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, a 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. The disposition of non-core assets in Saskatchewan and the United States means 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, enhance profitability in our Canadian portfolio. In Germany, during Q1, we brought online the first well of the deep gas exploration program, Osterheide, and progressed 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 two 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 three 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, 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 made by each team across the business. In Canada, due to the improved operational scale and 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 six 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 two 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 costs 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 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 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 provides long-term visibility for future production and cash flow. The before-tax net present value of our 2P reserves discounted at 10% using the three consultant average pricing as of January 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 three-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 four gross and net liquids-rich gas wells, which are scheduled for completion and start-up in Q2 2026. A 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 two 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 one 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 and the delay of the planned crude export lifting. We do budget for cyclone downtime each year, and fortunately, it's been more than five years since we've experienced a direct storm event. Again, thank you to our staff for their hard work and commitment to safety in the lead-up during and after the cyclone 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 serves 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 five-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 roadmap to 2030 as outlined in our recent Investor Day. Our 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.

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. 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. 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. With that, we'll see the higher production and lower capital. So we were running at about $2.70 per share of excess free cash flow at that time, which was based on that price deck. But maybe I'll pass it over to Lars if you want to tie that price deck to potential upside from where we are today.

Yes. No, it's a good observation, Menno, regarding the run-up here that we've seen recently. 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. We're showing FFO for 2026 around $950 million. That's a 40% increase in 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, my second question relates directly to what you were just describing, and it's a typical hedging inquiry. There is quite a bit of backwardation, and liquidity is limited the further out we go. Are you achieving any progress today? Are you looking to take advantage of that situation? It’s a troubling scenario, but are there opportunities to hedge further? Is there a possibility that you might 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 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 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. 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 three quick questions. First on the Deep Basin well outperformance. I'm curious, 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.

Thank you. This is really just a continuation of the positive results we shared during Investor Day, where we highlighted the strong IP30 rates from the second half of our 2025 drilling program. Those rates have continued to perform well. In our current three-rig program, we've successfully brought on an additional 14 wells, which have also exceeded our expectations. It's important to note that this well mix includes a diverse range of well types and production areas, highlighting the depth of our inventory. As mentioned, we are not solely focused on Tier 1 locations; we are also drilling proof-of-concept wells. This demonstrates our inventory depth and the dedication of our Deep Basin teams to achieve these impressive 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, based on the results to date, that is correct.

Yes. I mean, I think we've got 40 to 45 wells, Amir, for the program, and we're first quarter into it, but everything we're seeing in the first quarter is encouraging. 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. 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 you expect Australian volumes to ramp back up to previous production levels?

Thanks. I'll pass it to Darcy Kerwin, our VP International, to discuss the plan and provide additional insights on what occurred, 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. In December of last year, while we were performing inspection and maintenance activities on our export system, we had a small leak on one component of that system. Now, at the time, the system was not exporting. We were isolated for maintenance. 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 regulatory response in a situation like that. Later that same day, we received their approval to complete a planned loading after we formally responded to their issued notice. In parallel to all this, we had a tropical cyclone that had been building offshore Australia, and we did have a direct hit from a category three tropical cyclone on the weekend of February 7. That shut in both our production operations and our export systems, which delayed 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, February 27. A little bit more long-term, we had already planned and budgeted for the replacement of portions of this export system. We had completed engineering work and received bids in 2025. We've committed to fabrication starting this year and 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 February shutdown. 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. Going into Q2, we expect things to be back to normal. But at this point, we want to be conservative for Q1.

Okay. So by Q2, you should be fully ramped back up? By the end of Q2 for sure, around there?

That's our plan.

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

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

It was on both the international and North American side. There were some negative technical revisions on 1P and 2P. 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. Really, when we talk about the negative technical, this is a result of us high-grading our reserves book, primarily as a result of the M&A activity. When we think about it in Canada, the team in Canada under Randy has done a great job of high-grading locations, part of why we saw those great results in the Deep Basin. Now we've shifted our reserves book to reflect that. So the negative technicals are because we've replaced locations with ones that we see as having better profitability. When you look at the numbers, we've added four times 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. This is due to 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 we're 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 taken 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? 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 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. When we have something to talk to, we'll let you know. But I do think there are going to be some interesting opportunities, both in Canada and in Europe. You've seen us core up the portfolio. Vermilion has done some divestitures 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. I’d like to follow up on Amir's earlier question. When the better wells were being developed in the Deep Basin, did you implement any changes in the drilling or completion design that contributed to the improved results, or was it primarily due to the geology?

I'll provide a brief answer and let Randy expand if he wants. But I believe the key factor is the rock quality, Jeremy. Over the years, we've built our legacy land position, and the teams have effectively maximized that land base. They now have a lot of new, high-quality inventory. Combining the high-performing teams from Vermilion and Westbrick has led to many opportunities, including the ability to extend wells and drive results. Ultimately, the quality of the rock is what we’re observing. Randy, is there anything I missed?

Yes. I would add that the combination of our two land bases and the various deals we've completed, including swaps and Crown land sales, has increased our land availability. This allows us to drill in optimal locations, unlike before. As for drilling and completions, we are performing consistently, and the costs are aligning with our expectations. Ultimately, it comes down to geology and optimizing our 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, from your Investor Day, you highlighted a little about infrastructure and 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. 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. We expect that the production rates that we have seen as of late will continue flat 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 to stay flat.

Great. Does that also bode well 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. We hope to see the same results on Wisselshorst takeaway as we've seen in Osterheide.

Great. My second question shifts the focus to the Netherlands. It’s encouraging to see that you received the permits there, confirming the timing of your drilling in the region later this year. More broadly, can you discuss any changes in regulatory government discussions and permitting timelines? I understand it's still early stage, but this has been a bottleneck affecting the pace of activity you were aiming to pursue in some areas. How has this been evolving over time? Has there been any increase in activity 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 are maybe falling on more open ears all of a sudden. That can only be good for us. You asked specifically about regulators sticking to timelines. I think we have seen and heard commitments, especially from the Dutch regulator about sticking to their own timelines. We've been quite successful lately in building up a nice pipeline of opportunities, both in the Netherlands and Germany. Just as a reminder, we drilled two wells in the Netherlands and Offenhausen in Q3 of last year. We discovered 16 Bcf of gas there at an F&D cost of less than $1.50. 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 a significant discovery with our net share being 43 Bcf there, on plan to drill two additional wells in the Netherlands in 2026, plans to spud two more wells in Germany in early 2027. I think one of the biggest differences, as you saw 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 the last 30 wells we've drilled in Europe versus the next 30, they're kind of 2.5 to 3x the size of the prior wells we've drilled over a successful decade of exploration 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 that has security of supply implications that people are starting to listen more and more to.

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? Is there much opportunity to do some future drilling there? 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. The 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 about $50 an Mcf to drill those from a cap. So what that means, Josef, is that when we look at it from a capital allocation perspective, we really like Germany. It just streams so well. But Ireland is a great asset; the team is optimizing. It generates strong, strong free cash flow. But there are no internal plans 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 in Ireland has been on the existing well stock that we have and making sure that plant is as efficient as possible, ensuring the highest recoveries from those wells that are currently drilled.

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 mean, we announced that we'll be exiting those areas. So for Croatia, there are some nice drilling opportunities there, but we've decided, as Dion just said, we really like Germany. You have to make tough decisions around where you're going to focus your portfolio. From a Croatia perspective, it has some lovely opportunities, but they aren't 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.