Prepared remarks
Good morning, ladies and gentlemen, and welcome to the Vermilion Q1 2026 Conference Call. This call is being recorded on May 6, 2026. I would now like to turn the call over to Dion Hatcher, President and CEO. Please go ahead.
Good morning, ladies and gentlemen. I'm Dion Hatcher, President and CEO of Vermilion Energy. With me today are Lars Glemser, Vice President and CFO; Darcy Kerwin, Vice President, International and HSE; Randy McQuaig, Vice President, North America; Lara Conrad, Vice President, Business Development; and Travis Thorgeirson, Director of Investor Relations and Corporate Planning. Please refer to our advisory and forward-looking statements in our Q1 release. It describes the forward-looking information, non-GAAP measures and oil and gas terms used today and outlines the risk factors and assumptions relevant to this discussion. I'd like to begin today with a comment on the macro environment. First quarter of 2026 was marked by heightened geopolitical uncertainty with continuing impacts in the global energy markets today. This uncertainty underscores the critical importance of energy security. Vermilion's substantial resource base with exposure to multiple commodities, including gas production in Europe and liquid production tied to Brent benchmarks, provides unique exposure to global prices. This diversity of production extends to our gas-weighted assets in Canada. We have strategically positioned ourselves in the oily window in the Montney and have numerous liquids-weighted zones in the Deep Basin. Operationally, we delivered another strong quarter with production volumes averaging 125,600 BOEs per day, exceeding the upper end of our guidance. Canadian operations contributed an average of 99,700 BOEs per day. That's a 10% increase over the prior quarter, driven by very strong Deep Basin performance and new Montney wells brought online ahead of schedule. International operations averaged 25,900 BOEs per day, and that's reflective of cyclone-related downtime in Australia and natural declines in our European assets, which is prior to the next German gas well coming online in midyear. In total, our production mix consists of approximately 59% Canadian natural gas, 13% European natural gas and 28% liquids with those liquids largely priced off of Brent and WTI. Our realized oil price increased by over 20% from the prior quarter, while our European gas production achieved an average sales price of approximately $16 per MMBtu. This meant that nearly 80% of our Q1 revenue was driven by European gas and liquids production. This underscores the value of our exposure to global pricing. Market fundamentals for European gas remain very supportive with Q2 pricing in excess of $20 per MMBtu. That is over 10x higher than the AECO pricing in Q2. The next four quarters are expected to average approximately $20 per MMBtu. Disruptions in the Strait of Hormuz have impacted global LNG flows at a time when European gas inventories are at multiyear lows with storage levels in Germany at about 25% and the Netherlands at 10%. European countries will need to add approximately 2 Tcf of gas to storage by November to meet the mandated 80% capacity levels requiring competitive action in the LNG market. Of note, we continue to see a more positive tone from governments recognizing Vermilion as a responsible operator with decades of experience, one who has a key role to play in their energy landscape. To further enhance our exposure to premium priced gas markets, we recently joined the Rockies LNG Consortium to evaluate delivering a portion of our Montney gas through the Ksi Lisims LNG project. This would complement our existing agreement on the Alliance Pipeline that connects us to the premium-priced Chicago hub where pricing averaged approximately $5 per MMBtu in Q1. I'll now pass over to Lars to discuss Q1 results in more depth.
Thank you, Dion. In the quarter, Vermilion generated $232 million of funds from operations with $135 million of E&D capital expenditures, resulting in $98 million of free cash flow. Net debt was reduced by an additional $50 million to $1.29 billion as of March 31, bringing our total debt reduction to $770 million over the past year. The timing of the lifting in France reduced Q1 FFO as a result of timing. This reduced Q1 FFO by $10 million, but will benefit Q2 FFO by $13 million due to the increase in the dated rent contract. Debt reduction remains a priority, and we now have more visibility to our $1 billion net debt target through our recent deleveraging resulting from strong operational execution and an improving commodity price outlook. This focus on debt reduction has resulted in a 40% reduction in interest cost per BOE versus Q1 of 2025, and our core asset base has driven Q1 G&A per BOE down by over 50% versus 2025. In addition to the $50 million of debt reduction this quarter, we also paid $21 million to shareholders in dividends and repurchased $5 million of shares through our NCIB. With the move higher in oil and European gas prices in March, we recognized a loss on hedges in the quarter. It is important to note that this is largely driven by noncash losses on hedges in place for future quarters; the portion of our production that remains unhedged will stand to benefit from increased pricing going forward. The realized portion of hedge losses in the quarter was $15 million. And for the balance of the unrealized hedge loss to be realized, pricing would have to remain at March 31, 2026 levels for the duration of our current hedge book. For additional context, we have updated our forecast of 2026 excess free cash flow in our most recent corporate presentation. And after incorporating current prices and the current 2026 estimated realized hedge losses, Vermilion will generate double the EFCF when compared to our 2026 budget projections. On the operations front, we maintained a three-rig drilling program in the Deep Basin, drilling 10 wells, completing 14 and bringing on production 18 liquids-rich gas wells. Several of these wells ranked among the best wells in Alberta throughout the quarter. We have now shifted our Deep Basin drilling to higher liquids-rate wells to capitalize on favorable pricing, which highlights the flexibility of our asset base and depth of inventory. In the Montney, we drilled five, completed six and brought online six liquids-rich gas wells. These wells were brought on ahead of schedule and with strong initial oil rates, while also coming in at a lower capital cost than we had previously guided to. We achieved another milestone. Our planned per-well cost in the Montney is now $8.2 million, down $300,000 from $8.5 million previously. In Europe, we are on track to bring the first Wisselshorst well online in Germany by mid-2026. We plan to spud follow-up wells on the Bommelsen license early next year and expect to commence drilling in the Netherlands in the second half of 2026. These activities support regional energy security through reliable, lower-emissions gas compared to imported alternatives. In Australia, our operations in the quarter were impacted by two cyclone events, the first consecutive direct hits ever. We are proud to say that we successfully managed all aspects of the safe shut-in of operations and evacuation of personnel with production resuming subsequent to the quarter following necessary repairs. While production operations were shut in, we were able to export 300,000 barrels of oil in February. During the quarter, we signed an agreement to acquire producing assets in Germany, adding approximately 1,000 BOE a day of low-decline production, weighted 85% to natural gas, which increases our European TTF-linked gas and Brent-linked oil production, enhances cash flow and provides strategic infrastructure control. The transaction is expected to close in the second half of 2026. We also announced the award of three new concessions in the North German Basin, doubling our acreage to well over 1 million net acres. Finally, we signed an agreement to divest our remaining 60% interest in the SA-07 block in Croatia for net proceeds of approximately EUR 15 million or CAD 24 million. Proceeds from this sale will primarily reduce debt with the transaction expected to close in the second half of the year. These recent steps are aligned with our strategy to reposition our asset base to further enhance long-term profitability. Operational momentum remains strong, and we continue to trend toward the upper end of our full year production guidance range without an increase to our capital budget. We will actively manage around lower AECO pricing to prioritize value over volumes, and we expect Q2 2026 production to average between 123,000 and 125,000 BOE a day. With our focus on liquids-rich production, liquids weighting is expected to increase from 28% in Q1 to approximately 31% in Q2. I will now pass it back to Dion.
Thank you, Lars. I'd also like to thank our Australia staff for their outstanding commitment over the last several months. I've been with Vermilion for 20 years. In that time period, we have never experienced back-to-back cyclone events. Being hit by a Category 3 storm, followed by a Category 4 storm shortly thereafter, was a real test for our team, and they performed exceptionally well in preparing for the storms, preparing our platform and safely restoring production. In summary, this was another strong quarter for Vermilion. Our repositioned portfolio and focus on operational excellence has reduced our unit cost structure and delivered production above our expectations. Our controllable expenses, that is operating, transportation, G&A and interest, were lower by 25% compared to Q1 2025. Our OpEx was down $2 per BOE or 14%. G&A was down $2 per BOE or over 50% and interest was down almost $2 per BOE or over 40%. The lower cost structure helped reduce net debt by another $50 million this quarter, bringing the total reduction to $770 million since Q1 of last year. These gains are coupled with our improving capital efficiencies. In the Montney, we have reduced our planned capital cost per well by another $300,000, improving full cycle economics in our Mica asset, which translates to another $60 million reduction of future capital requirements, bringing the total reduction in the last two years to over $250 million. In the Deep Basin, we continue to realize operational wins. We're now starting to exceed the $200 million of synergies that we estimated shortly after closing the acquisition. And in Europe, we continue to see steady production from the Osterheide well and advance the work to support first production from our Wisselshorst well, our largest discovery in Europe to date. Other key infrastructure will support a growing German gas production over time. In closing, we've built a very large resource base with 1.3 million net acres in Canada and over 2 million net acres in Northern Europe. This long-duration asset base compared with our strong technical teams, capital allocation flexibility and a focus on operational excellence, when combined with only 153 million shares, position Vermilion to generate growing and sustainable free cash flow per share. With that, we'll now open the line for questions.
Questions and answers
And your first question comes from Jeremy McCrea with BMO Capital Markets.
I just want to understand more about Germany here, your growth plans with this new acreage potentially holds? Is there any loosening of regulations? Just can you give us a bit more of the five-year outlook here for Germany and if it can be a much bigger part of the Vermilion portfolio?
Thanks, Jeremy, for the question. I'll just kick it off here before I pass it over to Darcy. I mean I just want to say, I think Germany is core to us. We just spent a few weeks there and it's really exciting with the first Osterheide well, as noted, continuing to produce strong and the second well, Wisselshorst, coming on here in a matter of weeks by midyear. And so it's looking really good. And more importantly, just the size of the resource. What we said in our Investor Day is our plan is to double Germany production by 2030. But the exciting thing for us is that's only 2.9 net wells of the 30 that we've identified. But with that, Darcy, maybe you want to provide some color on where we are, but also maybe the regulatory environment we're getting.
Yes. Thanks, Jeremy, for the question. I think you made reference to this new exploration land that we've acquired. So we are very excited about these three additional exploration concessions that we've gotten in Germany; it brings our total acreage to well over 1 million acres. This acreage is located in the same fairway where we've had historical success in the Netherlands and more recent success in Germany. So we're on trend with those discoveries. And we see potential certainly on these new concessions for additional discoveries. They've just been granted to us, so we do need some time to evaluate this new acreage and understand exactly what's there before we translate that into specific drilling targets. But we have a decade of experience and a decade of running room ahead of us. So this really just adds to our position. In terms of the regulatory environment, I think Germany has proven to be a pretty practical country to work in. We've had some success in getting permits and working with both the local and the federal governments to bring these discoveries on. What we have seen in Germany specifically and more broadly across Europe is a much more receptive environment when we're talking to host governments around the importance of domestic gas production and its importance to security of supply. So we've always enjoyed that in Germany. But again, it's continuing to improve, starting to see discussions both publicly and within government in the Netherlands about the importance of security of supply and the importance of domestic production, and starting to hear noises from countries like Ireland and France about the wisdom of some of their production and exploration bans and whether they should be relooking at those sorts of things. So I think the environment is much more open for what we're trying to do, and I think there's a recognition that what we're doing is important to energy security in Europe.
Maybe just a bit of a follow-up. Is there an M&A market opening up here that could produce more deals? Or could you describe what the M&A market looks like now, assuming pricing has normalized?
I'm going to pass it over to Lara.
You bet. We recently announced a deal acquiring 1,000 barrels of oil equivalent per day in Germany. What we liked about it is that it is adjacent to and increases our working interest in existing assets. We see potential there. I'm new to Vermilion, but Vermilion is not new to Germany and has developed strong relationships with the players there. We have a great team in Germany, so you'll see us active across deal flow and proactively pursuing opportunities. We view Germany as core to us and will continue to assess opportunities there.
Your next question comes from Spencer Limming with CIBC World Markets.
Just touching more on the regulatory environment: are you seeing discussions looking positive in terms of government policy to increase production? Has anything materialized in terms of fast-tracking permits, or have you heard any conversations about what that might look like if countries are looking to increase production?
Thanks for the question. I can summarize maybe what Darcy said and please jump in Darcy, if you have comments. I mean I think there's just like Canada in every jurisdiction, there's an established timeline and steps to assess and acquire permits in all jurisdictions. And I think the way to think about it is we're seeing the resources assigned from the government's point of view to ensure that those timelines are met and those permits are awarded in a timely manner. So what that means is we brought two wells on last fall in the Netherlands. We're going to bring our Wisselshorst well on mid this year. We're drilling another well here, kicking it off in the summer in the Netherlands. We got our two German wells planned early next year, right? So it's a daisy chain of activity. And what we do is we're planners, right? So we're working on permits now that we're going to drill in '27, '28, '29. So we just get ahead of it and what we want in all jurisdictions is stable and predictable. And so we have no issues with the rules. We just want to make sure they're followed consistently with good timelines. And that's what we're seeing. And frankly, that works well for us. Anything I missed there, Darcy?
Okay. Great. That's really good color. Sorry, do you want to go?
No, sorry, I didn't have anything to add.
Okay. Yes. No, that's great. Just a follow-up question, pivoting over now to the Deep Basin. So you guys have obviously shown over the years in terms of bringing costs down across the Montney. And I'm just kind of curious in terms of applying those cost-saving practices to the Deep Basin on the acquired lands. Do you see similar ability to reduce costs across those lands over time? And what would kind of be the cadence or timeline of achieving those better practices?
Thanks, Spencer. Again, Spencer, I'll kick it off here and pass it over to Randy McQuaig. But hopefully, the read-through, I made a comment here on the script that we're now starting to exceed the $200 million of synergies that we identified post the acquisition. And that is a combination of expense but also capital. I think we showed some things on the Investor Day around per-well costs coming down year-over-year. And with the three rigs we're running consistently in Deep Basin, we're seeing those wins. But, Randy, over to you to build on those comments.
Yes. That's a fair comment. In the Deep Basin, with our three-rig program, we've been able to leverage our operational scale and dominant position. We've seen costs come down, and as those savings flow through we'll work through them over the next couple of quarters. We've definitely seen cost reductions and, with continuous improvement, expect further efficiencies as we increase activity in the program.
There are no further questions at this time. I'd like to turn the call back over to Dion Hatcher for any closing remarks.
Well, thanks again for the call. And with that, we'll close the line. Enjoy the rest of your day.
Ladies and gentlemen, this concludes today's conference call. We thank you for your participation. You may now disconnect.