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Good morning, ladies and gentlemen, and welcome to the Vermilion Q1 2026 conference call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please press star 0 for an operator. 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.

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, Brandon McCue, Vice President North America, Lara Conrad, Vice President Business Development, and Travis Ferguson, 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 it 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, but 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 liquids production tied to Brent benchmarks, provides unique exposure to global prices. This diversity of production extends to our gas-related 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.

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 mid-year. In total, our production mix consisted 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 CAD 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 CAD 20 per MMBtu. That is over 10 times higher than the equal pricing in Q2.

The next four quarters are expected to average approximately CAD 20 per MMBtu. Disruptions in the Strait of Hormuz have impacted global LNG flows at a time when European gas inventories are at multi-year 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 to the Cedar LNG project.

This would complement our existing agreement on the Alliance Pipeline that connects us to the premium price Chicago hub for pricing average approximately CAD 5 per MMBtu in Q1. We'll now pass over to Lars to discuss Q1 results in more depth.

Thank you, Dion. In the quarter, Vermilion generated CAD 232 million of funds from operations, with CAD 135 million of E&D capital expenditures, resulting in CAD 98 million of free cash flow. Net debt was reduced by an additional CAD 50 million to CAD 1.29 billion as of March 31st, bringing our total debt reduction to CAD 770 million over the past year. The timing of lifting in France reduced Q1 FFO as a result of timing. This reduced Q1 FFO by CAD 10 million but will benefit Q2 FFO by CAD 13 million due to the increase in the dated Brent contract. Debt reduction remains a priority, and we now have more visibility to our CAD 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 costs per BOE versus Q1 of 2025, and our core DUP asset base has driven Q1 G&A per BOE down by over 50% versus 2025. In addition to the CAD 50 million of debt reduction this quarter, we also paid CAD 21 million to shareholders in dividends and repurchased CAD 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 non-cash losses on hedges in place for future quarters, and that 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 CAD 15 million.

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. 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 3-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 5, completed 6, and brought online 6 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 CAD 8.2 million, down CAD 300,000 from CAD 8.5 million previously. In Europe, we are on track to bring the first Wisselhorst well online in Germany by mid-2026. 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 2 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 SA7 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 2nd 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. Also like to thank our Australia staff for their outstanding commitment over the last several months. I've been with Vermilion for 20 years, and in that time frame, we've 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 reduced our unit cost structure and delivered production above our expectations. Our controllable expenses, that is operating, transportation, G&A, and interest, was lower by 25% compared to Q1 2025. Our OpEx was down CAD 2 BOE or 14%.

G&A was down CAD 2 per BOE or over 50%, and interest was down almost CAD 2 per BOE or over 40%. This lower cost structure helped reduce net debt by another CAD 50 million this quarter, bringing the total reduction to CAD 770 million since Q1 of last year. These gains are coupled with our improving capital efficiencies. In the Montney, we've reduced our planned capital cost per well by another CAD 300,000, improving full-cycle economics on our Mica asset, which translates to another CAD 60 million reduction of future capital requirements, bringing the total reduction in the last two years to over CAD 250 million. In the Deep Basin, we continue to realize operational wins.

We're now starting to exceed the CAD 200 million of synergies that we estimated shortly after closing the acquisition. In Europe, we continue to see steady production from the Osterheide Well and advance the work to support first production from our Wisselhorst Well, our largest discovery in Europe to date, along with other key infrastructure supporting growing German gas production over time. In closing, we built a very large resource base of 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, positions Vermilion to generate growing and sustainable free cash flow per share. With that, we'll now open the line for questions.

Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press star, followed by 1 on your touch tone phone. You will hear a prompt that your hand has been raised. Should you wish to remove your hand from the queue, please press star, followed by 2. If you're using a speakerphone, please lift the handset before pressing any keys. Just a moment for your first question. Your first question comes from Jeremy McCrea with BMO Capital Markets. Please go ahead.

Yeah. Hi, guys. I just wanna understand more about Germany here, your growth plans with this new acreage potentially hold. Is there any, you know, loosening of regulations? Just can you give us a bit more of a, you know, 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 really exciting with first Osterheide Well, as noted, continuing to produce strong, and the second well, Wisselhorst, coming on here in a matter of weeks by mid-year, and it's looking really good. More importantly, just the size of the resource. You know, what we've said in our investor days, our plan is to double Germany production by 2030, the exciting thing for us is that's only 2.9 net wells of the 30 that we've identified.

With that, Darcy, maybe you want to provide some color on where we are, but also maybe the regulatory environment we're getting.

Yeah. Thanks, Jeremy, for the question. I think you made reference to the, this new exploration land that we've acquired. We are very excited about these 3 additional exploration concessions that we've gotten in Germany. Brings our total acreage to well over 1 million acres. This acreage, it's located in the same fairway where we've had historical success in the Netherlands and more recent success in Germany, we're on trend with those, all of those discoveries. We see potential certainly on these new concessions for additional discoveries. You know, they've just been granted to us, we do need some time to evaluate this new acreage and understand exactly what's there before we kinda translate that into specific drilling targets.

You know, 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, you know, 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. You know, we've always kind of 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. Starting to hear noises about, from countries like Ireland and France about, you know, the wisdom of some of their production and exploration bans and whether they should be re-looking at those sort of things. I think the environment is much more open for what we're trying to do, and I think a recognition of that what we're doing is important to energy security in Europe.

Thanks, Darcy.

Maybe I'll just kind of a bit of a follow-up there then. Is there, like, an M&A market here that's opening up potentially a little bit more where there could be some more deals? You know, maybe just describe what the M&A market looks like now, assuming normalized pricing in that.

I'm gonna pass it over to Lara. Lara, you wanna provide some comments on M&A Europe?

You bet. I mean, we just recently announced our one deal of acquiring 1,000 barrels a day in Germany. What we liked about that is it's adjacent or increasing our working interest in existing assets. We do see potential. I think Vermilion I mean, I'm new to Vermilion, but Vermilion is not new to Germany and has developed strong relationships with the players there. We've got a super team in Germany. So I think you'll see us active in all deal flow as well as looking proactively. Germany, we do view as core to us, so we'll continue to assess opportunities there.

Thanks, Lara.

Okay. Thank you, guys.

Thanks, Jeremy McCrea.

Your next question comes from Spencer Leman with CIBC World Markets. Please go ahead.

Hey. Good morning, guys. Thanks for taking my question. Just kinda touching more on the regulatory environment. Are you seeing Discussions are looking good, right, in terms of government policy, in terms of increasing production? Has anything materialized in terms of fast-tracking permits, or have you heard any conversations around maybe what that might look like if the countries are looking to increase production?

Thanks for the question. You know, I can summarize maybe what Darcy said, and please jump in, Darcy, if you have other comments. I mean, I think there's Just like Canada and every jurisdiction, there's an established timeline and steps to assess and acquire permits in all jurisdictions. I think the way to think about it is, you know, 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. What that means is, you know, we brought 2 wells on last fall in the Netherlands. We're going to bring our Wisselhorst well on mid this year. We're drilling another well here, kicking it off in the summer in Netherlands. We got our 2 German wells planned early next year, right?

It's a daisy chain of activity and, you know, what we do is we're planners, right? We're working on permits now that we're gonna drill in 2027, 2028, 2029. We just get ahead of it, and what we want in all jurisdictions is stable and predictable. We have no issues with the rules. We just wanna make sure they're followed consistently with good timelines. That's what we're seeing, and frankly, that works well for us. Anything I missed there, Darcy?

Okay. Yeah, great.

Good, sir.

That's really good color. Oh, sorry. Darcy, did you wanna go?

No, sorry. No, I didn't have anything to add, Spencer. Thanks.

Okay. Yeah, no, that's great. Just a follow-up question pivoting over now to Deep Basin. You guys have obviously shown over the years in terms of bringing costs down across the Montney, and I'm just kinda 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 kind of achieving those better practices?

Thanks, Spencer. Spencer, I'll kick it off here and pass it to Randy McQuaig, you know what? Hopefully, the read-through, I made a comment here on the script that we're now starting to exceed the 200 million CAD of synergies that we identified post the acquisition, and that is a combination of expense plus also capital. You know, I think we showed some things on there Investor Day around per well costs coming down, you know, year-over-year. And with the three rigs we're running consistently in Deep Basin, you know, we're seeing those wins. I mean, Randy, over to you to build on those comments.

Yeah. Yeah. It's fair comment. You know, I think the Deep Basin, you know, with our 3-rig program, we've really been able to leverage our operational scale and our dominant position in that Deep Basin. We have seen costs come down as they flow through. We'll kinda work through it in the next couple quarters here. I would say we have definitely seen costs come down and continue to work on, you know, with this continuous improvement, we expect to see, you know, further efficiencies as we continue to get more active in the program.

Thanks, Randy.

Great. Thanks, guys. I'll turn it back.

Yeah. Thanks, Spencer.

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.

Good morning, ladies and gentlemen, and welcome to the Vermilion Q4 2025 Conference Call. [Operator Instructions] This call is being recorded on Thursday, March 5, 2026. I would now like to turn the conference over to Dion Hatcher, President and CEO. Please go ahead.

Thank you. 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 HSE; Randy McQuade, 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 on forward-looking statements in our Q4 release. It describes forward-looking information, non-GAAP measures and oil and gas terms used today, and it outlines the risk factors and assumptions relevant to this discussion. Vermilion had an impactful year, positioning ourselves as a global gas producer with top decile gas prices, lower cost structure and a long-duration asset base capable of delivering sustainable free cash flow for decades to come. In 2025, we delivered record production and marked a pivotal year in our company's history through strategic A&D activity, particularly the acquisition of the high-quality assets in our core Deep Basin area. And the disposition of noncore assets in Saskatchewan and the United States, our portfolio is now focused on liquids-rich gas assets in Canada and premium priced gas assets in Europe, building one of the largest land footprints in the Deep Basin, along with our growing liquids-rich gas business in the Montney has sharpened our operational focus. This allows us to improve our cost structure and more importantly, higher profitability in our Canadian portfolio. In Germany, during Q1, we brought online the first well of the deep gas exploration program, Osterheide, and progress the build-out of infrastructure to facilitate the production from one of our largest European gas discoveries, Wisselshorst, which we expect to bring online by mid-2026. In the Netherlands, we successfully drilled 2 wells with multiple prospective zones and brought them on production in Q4. The long runway of future prospects we've identified in Europe with finding and development costs of approximately CAD 1.50 per Mcf, represents an opportunity for profitable organic growth in our domestic European gas business. These core assets drove another strong quarter in Q4, both operationally and financially. Production of 121,308 BOEs per day was ahead of guidance. This was partially driven by highly productive wells in the Deep Basin, where 3 of the most productive gas wells in December were Vermilion owned and operated. Production also benefited from record volumes in the Montney as well as outperformance from the Osterheide well in Germany, which had 40% higher production compared to the third quarter and generated approximately $8 million of free cash flow in Q4 alone. Strong realized gas pricing of $5.50 per Mcf or double the AECO benchmark was driven by our direct European gas exposure, where TTF prices averaged $15 per MMBtu in the quarter. Our realized gas prices also benefit from enhanced market diversification in Canada and a sophisticated hedging program. On the operational side, we apply a continuous improvement mindset to the areas within our control, safety, production and cost management. I'm excited about the progress by each team across the business. In Canada due to the improved operational scale, high-quality assets, our unit operating costs are now the lowest in over a decade, which improved our corporate unit costs, now the lowest since 2020. Investments in infrastructure such as the Mica facility and development initiatives in Germany are expected to deliver an increase in excess free cash flow over the next few years. The long duration of our asset base and our commitment to disciplined capital allocation, when combined with only 153 million shares outstanding, positions Vermilion to add meaningful per share value. Moving to reserves. Vermilion's total proved plus probable or 2P reserves increased by 36% from the prior year, reaching 592 million BOEs. This growth was driven by a combination of organic development and the Deep Basin acquisition, which closed in February 2025, partially offset by the divestment of the United States and Saskatchewan assets in mid-2025. We added 86 million BOEs of proved developed producing or PDP reserves and 201 million BOEs of 2P reserves in 2025. Our average finding, development and acquisition costs, including future development costs, were $14.91 per BOE for PDP and $7.71 per BOE for 2P. That's a recycle ratio of 1.8 to 3.5x, respectively. These recycle ratios highlight the capital efficiency and strong returns of our reserve additions. It's also worth noting that PDP reserves do not include any volumes or present value associated with the Wisselshorst discovery well on the Bommelsen license, whereas the 2P reserves include approximately 7 million BOE or 43 Bcf related to our 64% working interest in the initial discovery. We have identified up to 6 additional drilling locations on the Bommelsen license that currently have no 2P reserves assigned, representing significant further upside for European reserves. We remain on track to spud the first 2 of these locations in early 2027 with long lead equipment ordered, the drilling rig secured and permitting progressing as expected. By applying the learnings from the previous program, we anticipate lower cost and faster cycle times resulting in these wells being on production in the second half of 2028. The 2P reserve life index was 14 years, in line with our historical averages. Our internal estimate is we have 1,700 drilling locations across our 1.3 million net acres of land that's in the Deep Basin and Montney and only 23% of these are included in our year-end reserves. Also of note, internal estimates of initial gas in place related to exploration and development prospects in Europe are minimally included in our year-end reserves. We believe there's significant upside to our European gas reserves given our 1.4 million net acres land across Germany and Netherlands combined with our track record of exploration success. Across our portfolio, the combination of book reserves and additional internally estimated locations provide long-term visibility for future production and cash flow. Before-tax net present value of our 2P reserves discounted at 10% using the 3 consultant average pricing as of Jan 1, 2026, and deducting year-end net debt, is $23 per basic share, well in excess of our current share price. I will now pass to Lars to discuss the Q4 results in more depth.

Thank you, Dion. Vermilion generated $241 million of funds flow from operations in the fourth quarter. An active quarter of drilling saw $192 million invested in exploration and development capital expenditures, resulting in free cash flow of $49 million. Production averaged 121,308 BOE a day with a 69% weighting to natural gas. In Canada, we executed a 3-rig drilling program in the Deep Basin, drilling 16 and bringing on production 17 liquids-rich gas wells. We made the deliberate decision to defer the start-up of several highly productive wells that were drilled and completed in the third quarter into mid-Q4, allowing us to capture stronger realized gas prices and maximize returns. As Dion noted, these were some of the most prolific wells in Alberta. In the Montney, we drilled 4 gross and net liquids-rich gas wells, which are scheduled for completion and start-up in Q2 2026. Combination of strong Deep Basin well results, the return of previously shut-in production and record Montney performance drove a significant increase in production in Canada. Normalized for disposition activity, our Q4 production was more than 5,000 BOE per day higher than in Q3 with a lower unit cost structure, improving cash flow netbacks and overall profitability of our Canadian operations. International operations averaged 30,137 BOE per day in the fourth quarter, consistent with Q3. New production in the Netherlands and increased gas output in Germany largely offset natural declines in Ireland, Australia and Croatia. Vermilion completed and brought online 2 gross or 1.2 net natural gas wells in the Netherlands during the fourth quarter. We also advanced permitting and technical work in the Netherlands to facilitate the drilling of 1 gross or 0.5 net wells in 2026. Our approach to European development remains disciplined, leveraging our long-standing operating experience and strong regulatory relationships. In Germany, infrastructure development for the first Wisselshorst well, which is a 0.6 net ownership to Vermilion continued during the quarter, with first production expected mid-2026. The Osterheide well brought on earlier in the year saw an increase in production, averaging 10 million a day or 1,600 BOE a day for the quarter. Germany continues to be a key region for Vermilion, providing direct exposure to premium European gas markets and development upside. On the balance sheet, we accelerated our debt reduction during the fourth quarter by selling a portion of our ownership in Coelacanth Energy, which resulted in $42 million of incremental debt reduction and a realized gain on disposition of $12 million. We continue to hold a 10% ownership in Coelacanth. Returning capital to shareholders remains a core priority. Our strong free cash flow generation and disciplined capital allocation provide the foundation for sustainable dividends and opportunistic share buybacks. Our debt reduction trajectory has been accelerated with the sale of the Coelacanth shares and an increasing commodity price environment. This allows us to continue to be opportunistic in our balance of further debt reduction and returning capital to shareholders. As we continue to grow our asset base and improve profitability, we are confident in our ability to deliver attractive shareholder returns over the long term. I will now pass it back to Dion.

Thank you, Lars. Prior to my closing remarks, I want to take a moment to thank our staff in Australia. In Q1, our Wandoo platform was impacted by a category three cyclone, which resulted in minor damage than the delay of the planned crude export lifting. We do budget for cyclone downtime each year. And fortunately, it's been more than 5 years since we've had an experience of a direct storm event. Again, thank you to our staff for their hard work and commitment to safety and the lead up during and after the cycle event. In addition, our team has worked very closely with the regulator on the integrity of our asset, including planned maintenance of the export system, which is already included in our budgets. In late February, we exported over 300,000 barrels of crude following the cyclone-related delay, and we're in the process of restoring production on the Wandoo B platform. So on the back of the record 2025 annual production and strong Q4, while factoring in Australia cyclone-related downtime, we are providing a Q1 outlook of 122,000 to 124,000 BOEs per day. We expect production in the first half of 2026 to be in line with recent levels with lower Q3 production reflective of the planned maintenance as outlined with our budget release. The recent run-up in global gas prices offer as a reminder that in a commodity-based business, being able to sell your product for more offers a substantial advantage. Our unique portfolio offers direct exposure to European gas, where inventories are well below the 5-year averages and the current price is over $20 per MMBtu as well as Brent crude, both of which have been impacted by recent geopolitical events. In closing, it has been a very active year, high grading our portfolio and advancing major projects. Through this busy time, we have outperformed on the operational side, and that comes down to the exceptional work of our employees and contractors. This is an exciting time at Vermilion. The strategic road map to 2030 as outlined in our recent Investor Day. Multiyear plan reflects a disciplined approach to long-term profitability designed to generate meaningful per share excess free cash flow growth even under a flat commodity price environment. The higher free cash flow growth will support debt reduction and increased shareholder returns. Our asset base offers longevity, capital allocation flexibility, our top decile realized gas price, along with significant upside driven both by our operational excellence and our large resource position. We remain committed to operating with discipline, maintaining a strong balance sheet and investing in high-return projects that drive value for our shareholders. With that, we'll now open the line for questions.

[Operator Instructions] Your first question comes from Menno Hulshof with TD Cowen.

At your Investor Day in December, you talked about material free cash flow inflection starting in 2028. And at that time, I believe you were anchoring to something close to strip gas prices and oil prices that were generally north of $70, which could now prove conservative. So with that in mind, how would you frame free cash flow inflection in 2028 relative to what you were talking about in December?

Thank you, Menno. I appreciate the question. You're right. When we went through the Investor Day, we used $70 WTI, $3.50 AECO and CAD 13 for TTF, and using those numbers, and to your point, the inflection is driven by the ramp-up in Germany volumes with the gas that we see coming online there, but also, of course, the Montney, where we've nearly built out the kit and we'll get our production up to 28,000 BOEs a day. And with that, we'll see the higher production, lower capital. So we were running at about $2.70 per share of excess free cash flow at that time, which was, again, based on that price deck. But maybe I'll pass it over to Lars, if you want to kind of tie that price deck to potential upside from where we are today.

Yes. No, it's a good observation, Menno, in terms of the run-up here that we've seen recently. And so we've updated the slide in our slide deck. This would be Slide 13, to show what the impact of the run-up in commodity pricing is here. So we're showing FFO for 2026 around $950 million. That's a 40% increase to our excess free cash flow. Some of these near-term price moves haven't necessarily rippled through the curve yet. So that's something that we'll monitor. We stress the business as well as look at upside to the business on multiple price decks, but we are capturing a pretty decent portion of what we've seen here in the last week or so in terms of the commodity price run-up.

Yes. I mean I was just -- I guess my second question ties exactly into what you were just describing, and it's a standard hedging question. Like there's a lot of backwardation. There's limited liquidity the further out you go. Are you getting anything done today? Are you looking to capitalize on that? Capitalize is a wrong word, it's a horrible situation, but are there opportunities to hedge further? And is there a scenario where you hedge more aggressively than you have in the past?

Yes. Menno, Lars here again. So we're about 50% hedged on European gas for 2026, 53% on oil and then 45% on North American gas. Some of the recent hedges that we've put in place, specifically on oil have had participating structures. So calls that are -- allow us to participate in this rally. On European gas specifically, we have been active hedging this past week, locking in some of the price increases here. In the past, I'm not saying that this will be the playbook here, but in the past, we have taken our hedge percentage on a commodity up to 70% if we see an opportunity to lock in revenue as a result of significant price increases. So that is something that we'll continue to look at as a team. We will also continue to monitor periods like 2027, 2028 as well to see if some of these moves are going to be structural throughout the curve and take advantage if there is something to take advantage of.

Your next question comes from Amir Arif with ATB Capital.

Just 3 quick questions. Just first on the Deep Basin well outperformance. Just curious, is that -- are you targeting more Tier 1 locations or specific zones? Or do you feel that this recent well outperformance relative to your budget or your type curve can continue through the rest of '26?

Thanks, Amir. I'll pass it over to Randy. He can't wait to answer this question.

Yes, thanks. So yes, this really is kind of a continuation of the positive results that we showed in the Investor Day, where we had the strong kind of IP30 rates from the second half of 2025 drill program. That's continued to perform. And then when you take the results from our current 3-rig program where we're currently drilling, we brought on an additional 14 wells and they've also exceeded expectations. So it's worth noting that in that well mix, we have quite a wide range of well types and production areas. So that really does speak to our depth of inventory. We're not -- as you mentioned, it's not all Tier 1 locations. We are also drilling proof-of-concept wells. So it speaks to our depth of inventory and really the efforts of everybody on the Deep Basin teams to continue to achieve these strong results.

Okay. So it sounds like there's a good chance for these well outperformance to continue above the type curve. Would that be a fair comment?

Yes. It's very -- yes, based on the results to date, yes.

Yes. I mean, I think we've got 40, 45 wells, Amir, for the program, and we're first quarter into it, but everything we're seeing in the first quarter is encouraging. So we can provide more updates as we go. But to Randy's point, I think the team is doing an excellent job with the locations they are selecting and the execution. So as we get more data, we can revisit where we are.

Okay. Those are great results. Second question, just on Australia, can you provide a little more granularity on when do you expect Australian volumes to ramp back up to previous production levels?

Thanks. I'll pass it to Darcy Kerwin, our VP International and just talk with -- on Australia, the kind of plan there to kind of watch -- maybe a little more color on what happened, but more importantly, the plan to restore production here.

Yes. Thanks for that, Amir. I'll start by giving a bit of background on the issues that we've been having in Australia. So in December of last year, while we're performing inspection and maintenance activities on our export system, we did have a small leak on one component of that system. Now at the time, the system was not exporting. We were isolated for maintenance. But nonetheless, we did have a release of residual crude oil from that part of the system. We liaised pretty closely with the regulator, both with our initial spill response and then subsequent repair plans for that system. That did require an approved diving campaign to address the issue that we had. That diving campaign was completed by mid-January. On February 6, we did receive a notice from the regulator that limited the use of this export system, kind of a standard regulator response kind of in a situation like that. And then later that same day, we did receive their approval to complete a planned loading after we formally responded to their issued notice. So in parallel to all this, we had a tropical cyclone that had been building offshore Australia, and we did have a direct hit from category three tropical cyclone on the weekend of February 7. That shut in both our production operations and our export systems, which did delay an export that we had planned. We've conducted the damage assessments and are completing necessary repairs at this point in order to restart production operations on Wandoo B. We did manage to successfully complete an export of over 300,000 barrels last Friday, so February 27. A little bit more longer term, we had already planned and budgeted for the replacement of portions of this export system. And we had a completed engineering, received bids in 2025. We've committed to fabrication starting this year in offshore installation in 2027, and that's kind of now a formal commitment we've made to the regulator to do that.

Thanks, Darcy. And then with respect to Q1, we've assumed minimum volumes, Amir, post the early Feb shutdown. So in our Q1, we effectively -- we just want to diligently give the guys some time to restart, which we're in the process of doing. So going into Q2, we expect things to be back to normal. But at this point, we want to be conservative for Q1.

Okay. So but by 2Q, you should be fully ramped back up? By the end of 2Q for sure, around there?

That's our plan.

Okay. Okay. Sounds good. And then just one final question. Just noticed some negative technical revisions on the 1P, 2P side in both North America and international. Could you just provide a little color behind.

Just want to make sure I heard you there, Amir, negative technical revisions on the international side?

It was on both the international and the North American side. There was some negative technical revisions on 1P and 2P. So just some color around what was driving that.

Okay. I'll pass it over to Lara, she'll take that one. Thanks.

For sure. Thanks, Amir. So really, when we at the negative technical, this is a result of us high-grading our reserves book, really primarily as a result of the M&A activity. So when we think about in Canada, the team in Canada under Randy have done a great job of high-grading locations, part of why we saw those great results in the Deep Basin. And so now we've shifted our reserves book to reflect that. So really, the negative technicals are because we've replaced locations with locations that we see as having better profitability. And you can really see this because when you look at the numbers, we've added 4x as much volume through drilling extensions as we removed in our technical revisions in the Deep Basin. So a net positive overall, but negative from the ones that we replaced. As far as the international side of the book, we did have some minor negative technicals in the Netherlands, Germany and France. And this is really to do with, again, shifting development plans between wells as well as our capital allocation decisions, prioritizing drilling in Canada and the Deep Basin and Montney and in Germany over development opportunities in France. So just really making sure that our reserves book matches our long-term plans as an organization.

That makes a lot of sense. So it's mostly locations that have been taking out, not really production performance on existing wells. Is that fair?

That's correct. Yes.

Your next question comes from Jeremy McCrea with BMO Capital Markets.

Maybe just probably back to Lara here. Can you give me a sense of what the M&A market looks like here now? Just in terms of how many deals have you potentially looked at? Is there more deals potentially to come, you think? And then I've got one more follow-up question here as well.

Thanks, Jeremy. So just general M&A wherever, but maybe, Lara, do you want to provide a commentary there?

For sure. We've got a really great portfolio when it comes to looking at M&A opportunities, especially on the back of the Westbrick acquisition. I think whenever you do a rejig of your portfolio, it opens up further opportunities. So I'll give the standard M&A response. We look at everything. And when we have something to talk to, we'll let you know. But do you think there's going to be some interesting opportunities, both in Canada and in Europe. You've seen us core up the portfolio. Vermilion has done some divests recently, which is a little bit different than historically, but we're really trying to create that focused portfolio. So M&A will be part of that when we see the right opportunities.

Okay. And maybe just a bit more follow-up with Amir's question here earlier. When these better wells were coming out of the Deep Basin, was there anything -- I know you talked about like the geology looks good and you have a lot of Tier 1, but was there anything different that you did on the drill or completion design that led to the better results? Or was it just almost 100% geology?

I'll just give a quick answer and pass it on to Randy if he wants to elaborate. But no, I think it's the rock, Jeremy. As you know, the history is we've developed our legacy land position over the years, and I think the teams did a great job of working that land base harder. Effectively now they've got a bunch of new inventory and high quality. And you put the, I would say, the high-performing teams of Vermilion and Westbrick together and that range for us has found a lot of opportunities, ability to extend wells and again, just make things happen. But I think it's really the rock quality we're seeing. But Randy, anything I missed there or...

Yes. The only other thing I would add is the ability -- the combination of our 2 land bases plus all the deals we've done, we've done lots of swaps and Crown land sales that have created a bit more of land. So we're able to drill optimal locations as opposed to previous where we weren't. So I would say on the drilling completions, nothing different than what we've done. We've continued to perform, costs come in where we expect them to come in. So that's all good. It really comes down to geology and optimal from the land position.

Thanks, Randy.

Your next question comes from Dennis Fong with CIBC World Markets.

My first one is just around Osterheide. Obviously, that's fantastic to see the incremental uplift in terms of the production. As I recall, there is -- I think from your Investor Day, you highlighted a little bit about infrastructure and kind of local gathering constraints. Can you talk towards we'll call it, the durability of the higher throughput and kind of what some of the considerations happen to be?

Thanks, Dennis. I mean, I'll give a quick answer and then pass it to Darcy to elaborate. But I mean, I think the guys have positioned it well where we've got the well set up to be able to deliver and we've seen higher demand, which, again, probably no surprise with the situation in Europe, and it's been pretty steady here into the new year as well. But Darcy, what am I missing there?

Yes. I think that covers it. I would add, Dennis, the kind of infrastructure constraints that we had assumed are probably not as negative as we assumed initially. So we expect that the production rates that we have seen as of late will continue flat kind of through 2026. There is some day-to-day kind of market variation depending on who's buying and sending gas to different points. But overall, I think there is more capacity in that part of the system than we had assumed and the market seems to have a desire for that gas. So I think we expect that, that will stay flat.

Okay. Great. And then does that also bode well then for some of the opportunities you were discussing around Wisselshorst?

Yes, I think it does. Now it's not a direct same kind of tie-in point, but I think we were again quite conservative on our assumptions on both the infrastructure and what the market in that area would take. But I think directionally, it's going in the right direction. And yes, I think we hope to see the same results on kind of Wisselshorst takeaway as we've seen in Osterheide.

Great. My second question, really shifting focus to the Netherlands. It's obviously great to see that you received the permits there, helping kind of confirm the timing of your drilling in the region later this year. Maybe more broadly, can you -- and obviously understanding it's still incredibly early stage, can you talk to any shifts in terms of regulatory government discussions and discussions around kind of permitting time lines? I know that's been, we'll call it, a -- not point of friction, but a bit of a bottleneck in terms of the pace of activity that you guys were looking to pursue in some of these regions. How has it been shifting? How has that been evolving through time? And has there been kind of an uptick even this past week?

Yes. I'll pass it back to Darcy to walk you through.

Yes. I think, Dennis, certainly, the messages that we're constantly trying to send out about the benefits of domestic production in Europe is maybe falling on more open ears all of a sudden. So that can only be good for us. You asked specifically about regulators sticking to time lines. I think we have seen and heard commitments, especially from the Dutch regulator about sticking to their own time lines and just kind of -- we have been quite successful lately in building up a nice pipeline of opportunities, both in the Netherlands and Germany. And just as a reminder, we drilled 2 wells in the Netherlands and Offenhausen in Q3 of last year. We discovered 16 Bcf of gas there at an F&D cost less than $1.50. And then we brought those wells on production in Q4, right? So it was a pretty quick cycle time. We brought Osterheide on as planned in 2025. As you mentioned, that continues to have strong production volumes and had record volumes for us in Q4. We're progressing well on Wisselshorst with gas plant installation and the pipeline tie-in. We're still on schedule to start up mid this year. That's again a significant discovery with. Our net share is 43 Bcf there. On plan to drill 2 additional wells in the Netherlands in 2026, plans to spud 2 more wells in Germany in early 2027. And I think probably one of the biggest differences, and you would have saw that in the Investor Day is the opportunities that we're drilling. They're more step-out exploration type opportunities. They're bigger. If we look at kind of the last 30 wells that we've drilled in Europe versus the next 30, they're kind of 2.5 to 3x the size of what we've drilled over what was a pretty successful decade of exploration drilling there with a 70% success rate. We'll continue to work with the regulators and the stakeholders to develop support for additional domestic gas production. We think it's a strong message. It has security of supply implications that I think people are starting to listen more and more to.

[Operator Instructions] Your next question comes from Josef Schachter with Schachter Energy Research.

Congratulations on Germany and Netherlands. I'm wondering about Ireland. Have you done any more work there? And is there much opportunity to maybe do some future drilling there? And then maybe if you can give us some idea of Croatia, if there's any further work that you're doing that might open up some opportunities in like '26 or '27 for growth in those areas.

Thanks, Josef. I'll just give the high level on Ireland and Darcy, please fill in the blanks. But quick answer is, we don't see any drilling activity in Ireland. Darcy just talked about, in particular, Germany, those prospects that are 30 Bcf, they're onshore. It's a bit about 50 an Mcf to drill those from a cap. So what that means, Josef, like when we look at it from a capital allocation, we really like Germany, and it just streams so well. But Ireland is a great asset, the team is optimizing. It's super steady and generates strong, strong free cash flow. But no plans internally to allocate capital to drilling in Ireland, just given the strong opportunities that we have in Germany. But Darcy, anything to add there?

Yes. I think, Josef, our focus, certainly in Ireland has been on the existing well stock that we have and making sure that, that plant is as efficient as possible, and we have the highest recoveries we can out of those wells that are currently drilled.

And then with our activity over the last couple of years here in the coring up. We are progressing the potential divestment of some of the assets in Croatia. I know we can't say a lot, but Lara, any color to add to Croatia or CEE?

Yes. I think -- I mean, we announced that we'll be exiting those areas. And so for Croatia and like in specific, there are nice drilling opportunities there. And we just decided, as Dion just said, we really like Germany. And so you have to make tough decisions around where you're going to focus your portfolio. So from a Croatia perspective, I think there are some lovely opportunities, but they're not opportunities for us, and that's why we're divesting and focusing elsewhere.

There are no further questions at this time. I will now turn the call over to Dion for closing remarks.

With that, thank you again for participating in our Q4 call. Enjoy the rest of your day.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.