被基础产量更高的实现价格所抵消。
• 2027财年的初步产量和资本展望取决于当前的远期曲线价格和运营商的活跃度。

分析师问答亮点

管理层表示，更长的水平段应有助于在三到四年内将维持性资本支出减少约10%。更快的钻井和完井周期也缩短了Vitesse支付其分摊的油井资金与获得生产现金流之间的时间间隔。

在成本方面，管理层将三季度租赁运营费用的增加定性为暂时的，并认为这与机械故障和加速修井作业有关。公司还预计行政管理费用将同比有所下降，同时强调收购资产的整合仅需增加有限的人力成本。

Vitesse表示，尽管活动小幅增加，但未出现钻井能力严重短缺的情况。较大的运营商受益于较长期的钻机合同，而较小的运营商在现货市场上可能面临更大的排程风险。

管理层表示，收购估值通常随远期曲线价格变动。Vitesse在评估交易时，优先考虑回报率、每股净资产值增值和可分配现金流增值。

根据修订后指引的中点，2026财年剩余原油产量的约64%和剩余天然气产量的57%已进行套期保值。原油套期保值组合延伸至2030年，加权平均价格约为每桶68美元。Vitesse还对DJ盆地收购资产截至2030年的已开发探明在产（PDP）产量的85%进行了套期保值，最近又增加了2028年和2029年的套期保值。

业绩电话会议完整文字记录

完整财报电话会议逐字稿

管理层陈述

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.

分析师问答

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.