Vermilion Energy Aktie

Good morning, ladies and gentlemen, and welcome to the Vermilion Q3 2026 Conference Call. [Operator Instructions] This call is being recorded on Wednesday, November 4, 2026. I would now like to turn the conference call over to Mr. 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 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 the advisory on forward-looking statements in our Q3 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.

We are delivering on our plan to structurally improve our excess free cash flow with operational momentum continuing to build as we progress the key milestones communicated during our Investor Day. The rate of change in profitability is being reflected in operational results and outlook with improvements to our capital efficiencies, base declines, and controllable cost structure. Our diversified portfolio is benefiting from elevated pricing for European gas, Canadian condensate, and dated Brent oil. The combination of delivering on production and cost targets while benefiting from higher prices has enabled accelerated debt reduction and increased shareholder returns.

This quarter was focused on the execution of planned maintenance activities, which were completed on schedule and without incident, as well as the continued integration of the recently acquired German assets. Planned maintenance work, like this quarter's turnaround in Ireland, demonstrates Vermilion's commitment to safety and operational excellence. Maintenance work complete and production restored, Vermilion expects European gas of approximately 100 million cubic feet per day in Q4. Looking beyond the quarter, Vermilion is also pleased to announce our 2027 budget headlined by E&D capital of $675 million to $725 million and associated production guidance of 122,000 to 126,000 BOE per day.

The 2027 program builds on the company's operational momentum with increased drilling activity across the international business, a 3-rig program in the Deep Basin, and continued advancement of the Mica Montney development. This production guidance represents approximately 2% absolute and 5% per share growth from 2026. Important to note, the 2027 budget includes approximately $150 million of capital that is forecast to add production starting in 2028. This project represents an important step in our 5-year plan. Our strategic infrastructure investment in Germany includes a debottlenecking pipeline to increase production from our Wisselshorst discovery well, as deliverability of this well far exceeded our expectations.

This project is planned to start construction in early 2027 and is expected to increase gross capacity to approximately 17 million cubic feet per day by the end of 2027. We're also investing in Australia, where Wandoo crude, which sells for a premium to Brent pricing, offers strong returns. We will execute a 2-well campaign utilizing a rig that is part of an industry multi-well program in order to reduce our rig mobilization costs. Most cost-efficient timing of the rig results in production from the Australia drilling program commencing in early 2028.

As these projects are completed, Vermilion expects 2028 E&D capital to return towards 2026 levels in the low $600 million range. Finally, the 2027 budget is consistent with our sustaining or stay-flat capital estimate of $565 million. In 2027, we are forecast to deliver production growth even though only $550 million of the $700 million of capital has volumes in 2027. We remain confident in our ability to meet or exceed the multi-well production and capital objectives established at our Investor Day. Our plan factored in the strategic international capital program in 2027 to increase exposure to European gas and Brent oil. At current commodity prices, our 2026 excess free cash flow forecast is over 60% higher than our initial forecast for the year.

As we look to 2027, our excess free cash flow forecast will be over 20% higher than 2026, even with the higher capital program in 2027. Our excess free cash flow estimate for the 5-year period has increased to $1.9 billion. The estimate factors in the 2026 operational outperformance and price, gives the 2027 budget strip price, and reverts back to the Investor Day conservative price assumptions for 2028 to 2030. That's an increase of $200 million 1 year into our 5-year plan. With the strength in our underlying business, we also announced our plan to increase the 2027 base dividend by 4% to $0.56 per share annually.

This represents the sixth consecutive year of dividend increases, aligning with our commitment to sustainable, ratable dividend growth. Vermilion's dividend payout remains among the lowest in the Canadian E&P sector at sub-10% of our fund flows, offering capacity for years of future increases. I will now pass it to Lars to discuss the quarter and add some additional detail on the 2027 budget.

Thank you, Dion. In the third quarter, Vermilion generated fund flows from operations of $237 million on E&D capital expenditures of $146 million, resulting in free cash flow of over $90 million. This cash flow supported increased shareholder returns and further debt reduction in the quarter. Following the increase in our return of capital target to 40% to 60% of EFCF announced with Q2 results, we paid $21 million in dividends and repurchased $20 million of shares during the quarter, twice the value repurchased through the first half of the year. Through the first 9 months of 2026, Vermilion has returned $92 million to shareholders, while reducing net debt by nearly $180 million.

This represents $1.76 per basic share of combined debt reduction and shareholder returns year-to-date, which we expect will increase with a strong financial outlook for Q4. During the quarter, we continued to advance key operational initiatives across our international portfolio. In Germany, we closed the previously announced acquisition of producing assets and brought the Wisselshorst well on production in July. Together, production from Wisselshorst and the acquired assets position our German business for production of approximately 7,500 BOE per day in the fourth quarter, which is a 25% increase compared to Q1 of this year.

Overall, European gas production in the quarter was impacted by planned turnaround activity in Ireland and non-operated downtime in Germany, which temporarily reduced production to 81 million cubic feet per day. All of the required work was completed safely and on schedule, and production has been fully restored, positioning us for fourth quarter European gas production of approximately 100 million cubic feet per day. Subsequent to the quarter, we spudded a well in the Netherlands, with first production expected in the first half of 2027.

In Canada, by reallocating capital within the portfolio, we were able to add 5 net wells in 2026, while managing to the midpoint of our corporate E&D capital guidance. Across our Canadian business, unit operating expenses are down approximately 10% year-over-year, driven by realized synergies and our continued focus on operational excellence. In the Deep Basin, we had multiple wells rank amongst the most prolific in Alberta during the quarter, including one well that produced 12.6 million cubic feet per day of natural gas and over 400 barrels per day of condensate in the month of August.

This well was the second-highest producing new gas well in the province that month, and the outsized condensate production drove exceptional well economics. We also set a new industry benchmark by drilling an Upper Mannville well to nearly 7,800 meters, representing the longest Upper Mannville well drilled by any operator. Deep Basin production was temporarily lower in the quarter due to planned third-party maintenance and the timing of drilling activity. We also elected to defer several new well startups and restrict gas production to align with expected higher pricing later in Q4.

In the Montney, we brought a 4-well pad on production in Alberta, piloting a new completion approach to reduce sand and water recovery. Subsequent to the quarter, we established a new drilling pace benchmark on a pad that will be completed and brought online in the coming months. Vermilion remains focused on translating these operating improvements into repeatable reductions to our $8.2 million per well D&C cost. The wells brought on production this quarter have been impacted by third-party downtime that has extended into the fourth quarter, but have otherwise produced in line with expectations when capacity has been available.

Looking forward, we expect production to average 121,000 BOE per day in the fourth quarter, which will result in full year 2026 production of 122,400 BOE per day on E&D capital expenditures of $620 million. Annual production is above the original midpoint of guidance despite unplanned Australia downtime and shut-ins and deferrals of Canadian gas wells to optimize profitability. We expect to see production growing through Q4 to align with typically higher pricing. As Dion noted, we released our 2027 budget this morning with E&D capital of $675 million to $725 million, supporting production guidance of 122,000 to 126,000 BOE per day.

Our Canadian investment is broadly unchanged from 2026. The increase in our '27 budget is concentrated in European gas and Brent oil international projects that support production beyond 2027. In our international operations, we plan to invest approximately $315 million in 2027, a roughly 50% increase compared to our '26 budget. This capital will be focused on advancing high-value European natural gas opportunities as well as drilling in Australia. In Germany, we plan to drill 2 follow-up wells at Wisselshorst with spud planned for the first half of the year. We'll drill these 2 wells back-to-back using the same rig, and we expect cost savings of approximately 20%, along with a 30% improvement in cycle time compared to previous drilling programs.

We will also continue development of key infrastructure, including a connection to the broader gas distribution network to support higher production from the discovery at Wisselshorst. In the Netherlands, we plan to drill 2 wells targeting larger structures than those pursued in recent drilling programs. And in Australia, we plan to commence a 2-well drilling program in the second half of 2027, aligning with a broader industry drilling program, which will help reduce mobilization and demobilization costs. Based on the currently planned timing of rig availability, we expect drilling to take place late in the year with production to come online in early 2028.

We'll also continue to fund economic workover and optimization projects across the international portfolio. We expect European gas production in 2027 to be in line with 2026 as natural declines at Corrib are offset primarily by year-over-year growth in Germany. With a successful 2027 Wisselshorst drilling program, we expect European gas production to increase by mid-2028 as production from new discoveries is brought online and the debottlenecking pipeline from the Wisselshorst discovery well is completed. In Canada, we plan to invest $385 million in our liquids-rich gas business. In the Deep Basin, we will target high-return wells across our asset base with a focus on condensate-rich prospects to capture strong pricing.

We expect minimal infrastructure requirements with drill capital primarily directed to proven developments while continuing with strategic investments to further strengthen our depth of inventory. In the Montney, we are allocating capital to drilling activity and expanding owned infrastructure while growing production 10% year-over-year, all within Mica's cash flows. Finally, we noted in the budget release the revised timing of third-party gas processing infrastructure in Northeast British Columbia, which is expected to shift our 28,000 BOE per day Montney target production rate to early 2029 from mid-2028.

In the interim, we are redirecting capital to high-return Deep Basin locations that use existing infrastructure. Exercising the flexibility we have within our portfolio keeps us on track for the production growth and excess free cash flow commitments outlined at our 2025 Investor Day.

This is a clear demonstration of the strength of Vermilion's diversified approach that offers enhanced optionality for capital allocation. Once the Montney reaches its target production rate, which requires $45 million of infrastructure and 28 wells to drill between 2027 and 2028, we expect annual drilling to moderate to approximately 8 wells to maintain production with no material infrastructure requirements going forward. I will now pass it back to Dion.

Thank you, Lars. In summary, Vermilion delivered another strong quarter and made significant progress executing our 5-year plan. The 2027 budget builds on that momentum and sets the stage for growth. We're making the investments that will structurally improve our business with improved capital efficiencies, lower base declines, and lower unit costs. Improving business fundamentals in combination with higher production is forecast to deliver per share excess free cash flow growth. Following the close of the largest cash acquisition in the company's history, Vermilion has reduced net debt by approximately $900 million while growing production per share by 50%.

Today, our outlook is even stronger with fourth quarter fund flows forecast to be significantly higher than Q3, supported by higher European gas and overall liquids volumes as well as elevated European gas prices. Looking ahead, European gas fundamentals remain constructive with inventories entering the winter season significantly below historical averages and Europe increasingly reliant on LNG imports to balance the market. These dynamics are expected to support European gas prices through 2027.

With the recent run-up in prices, the current TTF strip for the balance of 2026 is in excess of CAD 40 per MMBtu and in excess of $30 per MMBtu for the full year of 2027. Building on our decades of expertise and extensive land position, we have allocated more capital to Europe to ensure we provide responsibly produced secure energy for the countries that we operate in. While commodity prices will fluctuate, our focus remains on the factors we can control. With operational tailwinds and commodity price support, the company is very well positioned to continue generating sustainable free cash flow and shareholder value. With that, we'll now open the line for questions.

[Operator Instructions] And your first question comes from Amir Arif from ATB.

On a good quarter. A few quick asset questions for you here. Just starting with Germany, the next wells that you are drilling, they seem to be in the thicker part of the discovery. Are you expecting better production at all out of these 2 wells? And then I just wanted to confirm the timing. I know that you've got the debottleneck project ongoing. I think that's what allows for production to grow in mid-'28. So, I'm just wondering when the production adds from the 2 wells being drilled next year will come on.

Great. Thanks, Amir. I'll pass it over to Darcy to just walk you through that. But the summary level would be the pipeline, the Wisselshorst pipeline. That's the one I noted on the call, will kick off construction in early '27 and be on production late '27. And then the 2 Wisselshorst wells will be on by mid-2028. But Darcy, do you want to walk us through what you think are those next prospects and any other details?

Yes. Thanks, Amir, for the question. I'll kind of, step back and maybe give a bit of a broader view of the Germany Wisselshorst area. Kind of, in the immediate term on a gross basis, we expect kind of, 3 million to 5 million cubic feet a day from that first Wisselshorst discovery well. That's certainly not indicative of the capabilities of the well, but really the current capacity in the local network. So, the first step of, kind of, getting past that restriction is we will build a new 12-inch sales pipeline for this initial well. We're well along here. We've ordered pipe.

We've ordered long lead items. We've recently selected the construction contractor that we'll use. So, we do plan to break ground on that project in Q1 '27. And as Dion said, we expect startup of this pipeline late in 2027. So, that increases the takeaway capacity for the original Wisselshorst well to, kind of, that 15 million to 17 million cubic feet a day, which matches the on-site processing facility there. If I step away from Wisselshorst just for a second, I just wanted to provide a production update on the deep gas well that we brought on at Osterheide, a well that we had originally forecast with restricted rates when we drilled it. This well has produced a little over 8.5 million cubic feet per day since it started up.

And our production in August recently here was over 13 million cubic feet a day. So, that's been the highest month of production since we started up the well in 2025, allowing us certainly to capitalize on the stronger-than-expected local demand in the network there and really capitalize on that high gas price environment. It's worth pointing out that this well since it started up, has generated over $65 million of free cash flow. And when I compare the Osterheide well with the Wisselshorst discovery well, that Wisselshorst well is 2.5x the size of this Osterheide well.

So, that initial Wisselshorst well will be quite impactful once these sales restrictions have been removed with the pipeline. If I go back to the Wisselshorst area, focusing on the new wells, we are planning 2 follow-up wells on that same exploration license where we made the discovery at Wisselshorst Z1a. Lease construction is going to start right away here in November. And then we expect the rig move is scheduled for later in Q1. We would expect those wells to be drilled and into well testing early Q4 of next year, and then that puts us on schedule for first gas from those 2 wells mid-2028. From a production point of view, these next 2 wells won't have that same restriction as Z1a had.

They'll both tie into the higher capacity sales network in the area rather than the, kind of, local distribution network that we use for Z1a. We would expect production from these 2 wells starting at '28 at a rate of about 15 million to 17 million cubic feet again.

Would that be per well or is that combined, sorry?

That's combined from those two wells, limited by the gas processing installation on that particular site.

Surface. Okay. I appreciate that color. Just moving over to the Netherlands, the 2 wells you're going to drill there. I know you mentioned you're chasing larger targets. Will these carry a higher exploration risk? Or are they more development-type wells similar to what you used to drill in the past?

Thanks, Amir. I'll pass it back to Darcy. Sorry, just to close out the German for a lot of good color there. The only thing I would add to that is -- and maybe we've talked about this before, but that Wisselshorst well, the one that Darcy mentioned 2.5x the Osterheide well, that's over 60 Bs of gas recoverable. And when we look at the Z2 and Z3, and maybe that's where you're going with the thickness, we do put those in our plan as risk wells. And so that means we're forecasting results that are less than the discovery well, even though we're about 1,000 meters or a kilometer away from the first well.

So, anyway, potentially some upside there. You've got to drill the wells, of course, but sure it's nice to be drilling those wells offsetting a really large discovery well. With that, some good things happened in the Netherlands. And Darcy, back to you.

Yes. So, Amir, in the Netherlands, as we said, we're currently drilling a well here with 2 more wells planned in 2027. You correctly pointed out that those wells are potentially larger than some of the wells we've been drilling recently in the Netherlands. I wouldn't necessarily read through to that, that they are higher risk opportunities. They are opportunities where we're stepping out a little bit further from a surface point of view from our existing areas, and we had, kind of, limited ourselves from a permitting point of view to drilling more wells in the heart of our operations.

We're still -- the wells we're drilling next year are still off existing pads, but they do allow us to reach what we think are larger prospects than we've seen in the last couple of years. But I think similar risk levels than the drilling you've seen from us in the Netherlands in the last 5 years, certainly.

Thanks, Darcy. And I mean, to summarize that, Amir, what we're really excited about is we've got the well we drilled in the Netherlands and 2 more next year and then the 2 wells that Darcy walked through at Wisselshorst. So, we've got a 5-well program over the next nominally 4 quarters. And if you think about the EURs on those wells, they're 20 to 40 Bs. And so with 5 wells and some larger structures, we're pretty excited about converging on the budget results, if not better, given the quality of the target. So, we look forward to reporting more as we get into the second half of next year.

Yes. Should be good drilling coming up. And then just shifting over to Australia, the 2 wells you're going to drill in late '27 with production adds in '28, will those offset production declines? Or is it enough, or 2 wells enough to sort of get that field-level production to grow into '28?

Got it. So, are you referring to Australia?

Australia, yes.

Yes, a quick answer there, and Darcy, jump in. But yes, as a reminder, we drill in Australia every 2 to 4 years. With commodity prices the way they are, Brent in particular and the premium you get, it's quite attractive. We had foreshadowed this during the Investor Day back in December that 2027 was likely to be a higher capital year. And so adding those Australia drills gets you from the low $600s to the $700 million midpoint of our guidance.

To your point, they're high-rate wells. And so these wells are typically 1,000 barrels. We do choke them and then we're able to hold the platform flat for 2 to 4 years depending on the restrictions and the quality of the wells. It's infill drilling. Again, we drilled lots of wells in that platform and quite excited to have a hot rig that's going to be in the area to execute the program as well. But Darcy, anything I missed there on those particular wells?

Yes. I think those 2 particular wells, we look at 2028, you certainly will see some growth over the rates that we've seen in 2026 and 2027. Part certainly as a result of those 2 wells, but also getting back to normal operations at Wandoo. As you know, we've been impacted by 2 cyclones this year that took us offline for quite some time. So, I think you should expect to see some pretty good growth in Australia in '28 versus '26.

I appreciate the color, but just to put some numbers around it, are we over 4,000 barrels a day at the field level even if you choked back the wells? Would that be fair in '28?

Yes, those are fair numbers. Like we're going to exit the year at around 3,000 in Australia to Darcy's point, with some of the maintenance work behind us planned through the year and the wells ramping up. So, without those wells, your run rate is over 3,000, you'll drill the wells and then we will be 4,000 to 5,000, I think is how you would think about it, Amir. And again, some of that with pricing the way it is and the premium on that crude. We've got the flexibility with volumes being piped there to be 5,000, and that will be a game day decision.

Okay. Sounds good. One final question. Just in the Montney, I know you talked about a new completion approach to reduce the sand and water. Can you just provide a little more color? Are you changing the completion approach? Or is it more in terms of the flowback timing and stuff?

Yes, just -- I'll pass it to Randy here. Kind of, the read-through is the team has done a great job, as you know, taking costs down by 25% and we thought they are seeing the flow through some examples of things the teams are doing to continue to find ways to take those costs down. But Randy, maybe any more color on those pilots and where you think it's going?

Yes. So, thanks. So, I think when we looked at, we kind of, trialed the soak time period here where we let the well soak before bringing them on flowback after we frac. We certainly did see less frac sand recovery and less load fluid water recovery. So, I think from our standpoint, we need to do a bit more analysis on it. But I think to Dion's point, we're continually trialing different D&C techniques and completion techniques and also operation techniques as we sort of kind of, level this thing out to get it up to peak production and understand that. So, we see there's savings for sure in both the capital side and our OPEX side with this trial, and we just need to analyze a little bit more to understand if this is the new go-forward plan.

And maybe super quick on the drilling pace. I know a couple of records there, but just...

We're very excited with kind of, the work we've done here that Lars noted in there that we had a pacesetter well here in our last drilling program. So, we'll continue with that. We hopefully want to be able to follow that up with the next 2 trials we're doing in the '27 program. But with that, I think where we do see -- we quote $8.2 million D&C, we do have line of sight to get this down to $8 million, and that's really what we're striving towards and then obviously never stopping beyond that.

And there are no further questions at this time. I will turn the call back over to Mr. Dion Hatcher.

Good. All right. Well, with that, I want to thank everyone for participating in the call. Enjoy the rest of your day.

Ladies and gentlemen, this does conclude your conference call for today. We thank you very much for your participation, and you may now disconnect. Have a great day.

Good morning, ladies and gentlemen, and welcome to the Vermilion Q2 2026 Conference Call. [Operator Instructions] This call is being recorded on July 30, 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 and HSE; Brandon McCue, Vice President, North America; Lara Conrad, Vice President, Business Development; and Travis Thorgeirson, Director of Investor Relations and Corporate Planning.

Please refer to the advisory on forward-looking statements in our Q2 release. It describes forward-looking information, non-GAAP measures and oil and gas terms used today and outlines the risk factors and assumptions relevant to this discussion.

Second quarter of 2026 was another strong quarter for Vermilion with production averaging [ 125,800 ] BOEs per day, exceeding the top end of our guidance range. Positive results across our portfolio continue to support performance that is trending ahead of our 5-year plan that we communicated during our Investor Day in December of 2025. With this current performance in mind and with significant progress in debt reduction, we have increased our return of capital target in a range of 40% to 60% of excess free cash flow, up from 40% previously.

Production performance is driven by record output at Mica Montney, continued strong execution in the Deep Basin and the state's restart of production in Australia following the back-to-back cyclones earlier this year. Based on operational performance year-to-date, we have increased our full year production guidance now 121,000 to 123,000 BOEs per day, while maintaining our E&D capital budget range of $600 million to $630 million. Our E&D capital expenditures and operating expenses are weighted towards the second half of the year, and we expect full year costs to be within the stated guidance ranges for these items.

In the Montney, strong performance from the most recent BC six-well pad at 835 drove quarterly production at Mica of 18,000 BOEs per day. The pad achieved an IP90 of more than 950 BOEs per day per well comprised of 3 million a day of natural gas and 470 barrels per day of oil and NGLs with DCET costs reduced to $8.2 million per well. These results continue to support the quality, the repeatability and the improving capital efficiency of our Montney inventory.

In the Deep Basin, activity was moderated through spring breakup. The program continues to outperform budget expectations and has been the primary driver of corporate production outperformance through the first half of the year. In Europe, following the quarter end, we achieved another important milestone in our German deep gas exploration program with the Wisselshorst well being brought on to production in July. This represents first production from the largest discovery Vermilion made in Europe to date.

I would like to take this opportunity to thank our teams for their commitment to safe operations during the many steps required to bring this well in production. We are excited about the next steps, debottlenecking the production with a new sales pipeline as well as drilling the next 2 wells on this license in 2027.

Elsewhere, the Osterheide well continues to perform in line with prior quarter rates with cumulative free cash flow of $43 million since startup. We expect production growth in Germany to be driven by our deep gas exploration program, reaching 10,000 BOEs per day by 2030 and given the significant resource continuing to grow into the next decade.

Also in Germany, we closed the previously announced bolt-on acquisition following quarter end. The transaction adds approximately 1,000 BOEs per day of production weighted 85% to natural gas as well as ownership of key infrastructure around the Osterheide well. Adding production from resource and these acquired assets is particularly impactful with the recent rally in European gas prices, currently over $25 per MMBtu through winter 2026.

European storage levels are well below average for this time of year, and the current pace of refilling is not sufficient to reach the 80% target for winter. We plan to increase our domestic gas production through debottlenecking infrastructure as well as exploration and development across our significant land base in both Germany and the Netherlands. Growing prospect list of high-return capital-efficient targets, Vermilion is well positioned to grow our production and free cash flow by providing our communities with a reliable source of energy.

In Australia, production operations at Wandoo safely resumed following repair work completed during the quarter. Our next export is planned for the third quarter, and we expect to return to more regular exports thereafter. Our 5-year plan continues to progress well. Operational execution across the portfolio, combined with the first production from Wisselshorst and continued success in the Deep Basin and Montney reinforces our confidence in the ability to generate growing free cash flow.

Before I pass to Lars to further discuss these results, I want to take a moment to acknowledge the challenges faced by some of our employees, contractors and their families that have been impacted by the fires in Southern France. Our thoughts are with you, and we hope the situation continues to improve in the upcoming days.

Thank you, Dion. In the second quarter, Vermilion generated fund flows from operations of $231 million on E&D capital expenditures of $110 million, resulting in free cash flow of over $120 million. Capital allocation remains focused on disciplined investment, continued balance sheet improvement and shareholder returns.

During the quarter, net debt was reduced by approximately $70 million to $1.22 billion. As of June 30, 2026, net debt to trailing 4-quarter fund flows from operations was 1.3x. Over the past 5 quarters, Vermilion has reduced debt by approximately $840 million, accelerating progress toward our $1 billion net debt target and significantly strengthening the balance sheet. This continued deleveraging has also reduced structural financing costs with unit interest expense declining approximately 35% from the prior year. And we are on track to reduce full year interest expense by $30 million from 2025.

Reflecting this progress as well as improved visibility to future cash flow and confidence in the sustainability of the business, we have enhanced our return of capital framework. Vermilion now intends to return 40% to 60% of excess free cash flow to shareholders compared to the previous target of 40%. This framework continues to be supported by our base dividend and ongoing share repurchase program.

Subsequent to the quarter, we announced the renewal of our NCIB out to July 2027. During the quarter, we returned approximately $26 million to shareholders through dividends of $21 million and $5 million of share repurchases. With the increased return of capital target, we expect the pace of share buybacks to increase.

Turning to commodity risk management. Vermilion recognized a gain on hedging during the quarter as a realized loss of $57 million was more than offset by unrealized mark-to-market gains of $174 million on our hedge portfolio. These unrealized gains reflect changes in forward commodity prices relative to our hedge position at March 31, 2026. Our percentage of production hedged will decrease in the second half of 2026 relative to the second quarter levels, which increases our exposure to current elevated commodity prices.

Operationally, Canadian production averaged 99,605 BOE per day during the quarter. which included record production from Mica. We continue to actively manage AECO exposure and prioritize profitability over production during periods of weaker natural gas pricing. We maintained strong well performance and continued to shift Deep Basin activity toward liquids-rich opportunities in the Rock Creek, Niton and Ellerslie. Several of our wells in Canada in both the Deep Basin and Montney ranked among the most prolific wells brought online during the quarter.

In Europe, in addition to our work getting Wisselshorst online and preparing for follow-up drilling, our activity this quarter focused on workovers, maintenance programs and preparation for drilling activities in the Netherlands during the second half of 2026. These activities, together with production from Wisselshorst and Osterheide, support the continued development of our European gas platform.

Looking ahead, we expect third quarter production to average between 116,000 and 118,000 BOE per day, reflecting planned maintenance activities in Ireland, Germany and Canada. This is consistent with our assumptions at the time of the budget release. We expect Q4 production to be approximately 122,000 BOE per day with European gas production back in line with first half levels.

For the full year, production guidance has been increased to 121,000 to 123,000 BOE per day, while E&D capital expenditure guidance remains unchanged at $600 million to $630 million. Both operating expenses and capital expenditures are expected to be weighted toward the second half of the year, as Dion previously noted.

The increased production guidance reflects our strong operational performance year-to-date, which has more than offset the impact of back-to-back cyclones in Australia earlier this year. We are confident in the ability of the company to continue to deliver on our Investor Day outlook.

I will now pass it back to Dion.

Thank you, Lars. In summary, Vermilion delivered another strong quarter and made significant progress executing our 5-year plan. Production exceeded the top end of our guidance range. Free cash flow totaled $122 million and net debt was reduced by another $70 million. These results reflect the strength of our asset base, quality of our teams and our disciplined approach to capital allocation. Vermilion continues to focus on what we can control. As a result, we're seeing structural improvements in the business with stronger capital efficiency, improving well performance, lower controllable costs, which improves our full cycle margins. Operationally, record production at Mica, continued Deep Basin performance and the successful restart of Wandoo supported strong results across the portfolio. In Europe, we achieved first production from Wisselshorst, marking another important milestone for executing our long-term European gas growth strategy.

Financially, our balance sheet continues to strengthen with approximately $840 million of debt reduction achieved over the past 5 quarters. As leverage declines and visibility to growing free cash flow continues to improve, we are increasing our shareholder return framework to target 40% to 60% of excess free cash flow.

Looking forward, operational momentum remains strong. production performance through the first half of '26 has allowed us to increase annual guidance without increasing capital spending. Supported by our repositioned portfolio, growing European gas exposure, a strengthening balance sheet and a disciplined capital allocation framework, we believe Vermilion is well positioned to continue generating sustainable free cash flow and shareholder value.

With that, we will now open the line for questions.

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

I'll start with a question on the higher level operational setup through the middle of next year. You did touch on this to some degree in your opening remarks. I understand that you can't provide guidance for 2027, but beyond turnarounds this quarter, is there any significant downtime or other considerations we should be aware of between now and the middle of next year? And then what could the -- and I think you did guide Q4, but what could the exit rate look like for this year?

Menno, thanks for that. A couple of comments. To your point, I think the turnarounds that we're planning for and executing here in this quarter, I mean, Ireland is a great example. That is a 5-year cycle on that turnaround. And so that would be very unique, but something we plan for on that key asset.

Looking out from now into mid-2027, yes, the answer is no. We don't see any key downtime. Yes. So quick answer is no. The set up, we're quite excited. So if you look at the exit rate, Lars referenced this, we're back to [ 1.2 ] or better. If you reference back to European gas, what does that mean for our business? The first half, we were 95 million to 100 million a day. Again, hopefully, we're on the higher end of that range as we exit this year. So we'll get these turnarounds behind us and I think have a strong Q4, and that really is a good setup going into 2027.

Terrific. And then second question is on the Germany drilling program. Can you maybe just remind us of how you manage the risk on these larger wells, including the 2 that will get drilled next year. I understand there's the farm-down component, but maybe you could just remind us of the broader risk mitigation strategy and maybe also the math on the out-of-pocket cost of Vermilion in the event of a dry hole because if I recall, it's significantly lower than the actual well cost.

Thanks, Menno. Yes, a lot of good questions there. So first of all, I think it comes down to, I think the quality of the team and the G&G and the science and the decades that we have, multiple decades of working on these structures in Europe. This particular formation of Rotliegend, again, it's something we've been drilling for decades.

Second, I would say we're in a proven fairway. When you look at some of those maps where we're drilling these structures, it is not uncommon. There's multiple, let's call it, a handful of structures that have cumulatively produced over Tcf. So if you're going to find big oil -- big gas, start drilling in areas where there's been big gas found. So we're excited about the setup.

As to how we look at the risk reward, let's call it. First, economically, if you think about the cost to drill these wells at [ CAD 50 million ], our target rate is 30 Bcf recoverable. For of course, is twice that. But if you spend 50 million in the success case and that gets you the drill, the test, the on-lease gas plant, the pipeline for $50 million and you get 30 Bcf of gas, that's $1.15 Mcf. If you assume gas prices are $13 and of course, we more than double that now, but at $13, NPV per well is $60 million, right? And you can see with Oster, it's been on for a year and it's [ cumed ] over $40 million of free cash flow and the well hasn't started to decline yet.

So the success case, I think, is pretty hopefully straightforward. The failure case is we drill the well, we don't like what we see, we get off of the well. It's less than $15 million, okay? So the $50 million is the all-in success case. The dry oil case, let's call it, is sub $15, so 1-5.

The final point is commercially, when we drilled this horse, we knew that it was a very large structure, but also we view that one as a little more higher risk, but it was big. And so commercially, we did use a farm-in to provide -- promote. And with that carry, it effectively meant the after-tax [indiscernible] cost was 0, right, or less than 0 maybe.

So that's another quiver in our strategy here is we can use farm-ins. They're good prospects. We're going to drill these prospects. But if someone wants to come in and leverage some of the great work we've done, commercially, we can further reduce our risk. So hopefully, that gives you right from, hey, we're looking for big targets in a period where -- in the area where big gas has been found. We got a team that's been doing this for decades. We've done all the technology and reprocess seismic and then the failure case is sub-15 and then commercially, we can further mitigate that failure case with a promote or carry.

Your next question comes from Greg Pardy with RBC Capital Markets.

I wanted to stay just maybe on the back of Menno's question. Maybe just to stay with Germany for a minute. And just in terms of the next 2 exploration wells that you have planned for early next year, I'm just wondering how far away those might be from Wisselshorst? And then in addition to that, maybe just any potential debottlenecking opportunities that you would have in that area, maybe just to increase rates and what's required to accomplish that?

Thanks, Greg, for those questions. I'm going to pass it over to Darcy and just talk about the location of the next 2 Wisselshorst wells and some of the steps as noted for the debottlenecking of the gas.

Yes. Great. Thanks for that. To answer your first question, those next 2 wells are located on a common pad. So they'll be drilled together on one pad. That location is kind of between 1 and 2 kilometers away from the original Wisselshorst discovery well as crow flies. In terms of debottlenecking the first Wisselshorst well that we brought online, we are in the process of permitting and acquiring land to build a new sales pipeline for that well. We expect that, that pipeline be online, ready for service towards the end of next year.

And then we do for the new -- the next 2 new wells have a plan for an initial gas plant on that one site to capture their production. We have the opportunity to twin that gas plant on that site if we have strong results there. And then that sales pipeline that we're building for Wisselshorst 1 will also be the sales point for the next 2 wells of Wisselshorst. So lots of opportunity to debottleneck that area kind of next year with the sales pipeline and then hopefully, a new gas plant for those next 2 wells in a success case.

Thanks, Darcy. Yes. So summarize there, that sales line, it's a 12-inch piece of pipe. I think all the materials ordered. We're going to plan to start construction here early next year. And as Darcy noted, that will allow us to open that well up and get it up to that full 16 million, 17 million a day design rate. And further on that is the twinning of the infrastructure that Darcy mentioned. In fact, you're able to double to go from 17 million to 34 million a day with the amount of gas we've got behind pipe. But first step, Greg, to your point is, as Darcy mentioned, is getting that 12-inch pipe in the ground, and we're well on our route to do that.

Okay. Terrific. Yes. And maybe just staying with Europe and maybe just moving into the Netherlands. In the past, you probably drilled potentially smaller prospects. Now you're -- what I understand is you're drilling perhaps fewer but bigger prospects. Could you -- is that -- am I thinking about that the right way? And just any color around that would be great.

Yes. I'll pass it back to Darcy, but I think just unwind the clock a little. In the Investor Day, Geoff MacDonald would have talked a lot about this and the plot that we -- that he was emphasizing is these targets are 2.5 to 3x bigger than what we were targeting before. But Darcy, do you want to build on that?

Yes, sure. Thank you. Yes. In the Netherlands, I think if we look back kind of the last 10 years, as you said, the projects we were drilling were getting smaller. That was really driven by an effort from the permitting side to stay drilling on existing leases in existing areas. And we've been continuously pursuing drilling locations outside of those areas to access some of these bigger pools and the drilling that we have planned for later this year as well as next year kind of is on the back of that where we are stepping out a little bit further from our existing operations and able to access bigger pools again in that area.

So permitting for wells, the wells that we have planned this year kind of firmly in hand, we're ready to go once we have the rig available towards the end of September, then wells for '27 and '28 are in the midst of permitting have everything kind of in hand to drill wells in '27 and onward to '28 in these bigger pools.

The team has done great work again on the permitting, but also the technical side, building on Darcy's comments to bring these larger structures forward. We're quite excited to allocate capital there.

[Operator Instructions] Your next question comes from Dennis Fong with CIBC.

Sorry to keep focusing on Germany here. Obviously, a lot of exciting things there. I was hoping to dig into the recent concessions that you've been awarded and how specifically you're thinking about balancing, we'll call it, step-outs or follow-up drilling like things that you're doing with the [indiscernible] license versus, we'll call it, little E exploration work to, again, further build out the depth of inventory that you have out in Germany, especially with the winning of these new concessions.

Thanks for that, Dennis. I can give you a good summary there. And the team has done a great job with the land we currently have, which is obviously a big number over 1 million net acres, identifying those 9 structures, and we see up to 30 wells on those structures, and we're excited to now develop Wisselshorst, but also test some of those additional 6 structures in the upcoming years.

To build on that, deals like the one we closed, but also the new concessions, another 0.5 million net acres. The team will do, let's call it, more of that study, G&G work, relatively low cost, pulling a lot of data, but we'll spend the next 2, 3 years really defining the prospectivity, maturing prospectivity, then you would look at the next couple of years after that to think about drill commitments and those kind of things.

So really, we see this with the defined inventory that we've got, let's call it, a decade at a risk base. Things like this new concession is really extending that runway even further. And I think as we're having this conversation a couple of years from now, Dennis, we'll be able to start to point to things on the map. Right now, it's a lot of land in the fairway that we like. We're going to spend a year or 2 just doing the G&G work to mature what we expect to be some prospects on that. But it's just really built on that decade that we've had in front of us. So you're going to see us test some new structures in the upcoming years as well as develop these.

Okay. Great. I appreciate that color and context there, Dion. My next question focuses a little bit more on the balance sheet and allocation of free cash allocation to shareholders. So obviously, you've continued to delever and this is kind of a nice bump up in terms of directing 40% to 60% of excess free cash towards shareholder returns. Can you talk towards kind of what kind of drives you to maybe a 40% versus a 60%? Is that more commodity or kind of value that you see in the shares? And then how do you think about the confidence that you build in terms of allocating more and more free cash to shareholders, especially just given as you've improved, obviously, depth of inventory across the asset base and then continue to execute across the various assets, whether it be in Canada or in Europe or Australia?

Lars, can't wait to answer that question. I'm going to pass it over to him.

Great. Yes. No, thanks, Dennis. And I'll just try to give a little bit of context in terms of how we arrived at the decision to move to 40% to 60%. So maybe 2 key data points that we look at. Obviously, the first one is just the status of the business today in terms of where we've taken the balance sheet, the quality of inventory. But maybe what I'll spend a bit more time on is just the rate of change of how we've gotten here. And so I made the comment in my remarks, we've reduced net debt by $840 million over the past 15 months. So a lot of progress there made in a short period of time. And you think back to 15 months as well, we have just closed the Westbrick acquisition, consolidated into a 1.2 million acre Deep Basin position. We still had some infrastructure spend in the Montney to execute on some key pads to deliver on as well. And we were still trying to quantify what we had in Germany.

And so you fast forward 15 months to the end of the second quarter here. And I think a lot of boxes have been checked. And in a very short period of time, and so those are the type of things that we want to look at. It's sort of structurally, are we executing on the plan within the business. As we look back, we said, you know what, we are more comfortable increasing that return of capital. You'll recall when we did the Westbrick acquisition, we reduced or temporarily reduced the return of capital from 50% to 40%. So with those boxes checked, happy to move to the 40% to 60%.

Now one thing that we are going to continue to maintain here is flexibility within that 40% to 60%. And so if you think back to the second quarter here, lots of volatility, whether it was commodity price-wise, share price-wise. And so we want to maintain flexibility in terms of how we allocate capital over the longer term. But with this announcement today, we are looking to increase what we're allocating to shareholder returns.

And then maybe just the last point I'll make, Dennis, if you go back to the Investor Day, last December, we laid out a framework of what we wanted to achieve here over the 5-year plan in terms of end of 2030. I think we are well into that plan, delivering on that plan. We've been able to increase our guidance here in 2026 on the production side, maintain the capital as well. And so we are looking at this from a long-term perspective in terms of allocating that capital.

Maybe just lastly, you asked about Australia as well in terms of how we think about allocating capital. We continue to evaluate the prospect of drilling in Australia in 2027 with where oil prices are, we are leaning towards that being the right decision. So as we foreshadowed in our Investor Day, that would push capital for 2027 into that $700 million range, something that we'll manage within this framework.

So anyways, I'll maybe stop there, Dennis, just to see if there's any follow-up.

Yes. Just I appreciate that color there, Lars. I guess that was kind of a little bit of a lead into my follow-up question is kind of how to think about '27 CapEx. And then again, as you see that kind of free cash flow rate of change in the second half of next year as you round out effectively Montney drilling and then, I guess, now this Australia program, does that help drive more comfort in maybe moving up that targeted range if the balance sheet improves and so forth? Or is kind of there's going to be a balance in terms of where you want to really kind of drive down net debt even further because -- for whatever reason on a go-forward basis?

Yes. No, I think you framed it very appropriately there. So as we get into the second half of 2027 and then sort of, let's call it, the later 3 years of the 5-year plan that we laid out, Capital comes back into that $600 million to $630 million range as the business grows towards that 130,000 barrels a day. And so the reason that we are able to keep capital within that range, grow production are for the reasons that you referenced their Montney infrastructure spend starts to come down. We start to get some gas behind pipe in Germany online. We get the Australia drill behind us as well. And so those will be the type of things that we look at. And I think with the flexibility we have in the framework now, we don't necessarily need to wait for those inflection points to buy back shares. If we want to be a bit more aggressive leading up to that, we have the capability within the framework here. The vice versa is also true in terms of targeting within that 40% to 60%.

Maybe just to build on Lar's comments there because Lars would have presented a slide that's in our deck that shows how that $1.7 billion of excess free cash flow potentially be allocated over that 5-year time frame. And if you look at that plot, it shows the net debt getting down midpoint around $750 million, shows the dividend, of course, lots of runway there. And then on share buybacks, right, we showed a range, but share count was coming down about 30%, right? Now that, of course, would have been based on a $12 stock price, but that was based on $70 oil. That was based on $13 TTF.

So it summarizes Lar's points there as the business fundamentals continue to improve return on capital, there's more free cash flow in the system. We're looking forward to returning more of that. And again, I think the IR Day 5-year plan is a good summary of what this business can deliver at reasonable commodity prices, i.e., $70 oil. is a big number, $1.7 billion of excess free cash flow over 5 years.

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

Thank you again for participating in our Q2 conference call. Enjoy the rest of your day.

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.

Good afternoon, ladies and gentlemen. Thank you for standing by. Welcome to Vermilion Energy's Virtual 2026 Annual General Meeting. Following the formal portion of the meeting, a presentation will be given by Dion Hatcher, Vermilion's President and Chief Executive Officer.

As a reminder, this event is being broadcast live on the Internet and is being recorded. The archived event will be posted on Vermilion's website under the heading, Invest with Us and subheading Events & Presentation.

[Operator Instructions]

I would now like to turn the conference over to Myron Stadnyk, Vermilion's Chair of the Board. Please go ahead.

Thank you. Good afternoon, and welcome to the 2026 Annual General Meeting of the Shareholders of Vermilion Energy Inc. My name is Myron Stadnyk, and as Chair of the Board of Directors of Vermilion, it is my responsibility and privilege to act as the Chair of this meeting. I welcome our registered shareholders, proxy holders and all guests that are joining this meeting through our virtual meeting platform. We are excited to have your participation in the meeting, and thank you for your interest in the affairs of Vermilion.

Before we begin, I would like to offer a land acknowledgment. We respect the histories, languages and cultures of the indigenous peoples where we operate and their continuing connection to the lands, waters and community, and we pay our respects to elders past and present.

I would now like to introduce the other independent directors of Vermilion here with us today. James Kleckner, Corey Bieber, Stephen Larke, Paul Myers, Manjit Sharma and Judy Steele. I would also like to introduce Dion Hatcher, our President and CEO and Director; and Lars Glemser, our Vice President and CFO. In addition, present on this call are members of our Executive Committee.

In terms of our agenda today, I will deal first with the formal business of the meeting as described in the circular. Immediately following the formal business, Dion Hatcher will provide you with an overview of our business and strategy. A question period will then follow. As this meeting is being held virtually via live webcast, I will ask now Tamar Epstein, our General Counsel and Corporate Secretary, to go over the procedures for the orderly conduct of the meeting.

Thank you, Mr. Chair. The following are the procedures. Only registered shareholders and proxy holders who have properly logged in with their control numbers or username will be available to vote on the motions being brought forth. Questions in respect of a motion can be submitted by any registered shareholder or proxy holder using the instant messaging service of the virtual interface. Questions will be forwarded to me shortly after they are submitted, but will only be addressed if they relate to procedural matters or to the motions before the meeting. Questions which do not relate to procedural matters or to the motions before the meeting will be addressed during the question period at the end of the meeting. Questions which were already answered or that are redundant or repetitive will not be addressed, and all matters will be conducted by electronic ballot.

The polls have been opened by our scrutineers and registered shareholders and proxy holders who have not already voted or who wish to change their votes are able to do so on each business item until polls are closed following the formal business presentation. If we encounter any technical difficulties with the webcast, please remain logged on, and we will resume as soon as possible.

Thank you, Tamar. The meeting will now come to order. I will ask Tamar Epstein to act as Secretary and representatives of Odyssey Trust Company to act as scrutineers. To ensure that this meeting covers all the business for which it was convened within a reasonable amount of time, we have arranged for Vermilion representatives who are also shareholders to move and second certain motions.

As mentioned, the polls are now open. And at this time, all registered shareholders and proxy holders who have properly logged in with their control numbers or username and wish to vote will be able to see on the screen all motions being brought forth at this meeting. Please register your votes by selecting the For or Withhold, Against button next to each item to be voted on. If a registered shareholder or proxy holder has already voted on all matters, there is no need to vote again unless you wish to change your vote on a matter.

To my knowledge, the decision of the meeting will be in favor of each resolution to be considered. The scrutineer will compile a report regarding the voting results once all votes have been conducted and the polls have closed. I have received confirmation from Odyssey Trust Company that all materials in respect of the meeting were delivered to shareholders in compliance with applicable securities requirements. I direct that the affidavit, together with copies of the documents delivered to the shareholders, be filed with the minutes. I've been advised by the scrutineers that there is a quorum present at this meeting. Accordingly, I declare that this meeting is regularly called and properly constituted for the transaction of business. I direct that the scrutineer's report be filed with the minutes.

The first item of business is to table the consolidated audited financial statements of Vermilion for the year-ended December 31, 2025, and the report of the auditors thereon. A copy of these materials has been mailed to each registered shareholder who elected to receive such. Any questions related to the financial statements can be raised later during the question period.

The next item of business is to fix the number of directors of the company to be elected at 8. May I have a motion, please?

Mr. Chair, my name is Travis Thorgeirson, and I am a representative of Vermilion and a shareholder. I move that the number of directors of the company to be elected be fixed at 8.

Mr. Chair, my name is Brittany Jensen, and I'm a representative of Vermilion and a shareholder. I second the motion.

Thank you. Any discussion?

I will ask registered shareholders and proxy holders who have not already done so to cast their votes through the online portal.

The next item of business is the election of the company's directors. As noted in the circular, the Board has adopted an advanced notice bylaw, which provides a procedure to be followed for the nomination of directors at shareholder meetings. There were no other nominations received within the requirements of the advanced notice bylaw. Therefore, the only individuals entitled to be nominated as directors at this meeting are the persons named as nominees in the circular as directed by the Board.

I will ask Mr. Thorgeirson, our Director of IR and a shareholder, to read the nominees.

Thank you, Mr. Chair. The following people are hereby nominated to act as directors of Vermilion, Myron M. Stadnyk; Corey B. Bieber; Dion Hatcher; James J. Kleckner, Jr.; Paul B. Myers; Stephen P. Larke; Manjit K. Sharma and Judy A. Steele.

May I have a motion to elect Vermilion's Director nominees as directors of the company?

Mr. Chair, I move that Vermilion's Director nominees be elected directors of the company until the next Annual Meeting of Shareholders or until their successors are elected or appointed.

Mr. Chair, I second the motion.

Thank you. Any discussion?

I will ask registered shareholders and proxy holders who have not already done so to cast their votes through the online portal. In accordance with the company's majority voting policy, we will conduct the election on an individual basis for each director.

The next item of business is the appointment of the company's auditors. May I have a motion, please?

Mr. Chair, I move that Deloitte LLP be appointed auditors of the company until the next Annual General Meeting of Shareholders or until their successors are appointed and that the directors of the company be authorized to fix their remuneration as such.

Mr. Chair, I second the motion.

Thank you. Any discussion?

I will ask registered shareholders and proxy holders who have not already done so to cast their votes through the online portal.

The final item of business is the approval on an advisory nonbinding basis of the company's approach to executive compensation. May I please have a motion?

Mr. Chair, I move that the related resolution as set out in the circular be approved.

Mr. Chair, I second the motion.

Thank you. Any discussion?

I will ask registered shareholders and proxy holders who have not already done so to cast their votes through the online portal.

We will provide registered shareholders and proxy holders a few more moments to complete the electronic ballots before we close the polls. Once the electronic balloting closes, the voting page will disappear and your votes will automatically be submitted.

[Voting]

Odyssey, please close the polls. I ask the scrutineer to compile the report regarding the voting results.

I have been advised by the scrutineers that greater than a majority of the votes cast at this meeting have been voted in favor of the resolutions. Accordingly, I declare all motions carried. I direct that the results of the poll be included with the minutes and the results of the voting will be announced in a press release in accordance with the policies of the Toronto Stock Exchange and filed on SEDAR.

As there is no further business to come before the meeting, I declare the formal part of this meeting concluded. Before turning it over to Dion Hatcher, our President and Chief Executive Officer, I would like to extend my thanks to our management team and employees around the world for their dedication to Vermilion.

Dion Hatcher will now provide an update on our business and strategy and looks forward to your questions.

Thank you, Myron. Hello, ladies and gentlemen. I'm Dion Hatcher, President and CEO of Vermilion Energy. Thank you for joining our Annual General Meeting today. I remind our attendees to please refer to our advisory on 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.

Over the past 3 years, we've committed to repositioning Vermilion as a more resilient and profitable company. 2025 was a very impactful year as we delivered on our strategy and transition to a global gas producer. The outcome of that execution is a structurally more efficient business, as shown by the numbers. Production per share has increased by approximately 45%. Unit costs when combined with G&A are down more than 30% and capital intensity has improved by over 30%.

Before I move on, I want to pause and thank our people. The improvements you see here, higher production per share, materially lower costs and better capital efficiency don't happen without the hard work of our teams. They reflect disciplined execution across our operations, technical, subsurface, commercial and corporate functions. I also want to recognize our focus on health, safety and environment. During this busy year, we implemented multiple new safety initiatives that combined with our strong HSE culture will further enhance our performance. I sincerely want to thank our employees and contractors for their efforts in 2025.

The Deep Basin, Montney and Germany are our 3 core development assets, and they underpin our long-term growth plan. These assets provide decades of inventory and multiple capital allocation levers to generate strong returns with visibility to both near-term and longer-term excess free cash flow growth. In the Deep Basin, that opportunity is today, supported by existing infrastructure and strong well results. In the Montney, the asset transitions to meaningful excess free cash flow in 2028 as infrastructure is completed and capital intensity declines. In Germany, growth accelerates as both our discovered gas and new wells are brought online over the next several years. Although these are our growth assets moving forward, there are plenty of great things happening across our company.

In Ireland and the Netherlands, our teams are focused on supplying natural gas to our customers, which is critical given the need for energy in Europe. In France and Australia, we provide premium liquids, again, critical given the demand for crude across the globe.

Turning to reserves. Vermilion's proved plus probable reserves increased by 36% year-over-year to 592 million barrels of oil equivalent. Importantly, this growth was achieved with a 2P recycle ratio of 3.5x, reflecting the quality and the capital efficiency of our portfolio. This increase was driven by a combination of organic development and our Deep Basin acquisition, partially offset by the divestment of our United States and Saskatchewan assets.

Our internal estimates indicate approximately 1,700 drilling locations across our significant land position in the Deep Basin and Montney with only about 23% of those locations reflected in our year-end reserves. Similarly, internal estimates of gas initially in place associated with our European exploration and development prospects are only minimally included in our book reserves. This reflects our conservative approach in Canada, together with our track record of replacing and growing reserves in Europe. As a result, we believe the duration of our business extends well beyond our current book reserve life.

Turning to the Deep Basin. Vermilion is a top 5 producer by both volume and land position with approximately 1.2 million net acres of continuous land and significant infrastructure already in place. This supports our development plans, meaning our per well half cycle returns are effectively full cycle with minimal incremental capital required to bring new wells on stream. We also benefit from higher liquids weightings than many of our peers, which drives profitability and provides flexibility to optimize capital allocation through the commodity cycle. Our continuous acreage allows us to drill longer wells, further enhancing returns.

The map on the right highlights some of the strong wells from our recent drilling program. These results are not concentrated in any single zone or restricted to one formation. Rather, they are distributed across our land base, demonstrating both the depth and the consistency of our inventory.

Turning to the Montney at Mica. This long-duration asset has required significant upfront investment in order to position it to generate robust excess free cash flow for the next 2-plus decades. Since 2022, production has increased from 4,000 to current 16,000 BOEs per day. Over that same period, we've materially improved both capital and operating efficiencies. The reduction in per well cost has reduced future capital requirements by over $250 million. In addition, operating costs have come down and the majority of the required infrastructure investment is now behind us.

At this stage, Mica is approaching an inflection in free cash flow in 2028 as production reaches approximately 28,000 BOEs per day. Importantly, this outlook does not assume an accelerated Alberta Montney development program. We are actively drilling on the Alberta portion of our land base today, which represents additional upside beyond the base development plan.

In Germany, our deep gas exploration program is delivering results. The Osterheide well has been on production for over a year and the Wisselshorst well, which represents our largest discovery to date in Europe is expected to come on stream by midyear. Wisselshorst is located on the Bommelsen license where we have identified up to 6 additional drilling locations, highlighting the scale and the materiality of this opportunity. We remain on track to drill the next 2 wells on this license in early 2027, and we'll apply learnings from our initial wells to improve cycle times and capital efficiencies.

In addition, we are excited to test additional structures the team has identified on our large land position. With the depth of inventory in Germany, we are well positioned for meaningful free cash flow growth through 2030 and beyond. Importantly, this growth is organic and not depending on acquisitions. That said, our recent acquisition in Germany strengthens the outlook by adding low decline production and by increasing our control over gathering infrastructure surrounding the Osterheide area.

Following the largest cash acquisition in Vermilion's history in 2025, our debt levels increased, and we had a clear plan to reduce debt as we recognize the importance of a strong balance sheet. Over the past year, we've reduced net debt by approximately $0.75 billion through a combination of organic deleveraging driven by excess free cash flow and inorganic reduction through strategic asset sales. As a result, we have now increased visibility to our net debt $1 billion target, and we will continue to prioritize our excess free cash flow to the balance sheet and accelerate the pace of deleveraging.

Vermilion is focused on disciplined capital allocation with a clear emphasis on profitability and long-term compounding. Our approach is to allocate excess free cash flow to strengthen the balance sheet, invest in high-return projects, grow the base dividend and reduce our share count. We have a long track record of returning capital to shareholders, and we aim to continue to grow the base dividend as well as repurchase shares when our market valuation does not reflect our business fundamentals. We target a nominal return of 10% to 15% year-over-year by a combination of moderate production growth, dividend yield, debt reduction and share repurchases. With a relatively low share count, our capital allocation decisions have a greater impact on per share outcomes. This amplifies the benefits of our investment and is a key advantage.

Our disciplined approach to investments gives us confidence in our 5-year operational plan by investing in the Montney infrastructure, advancing our German deep gas program and expanding our position in the Deep Basin, we are laying the foundation for sustained profitable growth. Under the plan we outlined in our December Investor Day, we expect production to increase from approximately 120,000 to 130,000 BOEs per day. When combined with ongoing share repurchases, production per share is projected to increase by approximately 40% by 2030. Our annual exploration and development capital over the next 5 years is expected to average between $600 million and $630 million. The upper end of the average range includes 1 year of higher investment due to the planned offshore Australia drills currently targeted for next year.

Based on our Investor Day pricing assumptions of $70 WTI, $13 per MMBtu European gas and $3.50 per GJ AECO, we expect to generate approximately $1.7 billion of excess free cash flow over the next 5 years. Today, prices for both WTI and TTF are much higher, which highlights the ability of our portfolio to generate even more robust excess free cash flow that, in my view, is not yet reflected in our current valuation.

In closing, I want to thank our employees for the focus and the commitment you brought to 2025. It was a demanding year, and your execution has positioned Vermilion exceptionally well for the future. Over the past 3 years, we've executed a strategy to reposition our portfolio to add operational scale and long-duration assets to strengthen the balance sheet and sharpen our focus on profitability. We're seeing the results of that execution today, and we remain committed to disciplined capital allocation and operational excellence as we move forward. On behalf of the Board and management team, I want to thank our shareholders for your continued support.

With that, we'll check the line for questions. Okay. It looks like we don't have any questions at that time. And so with that, again, I want to thank everyone for attending today, and we'll close the meeting. Enjoy the rest of your day.

Thank you. And this concludes today's meeting. You may now disconnect.

Good morning, ladies and gentlemen, and welcome to the Vermilion Q1 2026 Conference Call. [Operator Instructions] 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 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 4 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. 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 up asset base has driven Q1 G&A per BOE down by over 50% versus '25.

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 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 $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 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 $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. 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 3 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. And 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 was lower by 25% compared to Q1 025.

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 2 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, along with other key infrastructure 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.

[Operator Instructions] 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 5-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, continue 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 3 additional exploration concessions that we've gotten in Germany, 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 -- all of 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 kind of 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 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 the wisdom of some of their production and exploration bans and whether they should be relooking at those sort of things.

So 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.

Maybe I'll just -- 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? Or maybe just describe what the M&A market looks like now, assuming normalized pricing in that.

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

You bet. I mean we just recently announced our one deal of acquiring 1,000 BOEs a day in Germany. What we liked about that is adjacent or increasing our working interest in existing assets. We do see potential.

I think Vermilion -- 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. And 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, and so we'll continue to assess opportunities there.

Your next question comes from Spencer Limming with CIBC World Markets.

Just kind of touching more on the regulatory environment. Are you seeing -- discussions are looking good, right, in terms of government policy, in terms of increasing production. But has there anything -- 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. I can summarize maybe what Darcy said and please jump in Darcy, if you have comments. I mean I think there's a -- just like Canada in every jurisdiction, there's an established time line 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 time lines are met and those permits are awarded in a timely manner. So what that means is we brought 2 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 Netherlands.

We got our 2 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 time lines. 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 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 time line of kind 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 3 rigs we're running consistently in Deep Basin, we're seeing those wins. But, Randy, over to you to build on those comments.

Yes. It's a good -- it's a fair comment. Like I think the Deep Basin, it's -- with our 3-rig program, we've really been able to leverage our operational scale and our dominant position in that Deep Basin. So we have seen costs come down.

As they flow through, we'll kind of work through it in the next couple of quarters here. But I would say we have definitely seen costs come down and continue to work on with this continuous improvement, we expect to see further efficiencies as we continue to get more active 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.

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.

Good morning, everyone, and thank you for joining us for the 2025 Vermilion Energy Investor Day presentation. I'm Travis Thorgeirson, Director of Investor Relations and Corporate Planning, and I'm excited to tell you what we have planned for today. We will cover our corporate overview and strategic advantages as we spotlight the depth, quality and duration of our growth assets in both Europe and Canada.

We'll discuss portfolio management and review our near-term outlook, along with the capital allocation principles that guide our decision-making. Please refer to the advisory on forward-looking statements provided at the end of this presentation [Technical Difficulty] forward-looking information, non-GAAP measures and oil and gas today and outline [Technical Difficulty] and assumptions relevant to this discussion.

As we near the end of a highly impactful year in 2025, we are looking ahead to a bright future as a global gas producer. Vermilion is focused on investing in our global gas assets over the next 5 years with approximately 85% of our capital expenditure plan to be allocated to our Deep Basin, Montney and onshore European Gas assets, particularly in Germany, as they will be the key drivers of a step change in excess free cash flow generation for the company.

As a reminder, we define excess free cash flow or EFCF as our fund flows less capital expenditures and abandonment and lease obligations. We'll also continue to harvest cash from our assets in Ireland, France and Australia, which have contributed a significant amount of excess free cash flow over the years has been a critical component of the company's success. Slide 4 highlights the long-term commodity price forecast used in today's presentation.

This forecast reflects natural gas prices relatively in line with where the forward strip is today, while oil prices are reflective of a longer-term average for both WTI and Brent. Our global gas portfolio is uniquely positioned to benefit from top decile realized natural gas prices with meaningful contributions from our 30% [Technical Difficulty] production rate. We will continue to apply financial discipline to navigate commodity cycles with resilience.

Today's presenters include Dion Hatcher, President and CEO; Geoff MacDonald, VP, Geosciences; Darcy Kerwin, VP, International and HSE; Randy McQuaig, VP, North America; Lara Conrad, VP, Business Development; and Lars Glemser, VP and CFO. The team brings a depth of knowledge and expertise [Technical Difficulty] to deliver priorities they will discuss today and drive Vermilion's future success. With that, I'll hand [Technical Difficulty].

Thank you, Travis, and good morning for everyone joining us today. I'm Dion Hatcher. This is my third year as CEO. After having the privilege to be a part of Vermilion for over 20 years. Now our last Investor Day was in 2018, that is over 7 years ago. Fair to say there's positive change in that time. I'm proud of our team and our portfolio. I'm quite excited to share our 5-year plan [Technical Difficulty] to look through these numbers, we're going to generate $1.7 billion of excess free cash flow over a 5-year period.

That represents approximately 90% of our current market cap. So today, we want to leave you with 3 key takeaways. First, it starts with strategy. We've captured; we've discovered large in-place resource [Technical Difficulty] with repeatable [Technical Difficulty] we are excited to share. Second, we're going to show you lots of examples of operational excellence, continued improvement on controllable items, which safety, production costs when combined really helps to improve our profitability.

Third and of course, the most critical element then becomes per-share outcomes. We have only 153 million shares outstanding, which positions us to add meaningful value per-share as we execute our plan. So this ties directly into our per-share excess free cash flow that is doubling to $2.75 by 2028. More importantly, that number is sustainable. With this increasing excess free cash flow, the base dividend and share buybacks will continue to increase and our balance sheet will become even stronger.

I would mention, it's been a very impactful year. We're pretty excited about what Vermilion offers investors today. Our reposition [Technical Difficulty] global gas and oil has more production, is more focused and is more efficient and is underpinned by long-life assets. This global gas portfolio provides exposure to both Canada as well as premium priced European gas. That combination offers the top decile realized gas price.

If we move to our key assets, we have a Germany production growth plan, which is the lowest cost way to gain access to international pricing. So today, you're going to hear from Darcy and Geoff talk [Technical Difficulty] about our largest discovery in over a decade in Europe as well as the potential for material discoveries given the number of identified prospects we've got offsetting large fields, each which have produced over a Tcf of gas.

Also will review the milestones, which will enable us to double Germany's production by 2030, and it's great to see the team off to such a strong start with our production year-to-date in Germany up over 25%. In Canada, we've got a deep [Technical Difficulty] we've got this Dominant Deep Basin asset. We've got over 1.1 million acres. We've got multiple liquid-rich opportunities where we can profitably grow our production and utilize existing infrastructure. We're going to pair the Deep Basin with our liquids-rich Montney asset.

That's a concentrated asset that's nearing an inflection in free cash flow in 2028. The production ramps up and then the capital ramps down. I don't want to steal Randy's and Geoff's thunder, but with the recent well results, in particularly in the Deep Basin are well above our peers, and we're excited as this backstops the depth and the quality of inventory that we've got in our portfolio.

So with this repositioned portfolio, strong operational performance and a structural improvement in excess free cash flow, we are well positioned for returning capital over the long term. We've bought back over 20 million shares in the last 3 years alone. We've increased our dividend in each of the last 5 years, yet the dividend payout today is quite low, sub 10% of our fund flows. Lars and Lara will walk through our portfolio, the resilience of our business and the capital markets opportunity later in the presentation.

So when I took the CEO Chair, we moved quickly to recalibrate the portfolio, something that we had not done in the history of our company. Today, we are in the position of being prospect and inventory rich. We've got over 25-plus years, 20-plus years and 10-plus years of inventory in the Deep Basin in the Montney and in Germany. In the table, you can see the excess free cash flow growth. Deep Basin is today, Montney inflects and pivots in 2028 and Germany with just the gas that we've already discovered that's behind pipe will grow in 2028 and beyond. Our direct global gas exposure is unique.

We produce 100 million cubic feet a day of gas in Europe. For LNG, there is significant cost. You've got to build, operate and ship LNG [Technical Difficulty] the ocean. What we do shown on the right, we drill a vertical conventional well. Our finding and development cost is around CAD 1.50 per Mcf, and we sell that gas to the grid. That gas sells for a premium price. This year, our average will be about CAD 15 per Mcf.

By doing it this way, we avoid for our international gas exposure, the risk of these multi-decade large volume contracts, which often have fixed fees to deliver gas into the facility. Later in the presentation, Darcy and Lars will explain why our Germany drilling program is the lowest cost way to gain exposure to international premium pricing.

Inversely, given our amount of gas, over 400 million cubic feet a day of gas that we produce in Canada, the combination of the Deep Basin and the Montney, we have a lot of torque to improving AECO pricing, which we think will be a backdrop with the increased LNG export capacity in Canada. To put this in perspective, every 130 [Technical Difficulty] sorry, every dollar increase in pricing would add over $130 million of free cash flow, again, with 153 million shares outstanding that is impactful on a per-share basis.

Our business has become more efficient. We are now [Technical Difficulty] bigger with lower costs. In Q3, given the performance we're seeing in the second half of the year, we reduced our capital guidance. We reduced our operating costs, yet still delivered on our production. Our production was actually above the midpoint of our guidance range. In Q3, we also announced our 2026 budget.

Our repositioned portfolio, if you compare back to 2024, the year before the portfolio streamlining, the production per-share has increased by over 40% while the combination of [Technical Difficulty] has been reduced by over 30% as well as our capital intensity has improved by 30%. These reductions, although important, are just part of the story for structural increases in excess free cash flow. Our repositioned portfolio has structural increase, structural tailwinds as we go into 2028.

First is improving capital efficiency. If you look at our drilling inventory, we've high-graded our drilling inventory. Second is the Montney infrastructure. That build-out is [Technical Difficulty] nearing completion and the capital requirements will recede. Third is our ability to grow our Deep Basin volumes within existing [Technical Difficulty] the combination of these 3 things will improve our capital efficiency as we go forward. Second is [Technical Difficulty] peer group average.

But as we start these new German wells, which are essentially flat production, our base decline will further moderate with time. And the third is the long runway of decades of inventory that we now have and the flexibility to [Technical Difficulty] allocate either Canada or European drilling [Technical Difficulty] these structural improvements and use the price deck that Travis noted at the start of the presentation. So again, gas prices [Technical Difficulty] longer-term average price of crude of $70 WTI, we're forecast to generate $1.7 billion of excess free cash flow between 2026 and 2030, with a significant increase starting in 2028.

Our investments in Montney infrastructure and derisking and expanding our Deep Basin position provides confidence in our 5-year plan. Production will grow from 120,000 to 130,000 BOEs a day, while on a per-share basis, when you combine that with our share buybacks, production will grow by over 40%. If we move to capital, our average E&D investment is $600 million to $630 million. As a reminder, we're guiding to $635 million this year. That includes operating [Technical Difficulty] half of the year.

In 2026, we're guiding to $615 million, both 2025 and 2026 will also include Montney infrastructure, which again will decrease over time. There is 1 year of higher capital spend in our 5-year plan when we execute our Australia drilling program candidly in 2027. So under this scenario, generate $1.7 billion of excess free cash flow. Looking at how we would allocate that capital and the impact that would have on me and shareholders, we would find ourselves in 2030 with net debt approximately $700 million lower than today.

We would buy back over 40 million shares based on today's price, and we're able to significantly grow our base dividend while maintaining a payout ratio of low around 10%. So later in the presentation, Lars will speak more on this topic, but you can get a feel for how impactful this level of excess free cash flow will be for return of capital and share price appreciation. Last slide before I pass it over to the team outlines the step change in excess free cash flow starting in 2028. That aligns with the $1.7 billion over the 5-year period.

We start with the bar on the left in 2026, using the current strip pricing, crude sub-$60 oil, we generate excess free cash flow of about $200 million. The next bar is the excess free cash flow inflection. That's an additional $200 million of which 1/3 or $60 million is a structural increase. That's driven by strategic investments and assumed no increase in commodity prices.

Of note, the doubling of our excess free cash flow from $200 million to $400 million does not factor in any additional operational excellence improvements beyond what we are achieving today, which, of course, is a key focus of our teams every day. The table outlines the key milestones required to deliver a structural increase of excess free cash flow. Our teams have been busy delivering our plan. I'm confident we'll keep this momentum going into 2026 and beyond. So next, I will pass it to Geoff. We'll start with the depth and quality of our inventory in our key assets.

Thank you, Dion. Good morning. I understand the slides are not advancing online, so I'll just reference that we were on Slide 17 to those participants outside of the room. I'm Geoff MacDonald. I work as Vice President of Geoscience here at Vermilion. I've been here since 2019. I'm happy today to have the opportunity to walk you through a bit of Vermilion's past, but more importantly, a discussion about the resilience of our portfolio's growth assets in the future.

I'd like to start this section on Slide 18 by sharing some insight into Vermilion's technical culture. I'm proud to say that our geoscience staff considers several commercial fundamentals in every well we drill. For our Canadian teams, we constantly strive to unlock more value on every acre we own and make each well better than the last. For our European teams, it's about understanding and mitigating risk while constantly striving to find bigger and better targets to chase.

We build our core positions where there is a significant resource in place for 2 reasons. First, our fairways are proven. We believe in small-e exploration, adding zones and [Technical Difficulty] through time, which [Technical Difficulty] where there is resource concentration, time works in your favor, technology unlocking opportunity. Because every dollar matters, we strive to mitigate capital exposure risk through partnerships, competitive intelligence and technology. On Slide 19, we'll discuss the Deep Basin.

Back in the '90s, earlier in our history, Vermilion began to acquire and develop resources in the Deep Basin of Alberta. Despite being a trust, Vermilion was a pioneer in several emerging tight sand plays. We've drilled literally hundreds of wells in the Cardium, the Spirit River, the Ellerslie and now the Rock Creek formations, unlocking liquids-rich inventory across our acreage base that has led to meaningful organic production growth.

Complementary to this success, Vermilion entered the Montney at Mica, straddling the Alberta and British Columbia border in 2022. This geologically unique area secured Vermilion's portfolio of foothold in [Technical Difficulty] high liquids and inventory deep area. Finally, through the Westbrick acquisition, which closed earlier this year, our Deep Basin position now exceeds 1.1 million net acres. We have decades of inventory on both assets, yet 2/3 of this inventory remains unbooked.

For a geologist, the Deep Basin is an exciting fairway. It has the attributes of a basin-centered cell where water risk is minimal, yet as we've shown across our acreage, carbon liquids are prolific. We've identified 9 productive stacked siliciclastic horizons and counting, we are combining depositional models with 3D seismic visibly unlocks inventory that can be calibrated to outcrops in the foothills and also to local core. Randy will later show the exceptional performance of recent wells within the Spirit River formation, i.e., the Notikewin, Falher, and Wilrich that have exceeded our pre-position estimates.

It'll also show recent performance from the Lower Mannville and Jurassic interval, where early time oil rates from 2 recent [indiscernible] wells have outperformed much of our 10 years of legacy drilling. With decades of running room in these plays spanning from Badger in the South to Carrot Creek in the north, the Deep Basin is an exciting zone where our teams will continue to unlock new areas and new zones for years to come. On Slide 21, I'll shift to a discussion on the Montney.

As we have discussed later, our excess free cash flow inflection point is approaching. And once reached, our Mica asset has the inventory depth to then hold flat for the next 20-plus years. Mica has subsurface attributes such as an anomalously thick and liquids-rich anchor zone in the Middle Montney, but we also have synergistic yet isolated emerging upside in the upper Montney and a massive liquids resource in the Lower Montney, a resource we currently exploit through our Middle Montney completions.

The [indiscernible] potential makes Mica an area that can deliver for decades with the ability to surprise to the upside. On Slide 22, I'll shift to our international business, crossing the Atlantic. Vermilion entered the Netherlands in 2004 with our first drilling campaign in 2009. Over our 2 decades there, we've had a 70% track record of success, and we realized 270 billion cubic feet of gas production from our organic drilling to date. This is the equivalent of our [Technical Difficulty] unrisked resource predictions.

For context, we risk our conventional prospects and by 70%, we mean that 21 of the first 30 wells that we drilled successfully discovered hydrocarbons. On a portfolio basis, we apply similar probabilistic techniques to our volume forecasts as a means to balance risk and reward in our conventional exploration portfolio. Discovering the unrisked and therefore, higher volume demonstrates our commitment to technical rigor and risk mitigation.

Vermilion entered Germany a decade after the Netherlands in 2014, expanding its position to approximately 1.5 million net acres across the productive Permian reservoir fairways of the North German Basin. Our acreage is almost completely covered by 3D seismic. And with this, our strong teams have been able to build a funnel of opportunities that includes more than 50 leads, more than half of which have been adequately technically [Technical Difficulty] to be included in [Technical Difficulty] plan.

Several of these prospects, both in the Netherlands, but in Germany especially, have potential -- have multiple potential follow-up drills once proven. Our multi-decade track record of success suggests that we will continue to realize economic production, reserve replacement and growth for years to come. On Slide 23, in Germany specifically, where activity has ramped up, our most recent 3-well campaign [Technical Difficulty] significant discussions on Osterheide and especially Wisselshorst, which has a [indiscernible] predicted original gas in place of 380 billion cubic feet, which is proportionate in size to its neighboring fields.

Development of this field alone, along with our exploration campaigns over the coming years, maintains a robust level of activity. Any further success simply amplifies our capital allocation possibilities. Our third drill in 2024 at Weissenmoor South encountered permeability challenges during its discovery of a gas column literally hundreds of meters thick. However, there is ample room to sidetrack from the crest of the structure to an area where amplitude suggests better and thicker multi-zone reservoir less than 1,000 meters away.

I'd like to put our acreage in the context of the stacked zone schematic and map of adjacent producing fields on this slide. Several Rotliegend fields have each produced more than 1 trillion cubic feet [Technical Difficulty] Bommelsen and Osterheide licenses. These lie within the dune and fluvial [indiscernible] of the Rotliegend formation, where chloride mineralization preserves permeability despite the reservoir interval being approximately 5,000 meters deep. Moving up the stack to the Zechstein carbonates, our Bahrenborstel and Barenburg licenses are nestled in among several large Zechstein fields producing from prolific platform basis.

It is here that our Scholen prospect lies. Now back down the stack instead, there are both legacy and more recent discoveries in carboniferous stage rock, of which Vermilion also has prospectivity and we'll test at Uchte and at [indiscernible] in the Netherlands. Again, this is not frontier exploration. Rather, this is small reexploration in a proven basin where significant gas pools, some over 1 trillion cubic feet are common.

Our successful track record of discovering gas fields in the Netherlands and Germany is undergoing equal transition now for 2 reasons. First, the scale of targets in Germany is significantly larger than the targets we've been able to historically pursue in the Netherlands. Second, the volumetrics of the targets we are chasing in the Netherlands is also increasing. These 2 factors nearly triple the mean unrisked gross per well gas recovery from 9 billion cubic feet in our historical Netherlands drills.

Looking back, our first 30 wells discovered more volume than our unrisked internal estimates at approximately 270 billion cubic feet. Looking forward, our technical teams have identified 31 single- and multi-well structures that are on average 2.5x larger than those drilled to date. This is a meaningful step change to our European gas prospectivity. I'll wrap it up on Slide 25 before I pass the mic to Darcy. Here, I'll touch on Vermilion's opportunity set in the context of how we book our reserves.

In the Deep Basin, [Technical Difficulty] 1.1 million net acres, only 21% or approximately 300 of the 1,450 locations we've mapped was included in our year-end legacy 2024 reserves or the acquisition reserve estimate commissioned for the Westbrick deal. In the Montney, we've booked 6 years of our inventory. And for context, once the ramp-up to 28,000 BOE a day is realized, our remaining inventory will generate meaningful excess free cash flow for 2 decades to come.

And finally, building on comments from the last slide, only 16% or 5 of the 31 single- and multi-well structures we've identified in the Netherlands and Germany is included in our 2P reserves. Given our conservative philosophy in Canada, along with our strong track record of replacing reserves in Europe, not to mention the opportunity set in front of us, we are confident that the duration of our business is meaningfully longer than our reserve life index. With that, I thank you for your time this morning, and I'll pass it to Darcy Kerwin to discuss our European gas business in more detail.

Thanks, Geoff. Good morning, everyone. Thanks for joining us today. My name is Darcy Kerwin. I lead Vermilion's international operations as well as our corporate HSE Group. Over my 20 years with the company, I've had the pleasure to manage our assets in Australia, in France and in Ireland. Now my priority is on unlocking the next phase of growth in our European gas assets, specifically in the Netherlands and Germany.

Geoff has already presented the geology of the region, and I will further expand on our opportunities to show how these assets and our people will position us for profitable European gas growth. Our teams in Europe combine deep technical capability with strong relationships in these jurisdictions, both of which are critical for permitting and execution and continuing success in Europe. I will show you how our land base in Germany and the Netherlands is core to our European gas strategy.

The first item I'd like to point out is the close proximity of our German and Dutch operations. The distances between our offices in Amsterdam and in Hanover shown in blue on the slide, is approximately 400 kilometers, a 4-hour drive, not significantly different than the distance between Calgary to Edmonton or Boston to New York. Within this relatively small region, we have a double land base. This, combined with the proximity, reduces complexity and allows for synergies between our Dutch and German operations.

Together, Germany and the Netherlands represent a significant undeveloped land base. With approximately 1.5 million acres of land and almost 50 million cubic feet per day of gas production in these 2 countries alone, we see a long runway of high-return projects across the basin. In Germany, we're building out key infrastructure that will enable us to bring new discoveries online efficiently, improving costs and cycle time of several large prospects in our portfolio.

In the Netherlands, we continue to build on a history of successful exploration and development, and we'll focus on larger structures adjacent to our current infrastructure. These assets generate strong low decline cash flows, which underpin long-term excess free cash flow growth. Importantly, this comes without the burden of long-term LNG commitments, giving us flexibility to allocate capital where returns are greatest. Execution matters. We're building on more than 2 decades of European gas development expertise.

The track record of our strong technical teams speaks for itself. Since entering the Netherlands in 2004, we've drilled 30 wells with a 70% success rate, and we've added over 180 billion cubic feet of reserves. Some recent permitting achievements will allow us to focus on larger pool developments in the Netherlands adjacent to our asset base. By leveraging these skills in Germany on similar geologic formations, our deep gas program is targeting substantially sized pools of 30 billion cubic feet each.

These are large prospects, each with the potential for numerous follow-up locations. As an example, the 1.6 net wells that we've drilled at Osterheide and Wisselshorst add more than 20% to our European gas reserves. From a production point of view, once these wells are debottlenecked, these 2 wells will produce 25 million standard cubic feet per day compared to our current European production of 100 million cubic feet per day.

Looking to the future, our strong technical teams are working with our extensive 3D seismic coverage, and our permitting teams are working with host governments to deliver permits in a timely and a predictable way. To [Technical Difficulty] we have done over 10 years of development prospects, which will unlock significant value from these conventional gas assets. These opportunities are large. On the Bommelsen license in Germany, our most recent discovery, Wisselshorst, is European's largest in over a decade, adding 68 Bcf of gross reserves.

This discovery validates our technical approach and highlights the scale of opportunity in the North German Basin. Germany presents an opportunity not seen in Western Canada since well before the unconventional revolution, large conventional targets that have the ability to produce at flat or very low decline rates for years, reliably generating meaningful excess free cash flow without consuming additional drilling capital to offset declines.

Building on this success, within the broader Bommelsen exploration license, we have identified multiple follow-up locations with [Technical Difficulty] gas in place at least a 380 billion cubic feet, which will be the focus of our early 2027 drilling program. Now these wells are big reserves. Successful exploration in Germany can replace all of our current European gas reserves. We've identified up to 30 drilling locations with 6 gross, 3.9 net wells planned to be drilled by 2030.

Each of these wells has the potential to add approximately 30 billion cubic feet to our portfolio, which is transformational for [Technical Difficulty] European gas. Our recent gas discovery in Germany could fully replace all of our current European gas reserves. I should point out that these wells are a combination of exploration, appraisal and development wells. We may elect to farm down some of the initial exploration wells to manage capital at risk and improve prospect economics. This is not just incremental growth.

It's a step change in our ability to deliver premium priced gas in Europe. [Technical Difficulty] very impactful. To put them in perspective, 2 gas wells in Germany is equivalent to 12 wells in the Deep Basin in terms of reserves and value. Both opportunities are compelling. With similar investment costs and reserves, the premium European gas pricing drives higher NPVs in Germany. Two wells drilled in Germany can deliver the same impact as a full year of drilling in the Deep Basin, but with higher margins and longer durations.

We like to think about these wells in terms of how many times they pay out [Technical Difficulty] during their lifetime. Again, both the Deep Basin and German wells are impressive. Our Deep Basin wells pay out over 3x, which is better than most unconventional assets, but our German deep gas wells are even stronger, paying out 4x over their lifetime. These high payout numbers mean less capital is required, driving outsized NPV per well, resulting in higher excess free cash flow per-share for Vermilion, confirming why Germany is still a strategic growth lever for us.

We're focused on efficiency. By batch drilling wells and leveraging high-performance rigs, we're reducing cycle times and capital costs. Standardized modular gas facilities have similar impacts on capital costs and cycle times but will also significantly lower operations and maintenance costs going forward. As an example, we expect that the follow-up wells to our Wisselshorst discovery will have a 20% decrease in capital and a 30% reduction in cycle time from well release to first production, further enhancing economics.

We're confident that the cost for our new exploration wells will be significantly lower than our current European legacy cost structure. With unit operating costs of approximately $0.50 per Mcf projected for our Osterheide and Wisselshorst developments and F&Ds in the $1.50 per Mcf range going forward, we see significant cost advantages over LNG imported into Europe. Follow-up development wells will benefit from this improved and accelerated development time lines.

Later in his presentation, Lars will show you how this cost performance offers investors the best exposure to premium European gas prices. Our goal is to deliver the lowest cost of supply for international gas exposure, and we're well on our way. Infrastructure is key to unlocking value. We've completed the Osterheide facility and pipeline tie-in, and we're progressing the next phase of the Wisselshorst processing facility [Technical Difficulty] network. These investments set the stage for bringing additional wells online efficiently.

With long-lead equipment already ordered and permits secured, we're positioned to execute and grow quickly and cost effectively. On Slide 35, Germany is now pivoting from investment to excess free cash flow generation. With 2 wells drilled and infrastructure in place, we expect meaningful contribution starting in 2026, growing through 2030 and beyond.

With our Osterheide well currently online and producing above our pre-drill expectations with strong production rates heading into winter, we will bring our discovery well at Wisselshorst online in the second quarter of next year and we'll focus on infrastructure debottlenecking into 2027. The revenue generated from these first 2 discoveries will generate significant and sufficient excess free cash flow to self-fund planned further development and exploration wells in the Europe.

We see additional drilling opportunities on the Bommelsen license and have 2 wells planned for 2027, expected to come on stream in 2028 with production continuing to grow into 2029 and 2030. The program offers low-cost international exposure to European gas and long-duration cash flow. By 2028, German Deep Gas production will represent a significant portion of our European output, driving structural improvements in our cost [Technical Difficulty]. In summary, by 2030, we expect Germany's production to be approximately 10,000 BOEs per day, driven by the addition of over 8,000 BOEs per day of production from our Deep Gas exploration program.

Finally, Germany played a key role in more than offsetting declines from more mature assets like Ireland. As Ireland naturally declines, production from Germany will replace reserves and more than sustain European gas output for years to come. This is a [Technical Difficulty] that supports Vermilion's long-term excess free cash flow profile and positions us to deliver consistent returns to shareholders. I'll now pass to Randy McQuaig, VP North America, who will give you an overview of our Deep Basin and Montney assets. Thank you.

Good morning, everyone. My name is Randy McQuaig. I lead North American operations, and I've been with Vermilion for 12 years. As Travis said, this has been an impactful year for Vermilion, where we've repositioned and simplified our North American portfolio, and I'll review our 2 main assets, the Deep Basin and the Montney. So why are we in these plays? In this slide, you can see the independent research shows that these are 2 of the Top-4 North American gas plays.

And I'll note the payout shown here around 1 year, and I'll reference those when we review the economics later in the presentation. So starting with the Deep Basin. Geoff went through our history of working here for years. You can see our significant land position in the area and the large amount of infrastructure where we currently have in excess of 100,000 barrels a day of capacity.

This area provides us with significant upside and optionality with the high-graded position that we achieved through the Westbrick acquisition, and I'll walk you through some of the key attributes in the coming slides. The key stats that reflect our dominant position is that we are a Top-5 Deep Basin producer by both volume and land [Technical Difficulty] liquids weighting compared to our peers, which drives robust rates of returns. And as Dion had mentioned, there is significant infrastructure in place to support our plans.

So really, our half-cycle returns become full-cycle with a minimal amount of CapEx required. You can also see on the map the contiguous acreage position, which provides us the ability to drill longer wells, which also increases the rates of returns. Lastly, as mentioned in our Q3 release, our recent well results have exceeded our guidance. With our focus on profitability and the decision to defer, most of these wells were brought on production last month into a stronger AECO pricing environment.

The map on the right highlights a few of these wells where you can see they are not concentrated in any one area or any one zone, which really speaks to the depth of our inventory. Moving into inventory. The team has identified over 1,400 locations across our land base, where there are 9 discrete zones within the Deep Basin stack. This provides us with decades of inventory that support production rates of 70,000 to 90,000 barrels a day, assuming we're drilling 40 wells a year.

With this depth of inventory and existing infrastructure capacity, we have the ability to materially grow this production if we allocate -- choose to allocate more CapEx to this play. The inventory number is also quite dynamic where we allocate a portion of all of our drill programs to strategic wells to test new concepts areas. And when they're successful, they prove up additional inventory.

We've also been very active in increasing this land base, where we've already added 38 sections of land this year through Crown land sales and various swaps and farm-ins, and our teams continue to be active here with the goal of dominating the Deep Basin in our area. On the theme of operational excellence, where Dion mentioned, we have a culture of continuous improvement and focusing on what we can control. You can see the drilling costs compared to 30% improvement from previous programs.

This is done through our ability to drill longer laterals on our contiguous acreage block while having shallower depths in comparison to our peers. We're also starting to see the cost benefits of running a consistent 3-rig drilling program by realizing the efficiency and the optimization gains, which is helpful to further drive down these costs. The other key component to our program is achieving strong well results. You can see the significant improvement in our 2026 budget forecast compared to the average of the prior programs.

The star on here is showing the IP30 for the Q3 program, which is coming in at over 1,000 barrels a day, which is almost twice the rate of our previous programs and over 200 barrels a day above our budget forecast. This 13-well program definitely exceeded our expectations, and I am really proud of our team's efforts to deliver such a solid result, and I wouldn't be surprised to see a few of these wells show up in the top well reports later this month. Finally, we move to the economics.

Our improved tight curves combined with the lower cost is driving the robust economics shown on this slide. The research that I showed at the start of this presentation has our Deep Basin payout at 1 year, and you can see that our economics are aligned with this. And with our focus on continuous improvement and achieving strong results, I fully expect to see this get better over time.

So in summary, we have a strong technical team in place who've been energized with our recent results and the ability to work on the significant land position in the prolific part of the Deep Basin, and I have full confidence that they will continue to deliver on our Deep Basin commitments while providing further optionality to provide meaningful excess free cash flow to Vermilion. So with that, I will move to our Montney asset review.

As Geoff mentioned, we entered the Montney in 2022, which established this large contiguous land block, and we've grown our production from [Technical Difficulty] barrels a day to the current rate of 16,000 barrels a day while building out some of the key infrastructure that support our plans to achieve our target rate of 28,000 barrels a day in 2028. A key component to achieving this target is having our infrastructure in place, which is nearing completion.

You can see the progress that we've made here in the phased approach we took in expanding our 8-33 battery in BC, along with building the water hub, which resulted in $650,000 per well savings due to reduced water sourcing and handling costs. Final Phase 3 expansion of 8-33 is scheduled to be completed in the second half of 2027 with the estimated $40 million of spend occurring over the next 2 years.

This will bring our capacity in BC to 27,000 barrels a day, 20,000 of that or 120 million a day is related to gas compression. This gas will be processed at the expanded third-party West Doe facility, which is being constructed by Tourmaline scheduled to be completed in late 2027. We also have 6,000 barrels a day of capacity in Alberta, where we plan to drill a 4-well pad next year.

With the interpretation of our recently shot seismic and the [Technical Difficulty] of our recent retention well in the area, we see upside on these lands and are excited to get these results. Success here would provide further development upside and the optionality to exceed the current 28,000-barrel-a-day target we have for Mica. So with the majority of infrastructure investment behind us in 2028, Mica will be pivoting to a long-term free cash flow generating asset.

To get there, we forecast drilling 40 wells to reach our target rate, and then we can sustain that production level with around 8 wells per year. And as Geoff reviewed, we currently have enough identified inventory to hold this flat for over 20 years. We also have the long-term marketing agreements in place and [Technical Difficulty] egress points that allow us to maximize profitability of this asset, and Lars will expand more on that later in the presentation.

On the theme of operational excellence, you can see the significant improvement that our teams have made in reducing the DCET costs through various optimizations in both drilling and completions. In the past year alone, we've seen our DCET decrease by over $1 million per well, bringing our current estimate down to $8.5 million per well. This reduction has been critically important when you [Technical Difficulty] large number of wells we plan to drill in the next few years.

And with our team's focus on this, I wouldn't be surprised to see it come down even further over time. Moving to the economics. You can see here that our top quartile DCET for extended reach oily Montney, along with the strong production and high liquid rates is driving this robust rate of return. The economics are better than the industry payout of 1 year that I referenced earlier. And much like the Deep Basin, this play is moving to half-cycle returns [Technical Difficulty] full-cycle with the infrastructure investment spend behind us.

So in summary, you can see the progress that has been made as we approach the significant milestone of pivoting Mica to an excess free cash flow generating asset. Once we reach the target production of 28,000 barrels a day, which once again could be higher with an accelerated Alberta program, we estimate the free cash flow generation to be in the $125 million to $150 million range and which would be sustainable for 20 years.

And with the strong technical team that we have [Technical Difficulty] working this asset and their continued focus on optimizing the NPV, I fully expect to see these cash flow estimates increase over time. And so with that, I will now pass to Lara Conrad to review how we manage our portfolio.

Hello, and good morning. I am Lara Conrad, VP of Business Development, and I am very much newer to Vermilion than any of my colleagues, having just joined the team here in May. I made the decision to join Vermilion for 2 key reasons. First off, it's due to the strength of the leadership team here. The entire executive leadership shares talent, humility and hard work and the professionals here are top notch. So very excited to be part of this team.

Secondly, this team has made some really important changes to the portfolio, and I want to be part of that. Vermilion is now very well positioned in both Canada and in Europe. From a business development perspective, this means we are not pressured to make major moves on the acquisition and divestiture front. However, with the opportunity set that we have, we will continue to enhance the portfolio by looking at opportunities that increase our profitability, provide synergies and fit within our strategy of our unique group of assets.

This is what makes me very excited to be part of this team. On Slide 55, Vermilion's portfolio could be seen, and it includes assets across the play life cycle. In the [Technical Difficulty], we have exploration opportunities in Germany, infrastructure growth projects in the Montney and a wealth of inventory to sustain production in the Deep Basin. Our excess free cash flow generating international assets in France, Australia and Ireland, while now later in the asset life cycle, enabled Vermilion to build the land positions that we enjoy today in Germany, the Netherlands, Montney and the Deep Basin.

These assets continue to deliver free cash flow [Technical Difficulty] supply funding for infrastructure buildout at Mica and provide returns to shareholders. Vermilion benefits from diversified downstream exposure as a result of the geographies in which our assets are positioned with commodity sales exposure to both North American and international pricing points. We will continue to invest in coring up our current positions.

Vermilion's inventory in the Deep Basin and Montney provides stable base production to support scalable growth in Canada and [Technical Difficulty] in Europe. Additional to organic development, we will continue to actively pursue acquisition opportunities where high netback margins exist. When reviewing these opportunities, careful consideration will be given to value, strategic fit and market conditions.

These considerations support the streamlining of our asset base, which we've already undertaken while ensuring we make value-based decisions on both acquisitions and divestitures. On Slide 56, [Technical Difficulty] that Vermilion has in both international and Canadian markets. This provides us a very unique view as we have in-depth knowledge and understanding of evolving plays and policies in both North America and in European markets, while being a small enough company to be nimble and make decisions efficiently.

We'll pursue opportunities that have synergies in our core areas with the ability to compare and contrast the excess free cash flow margins [Technical Difficulty]. We have had success acquiring international assets from the majors, having built strong global relationships. Having operated in diverse jurisdictions for almost 30 years, the Vermilion team have proven experience in both onshore and offshore environments, have delivered success in exploration wells, development programs and later-in-life field optimization and have delivered significant excess free cash flow from our European and Australian assets.

The quality of the portfolio following our asset high grading, we have raised the bar when looking at acquisition opportunities. We are in a position to build on a strong base and look forward to being able to create additional value in the Vermilion portfolio. Liquids-rich positions will continue to be our focus in Canada, where we have a depth of knowledge in both unconventional and conventional plays.

As Geoff noted, we started amassing our position in the Deep Basin in 1995 and have successfully integrated the [indiscernible] driving significant synergies that were not included in our original evaluation. We will pursue tuck-in acquisitions adjacent to our existing acreage to deliver synergies and maximize value. We entered Europe in 1997, just 2 years after taking a position in the Deep Basin.

We look forward to continuing to pursue acquisitions in Europe that add value and compete with our organic development and additionally support balance between our international assets and main assets in our portfolio. We will safely take care of fields that are later in life. Through rigorous evaluation and disciplined action in our portfolio management, we look forward to enhancing Vermilion's excess free cash flow. I will now pass to Lars Glemser to discuss our outlook and capital allocation.

Thanks, Lara. Good morning. Just a quick coordinate check for those that are online. I understand you are advancing the slides on your own. So under Invest with Us upcoming events, you'll find the slide deck that we're progressing through here. Slide 59 is where we're at. Just as you're navigating there, no disrespect to my colleagues, but this really is the fun part of the presentation where I get to take all of their good work, wrap it up and share it through the corporate lens. So looking forward to that.

I'm Lars Glemser, CFO, and it has been a real pleasure to be part of the Vermilion team for the past 10 years. As referenced in this section, I'll walk you through our outlook and how our capital allocation is driving long-term shareholder value. Over the past hour or so, you've heard how we've repositioned our asset base, and I'm going to pull that together through 3 themes at the corporate level. resilience, sophistication and opportunity.

On resilience, this allows us to thrive through commodity price cycles, not just survive them, and it extends beyond the balance sheet. We then take a sophisticated approach to maximize our revenue and margins through a multiyear strategy supported by our long-duration assets to maximize returns. This position Vermilion uniquely in the capital markets for opportunity. On the global gas front, we have no real peer.

Our decisions are driven by a laser focus on per-share growth, both in production and excess free cash flow, giving us flexibility in the short term and delivering enhanced returns over the long term. On resilience, debt comes in many forms. As shown here on Slide 61, we've addressed it decisively to create both financial and operational resilience. As shown on the left of this slide, we've reduced net debt while repositioning the portfolio over the past 5 years.

By the end of 2026, we expect net debt to production to be down 50% from 2021. And we are committed to strong financial leverage and reducing debt to FFO to a 1x ratio where we have operated for a number of years. We've also strengthened our debt maturity profile. Over the past 3 years, we accessed U.S. public debt markets twice terming most of our debt out to 2030 and 2033 at approximately a 7% interest rate. Today, over 85% of our debt is termed out compared to just 20% in 2020.

In the bottom right, we show the combined impact of debt reduction and extended tenor, which leaves us with over $1 billion in liquidity on our covenant-based revolving credit facility, which is termed out to 2029 and supported by a 14-bank North American syndicate. Commodity cycles will remain volatile. But with this level of financial resilience, we're positioned to emerge stronger from downturns as a result of our repositioning and fully capture upside. Financial strength is only part of the story.

On Slide 62, we show how we've reinforced operational resilience at the same time. On the left, we show the progress we have made over the past 4 years as we significantly reduced the number of wellbores while increasing production per wellbore. The chart on the top right reinforces how we've invested meaningfully in infrastructure, primarily in our Mica asset to unlock long-term resource potential, which will benefit future production additions and EFCF. That investment phase is now winding down.

And post 2026, our focus is shifting to production [Technical Difficulty] adding activities in Mica and bringing gas behind pipe in Germany as well as follow-up drilling in our German discovery to support EFCF growth. Today, we are a larger company and more focused with over 90% of our production concentrated in global gas assets, the areas where we allocate capital. This clarity of focus positions us for the next leg of organic growth and more importantly, for per-share growth in production and excess free cash flow.

We take a technically driven sophisticated approach across the business. Marketing our global gas is a great example of this and how we enhance our realized price. With over 20 years of experience in European gas markets and over 30 years in North America, paired with long-duration assets, we can take a long-term view to optimize revenues. To elaborate on a couple of the examples on this slide, we have a diversified AECO exposure [Technical Difficulty] we have diversified through basis swaps.

We currently have AECO basis swapped from a legacy 10-year trade that -- and we recently added to this with a basis swap for the 2029 to 2035 period. This reduces our AECO exposure in place of Henry Hub, and we continue to evaluate other opportunities to diversify a portion of our gas from AECO to hubs such as Henry Hub and others. We also look to diversify with our physical transport capabilities, and we've recently extended our Alliance pipeline capacity by 10 years to 2035, which gives us access to the Chicago gas market. In addition, we will have capacity on West Coast pipeline beginning late 2026.

On our Mica Montney asset, we have secured pipeline takeaway capacity to produce [Technical Difficulty]. We also locked in firm capacity at a deep-cut plant, giving us 35% liquids weighting and more importantly, a 55% revenue [Technical Difficulty] weighting at Mica's high-value liquids. The result is shown on the right and reinforces the advantage we have with multiple markets that are not necessarily correlated. Our corporate and operational teams work together to maximize the value of our production.

On Slide 64, we show how we have a sophisticated and disciplined approach to hedging that provides market diversification, protecting capital outlays as well as the balance sheet. This all ties to capital allocation and return on capital employed as well as our business development strategy. As an example, we hedged 70% of the acquired production in the 2023 Corrib transaction to affect a less-than-2-year payout and not expose the balance sheet on a cash transaction.

Similarly, our Westbrick acquisition was done in a low gas price environment and the combination of an active hedge strategy on first, WTI and then gas paired with a disposition program was used to manage risk while protecting the balance sheet. This all serves the purpose of backstopping the strategy over the long term and to emerge from downturns in a better position than we went in. Our target is 25% to 50% of production hedged with positions initiated up to 3 years out.

For the period of 2023 to 2025, we expect approximately $700 million in hedge proceeds and have hedged about 40% of our production for 2026. Market diversification is only effective if it impacts the bottom line. And as you can see on the left, the combination of our market exposure and financial hedges results in the highest realized gas price amongst our peers and without the risk of LNG contracts. We think this is the better way to provide investors with exposure to global gas.

At the end of the day, these are all commodities, and they will cycle up and down over the years and overshoot and undershoot [Technical Difficulty] supply. We're not going to make a quick call on where we want exposure for the short term but are building our portfolio for the long term. We see a lot of advantages to having structural long-life resource in Canada and in 2 of the most prolific basins to participate in the North American and global desire to use and export more gas.

Our low cost of supply for European gas growth pairs well and investment today into Germany will set the stage for continued meaningful [Technical Difficulty] European gas volumes once the next decade to ensure meaningful exposure over the coming years to global gas. The opportunity, starting on Slide 65. Investing in the global gas thesis through public companies, it's challenging with limited options, especially in the mid-cap space.

In Canada and the U.S., there are few companies with gas weightings above 50% and even fewer with meaningful global pricing exposure today. Most LNG entities require investment-grade entities to enter supply contracts, and this is due to the longevity and associated risk with those contracts. This limits investor options when seeking high-quality, long-duration resource with global price exposure.

Vermilion stands out as one of the only companies with material global gas exposure and a market cap over $1 billion and the only mid-cap to do it. As North America works to supply gas globally for decades to come and as gas becomes more critical, Vermilion is uniquely positioned. To add to the Vermilion opportunity, shown on the right are production and revenue split ,70% of our production is gas, but the 30% of liquids we produce is high value and predominantly oil and condensate with exposure to Brent and Brent premium pricing in France, Germany and Australia and WTI and condensate pricing in Canada.

Our revenue is almost liquids and gas at 51% gas, 49% liquids, but we retain that meaningful exposure to the rising tide of global gas demand. Slide 66. Recall earlier that Darcy went through our European gas opportunities in Germany. And what we have done here is stack those opportunities against various LNG economics out of North America. Think of this as a cost supply curve. The lower the better [Technical Difficulty] cycles or the upside with [Technical Difficulty] between North American prices.

Canada West Coast LNG is extremely competitive, the most competitive source of LNG supply in North America. This has the potential to provide a tailwind to Canada gas demand and create a new and growing source to compete against our own growing demand requirements and exports to the U.S. This is positive for AECO and provides a direct advantage to Vermilion. For example, as Dion referenced earlier, a $1 increase in AECO pricing, whether through higher Henry Hub or tighter AECO basis translates into more than $130 million in additional EFCF per year.

We will pair this with our low cost of supply global gas. With this chart, we show a couple of data points indicating the cost to produce and ship gas from North America and Europe. More than 50% advantage that Vermilion has to the next lowest cost of supply results in Vermilion providing the most direct exposure to global gas prices and supporting investment into our European gas projects through the cycles without the exposure of long-term contracts.

This combination gives us flexibility to monitor global commodity price signals and invest where returns are strongest. On Slide 67, [Technical Difficulty] portfolio sets us up for meaningful growth, not just in production per-share, but more importantly, free cash flow per-share. Let me remind you how we define EFCF. We do start with funds flow from operations, deduct all exploration and development spending as well as the asset retirement and capital lease obligations.

The investments we've made, Montney infrastructure, derisking Germany and expanding our Deep Basin position structurally improves our ability to generate EFCF [Technical Difficulty] that means per-share EFCF growth that outpaces production growth. And that's a key differentiator for us going forward. As we enter this EFCF realization phase and work towards the $2.75 per-share of EFCF, the yield at our current share price would increase to in excess of 20%. On Slide 68, our return of capital priorities is unchanged, and we will structurally adding EFCF per-share.

Similar to how we have multiple options on the operational front to create value, we have multiple levers to pull to achieve per-share EFCF growth and the optimum approach will shift with the market cycles. We will be flexible. We will balance EFCF allocation between debt reduction, production growth organically and through acquisitions, share buybacks and dividends. As the team has outlined, we are an exciting part of Vermilion operational plans we have shared and a return to historical pricing, there will be ample EFCF to meaningfully reduce debt, reduce the share count and pay a dividend.

To put another way, our projected EFCF over the next 5 years at the price deck we have disclosed is close to our current market capitalization. Slide 69. To wrap up this section, this final slide puts the $1.7 billion of EFCF over the next 5 years in perspective. We will prioritize debt reduction in the short term, which will allow for the potential to allocate more EFCF to shareholder returns over the next 5 years. In addition to the potential $2.70 per-share of dividends over this 5-year period at the current dividend rate, the share count could be reduced by over 30% with net debt well below 1x.

We will also have organic opportunities in the portfolio that can be evaluated against the sale as we have inventory remaining in the Deep Basin and 15 years of inventory remaining in the Montney, and our Germany production will be growing at the end of this 5-year period. We are excited to have this EFCF optionality in the portfolio and we'll relentlessly evaluate the best allocation to support a growing EFCF profile over time. With that, I'll pass it back to Dion.

Thank you, Lars Glemser. Thank you to the team for the presentation today. Organization has done an incredible job delivering on our business plan. So I look forward to 2026 and beyond, again, we are confident that we'll do the same. I want to take this opportunity to sincerely thank everyone in our organization. Their efforts have made this greatly improved outlook possible. In closing, there were 3 items that we kicked off the meeting with.

First, strategically, we have [Technical Difficulty] place with our largest discovery in over a decade in Europe. We've talked the decades of inventory in the Deep Basin and Montney, 2 of the top plays in North America. Second was our focus on what we can control, operational excellence with tangible examples of lower costs in each of our plays as well as production exceeding our tight curves in the Deep Basin.

Third and most critical element, which Lars just touched on, is that excess free cash flow growth per-share with only 153 million shares outstanding, we have the potential to meaningfully double our excess free cash flow to the $2.75 in 2028. We're excited about that level of excess free cash flow, what that can do for return of capital and what that can do for shareholders' appreciation in the stock price. So again, I want to thank you for your time today. That concludes our presentation.

Good morning, ladies and gentlemen, and welcome to the Vermilion Energy Q3 2025 Conference Call. [Operator Instructions] This call is being recorded on Thursday, November 6, 2025. I would now like to turn the conference call over to Mr. 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 the advisory on forward-looking statements in our Q3 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.

Vermilion delivered another strong quarter in Q3, demonstrating both operational excellence and financial discipline. Our production came in at the upper end of our guidance range, and we're able to generate robust fund flows from operations in a challenging commodity price environment. Our performance this quarter reflects improvements in both capital and operating efficiencies, driven by the strategic repositioning of our asset base.

These structural improvements enabled us to lower the top end of our 2025 capital guidance by $20 million without impacting our production. This speaks to the growing efficiency of our capital deployment. In addition, we lowered our full year operating cost guidance by more than $10 million due to the improvements we are realizing in the second half of 2025. This momentum will carry into the 2026 budget guidance, which includes even lower capital and unit operating costs, reflective of our larger, more cored up portfolio.

When compared to 2024, the last full year before we launched our asset high-grading initiative, our production per share has increased by over 40%, where our unit cost structure is down by 30%. This reflects the strength of our repositioned portfolio where 85% of both production and capital is now concentrated in our global gas business. By focusing on these more efficient, longer duration assets, we have better positioned Vermilion for sustainable long-term success.

Our Q3 results underscore the resilience and the competitive strength of our differentiated asset base. Notably, our realized gas price in the quarter, excluding hedging gains, was $4.36 per Mcf, significantly outperforming the AECO 5A pricing. In Canada, we realized a gas price that was more than double the AECO benchmark. And when combined with our direct exposure to premium priced European gas, our realized pricing is 7x the AECO benchmark.

When you include hedging gains, the realized price increased to $5.62 per Mcf, 9x the AECO benchmark, highlighting the strategic advantage of being a global gas producer. During the quarter, we made a deliberate and strategic choice to temporarily shut in a portion of our Deep Basin gas production and defer the start-up of several wells, resulting in approximately 3,000 BOEs per day of production impact in the quarter. We expect to bring these volumes online in Q4, where pricing is more favorable.

During the quarter, we met a portion of our volume commitments by purchasing rather than producing our own gas, demonstrating our commitment to profitable development. We continue to make progress towards key milestones with the development of our global gas assets in Germany, the Montney and the Deep Basin. In Germany, in 2026, we will bring our discovery well at Wisselshorst online and look to expand takeaway capacity over the next 2 years to maximize the economics of this prolific well.

We will also advance our plans to spud the follow-up Wisselshorst structure in early 2027 and with a shorter cycle time than our initial exploration well, plan to bring these wells on production in the second half of 2028. In Canada, we will continue to invest in the Montney asset, as we progress towards a significant inflection in free cash flow in 2028. In the Deep Basin, we will run an efficient, consistent 3-rig program and generate strong free cash flow by producing volumes into our existing infrastructure.

As we look out over the next 3 years, these projects will significantly improve our free cash flow outlook. I will now pass it over to Lars to discuss the Q3 results as well as our 2026 budget guidance.

Thank you, Dion. Vermilion generated $254 million in fund flows from operations in Q3 with free cash flow of $108 million after E&D capital expenditures of $146 million. We continue to reduce debt during the quarter and have now reduced our net debt by over $650 million since Q1 2025, bringing net debt to under $1.4 billion as of September 30. This resulted in a net debt to 4-quarter trailing FFO ratio of 1.4x, reflecting continued progress towards strengthening Vermilion's balance sheet.

In addition, Vermilion returned $26 million to shareholders through dividends and share buybacks. comprising $20 million in dividends and $6 million of share buybacks during the quarter. This resulted in the company repurchasing 600,000 shares for a total of 2.5 million shares repurchased year-to-date. In total, we have repurchased approximately 20 million shares since mid-2022. Q3 production averaged 119,062 BOE per day with a 67% gas weighting, which was at the upper end of our guidance range.

In North America, production averaged 88,763 BOE per day, inclusive of the July divestments of our Saskatchewan and U.S. assets. as well as shut-in gas production and deferral of new well start-ups in Q3 in response to pricing. International operations averaged 30,299 BOE per day, up 2% from the previous quarter due to strong performance across our business units.

In the Deep Basin, we ramped up to a 3-rig drilling program in Q3, targeting multiple stack zones across our 1.1 million net acre land base. We drilled 13, completed 12 and brought on production 3 gross liquids-rich gas wells in the Deep Basin. The drill program results to date are exceeding our expectations with test rates indicating deliverability well in excess of our type curves.

Internationally, we executed a successful 2 gross or 1.2 net well drilling program in the Netherlands, discovering commercial gas across 2 zones, the Rotliegend and Zechstein. Both wells are expected to be completed, tied in and brought on production in Q4 of 2025. These 2 wells are the latest successes in our 2-plus decades of exploration and development in the Netherlands and combined with recent discoveries in Germany, demonstrate Vermilion's broader European gas exploration capabilities to repeatedly add European gas reserves at a cost of $1.50 per Mcf into a gas market currently in excess of $15 per Mcf.

Meanwhile, Osterheide, our first German exploration well continues to produce at a restricted rate of 1,100 BOE per day, generating nearly $2 million per month of excess free cash flow. And our second well, Wisselshorst, is on track for start-up by mid-2026, with preparations underway for follow-up drilling of 2 gross or 1.3 net wells in the Wisselshorst structure. As a reminder, the first well is expected to recover 68 Bcf of gas and our P50 estimate of gross gas in place for the structure is 380 Bcf. We also released our 2026 budget yesterday, featuring an exploration and development capital budget of $600 million to $630 million with approximately 85% allocated to our global gas portfolio.

Key investments include drilling and strategic infrastructure in the Montney, a continuous drilling program targeting high-return liquids-rich gas wells in the Deep Basin and drilling and infrastructure capital in Germany and the Netherlands. We expect modest production growth from second half 2025 levels on our continuing operations with annual average production between 118,000 and 122,000 BOE per day, maintaining our commitment to financial discipline and free cash flow generation.

Our 2026 budget includes a significant reduction in our overall cost structure with a 30% improvement in capital and operating efficiencies, reflecting the benefits of our repositioned global gas portfolio and our focus on operational excellence. For 2026, we plan to invest approximately $415 million into liquids-rich gas assets in the Montney and Deep Basin, drilling 49 gross wells, which translates to approximately 45 net wells, reflecting our high working interest in Canada.

In the Deep Basin, we plan to run a 3-rig program to drill 43 gross wells. Notably, minimal new infrastructure spending is required to support this development, which is a key advantage of our Deep Basin asset. In the Montney, we plan to drill 6 and complete and bring on production 10 wells. In addition, we will continue to expand our infrastructure in advance of total Montney throughput growing to 28,000 BOE per day by 2028, which aligns with the build-out of third-party gas infrastructure.

Once we achieve target production, infrastructure and drilling capital requirements will decrease, as we expect to drill about 8 wells per year to sustain production. The combination of higher production and lower capital will pivot the Montney asset to significant excess free cash flow of approximately $125 million per year for 15-plus years, assuming commodity prices of $3 AECO and $70 WTI. Internationally, we plan to invest around $200 million in 2026, focusing on European gas exploration and development and optimizing base production.

This includes drilling 1 well at a 50% working interest in the Netherlands and preparing for 2 additional follow-up wells at 64% working interest at the Wisselshorst discovery in Germany in early Q1 2027. We will bring the initial Wisselshorst well online mid-2026 and expand the supporting infrastructure to enable significantly higher production over the next 2 years. We will also invest in economic workovers and optimization projects across our international assets.

Higher maintenance spending in 2026 compared to prior years is due to nonrecurring turnarounds, including a planned 32-day turnaround in Ireland, the scope of which is scheduled to occur every 5 years. Our priorities on shareholder returns remain unchanged. We will use excess free cash flow to maintain a strong balance sheet, fund a sustainable base dividend and be opportunistic with share buybacks. I'm pleased to announce our intention to increase the quarterly cash dividend by 4% to CAD 0.135 per share, effective with the Q1 2026 dividend.

The dividend payout remains at a modest level even during this commodity price period, and we see the potential for higher return of capital, as free cash flow increases in the Montney, Germany and Deep Basin. I will now pass it back to Dion.

Thank you, Lars. Looking ahead, Q4 will mark the first full quarter of our repositioned global gas portfolio, following an active year of acquisition and disposition activity. We expect fourth quarter production to average between 119,000 and 121,000 BOEs per day, inclusive of the decision to defer the start-up of multiple wells. Based on this performance, our 2025 full year production guidance is expected to be 119,500 BOEs per day.

Importantly, we're able to maintain this production outlook, while reducing our E&D capital guidance to between $630 million and $640 million. The $20 million reduction at the top end of our guidance reflects continued improvement in capital efficiency. The capital reduction aligns with the improvement in operating costs, enabling a $10 million reduction in operating cost guidance.

We're now entering the next phase of our strategy with a larger, more focused asset base, one that's characterized by longer duration assets, high-return drilling inventory, a more efficient cost structure and a top decile realized gas price. With proven success in exploration and development across our portfolio, the plan to increase free cash flow in our key development assets and an improving outlook for natural gas pricing, Vermilion is very well positioned for the future.

In closing, I want to thank the entire Vermilion team for your efforts over the past year in creating our high-grade portfolio and realizing strong efficiencies throughout the business. It's truly been a heavy lift by all, and I'm extremely proud of your work of our team. With that, thank you. We'll now open the line for questions.

[Operator Instructions] And your first question comes from Travis Wood from National Bank Capital Markets.

Could you provide some additional color or further color around Australia in terms of kind of where current volumes would be sitting at and how you're setting that asset up through 2026 and potentially into 2027 with incremental drills and what that capital would look like?

Thanks, Travis. It's Dion. I'll take the call. Yes, Australia, as you know, is a premium pricing there. We get USD 10 to USD 15 premium to Brent pricing, which helps our netbacks. The last year here, we've been focused on optimizing the platform and frankly, getting ahead on some of our maintenance. We're well advanced on that. With respect to the next drilling program, we drill every 2 to 4 years. Tentatively, we planned the next drill for 2027. But frankly, we have flexibility on that depending on rig rates as well as commodity price environment. So we'll be at around 4,000 barrels per day currently, probably drift a little lower next year and then set up for that drilling program likely in kind of mid-2027.

Okay. Perfect. And then probably for Lars, you gave a modest dividend bump on the back of the quarter. How -- and I think you've walked through this before, but just to remind us, what -- or rather, how are you finding that balance of buying back more stock at this valuation versus kind of the base dividend growth, as you look out on the 2026 budget and flexing some optionality around commodity prices, too, I guess.

Yes. For sure, Travis. Thanks for the question. I think at the end of the day, what we're really focused on is things that we can control and driving per share value. We've got a number of ways to drive per share value. I would say that share buybacks is one of those ways to do it. There are other options as well. And if you kind of look at the portfolio now, we're getting a lot of this infrastructure spend in the Montney behind us. We've got a lot of infrastructure to fill up in the Deep Basin.

We've been able to derisk some of these exploration projects in Germany as well. And we want to balance that operational momentum with return of capital as well in delivering per share value over the longer term. Part of that is to continue strengthening the balance sheet as well and so we will have a chunk of our excess free cash flow reserve for debt reduction in 2026 as well. I think the dividend increase that should be viewed as confidence in a lot of these operational activities that we're executing on as well. And in addition to that, we will continue to buy back shares and be opportunistic on that front.

There are no further questions at this time. I'd like to turn the conference call back over to Dion Hatcher for further questions.

Great. I'm going to pass it back to Travis here. I know we had some questions on the Inbox from IR. So maybe we can work through a couple of those.

Yes, for sure. Thanks, Dion. First one, just for Lars here. So you mentioned in the release a realized gas price of about 7x the AECO price in the quarter. Can you please help me understand the drivers behind this?

Yes, for sure. Thanks, Travis, for the question. Zooming out here, a lot has changed with the portfolio in terms of the repositioning that we have done. Something that has not changed is we continue to have a very diverse portfolio. And so if you start with that AECO benchmark price, which is the price a lot of our peers use as well in terms of how do we do relative to that.

It's not just the European assets that are contributing to a strong corporate realized price. So here in Canada, we actually realized the price in the third quarter of $1.37 per Mcf, which was more than double the AECO benchmark. We've got an active program in terms of selling into the daily and the monthly price index as well. We also have over 26 million Mcf a day exposed to the Chicago market as well. So we're well diversified within our Canadian portfolio.

We were also able to strategically shut in and defer wells without meaningfully impacting the liquids production in our Canadian business as well. So a combination of all these led to that outperformance. When you combine the strong Canadian business with our European gas business, that's where you really start to see the impact and benefits of a diversified portfolio. And so the impact of that is we end up with a realized price of $4.36 per Mcf before hedges.

Say before hedges, we do have an active hedging program, both here in Canada as well as European gas. The majority of our hedge gain in the third quarter was driven by our gas hedges. When you combine that with the realized price, we get up to $5.62 per Mcf. So a really strong quarter, really shows the benefits of that diversified portfolio, and we are organically investing in both the Canadian assets as well as the European assets.

Just a reminder as well, Travis, as we move into 2026 here, I think it's worth noting that a $1 increase in that AECO price, it would effectively add $100 million of excess free cash flow. So lots of exposure to that AECO price and still lots of exposure to the TTF price as well. A $1 improvement in that TTF marker would add about $24 million of excess free cash flow. So we feel that Vermilion is very well positioned to benefit from improving gas prices here to 2026.

Yes. The only thing I can add to that, I think it's worth walking through the details because, again, it was 9x the AECO benchmark. So it's worth thinking through how we're able to deliver that with our differentiated portfolio, but back to you, Travis.

Thanks, Dion, Lars. Next couple here for Darcy. Could you provide more background on the next steps of the Wisselshorst prospect in Germany? What are the debottlenecking plans? And how are you thinking about drilling follow-up locations there?

Yes. Thanks, Travis. So in Germany at Wisselshorst, as you know, we have the one discovery well, we call, Wisselshorst Z1a that tested at pretty prolific rates, so a combined test rate of slightly over 40 million cubic feet a day. Our intention is to have that well tied in and producing by Q2 of next year, so Q2 of 2026. I think we've talked before that, that initial rate kind of ties into a more local gathering system that will be restricted for some time, but we expect that those restrictions start to go away in 2027, allowing us to bring production kind of up into that 17.5 million cubic feet a day.

And then there's some additional debottlenecking options that we expect to have online in 2028 that doubles that to 35 million a day. So that kind of talks about that first discovery well. So on the back of that successful discovery well, we see a number of follow-up locations. We intend to spud 2 of those, so the second and third well into the Wisselshorst structure in January 2027. Timing is partially driven by our ability to secure the rig that we want to use to drill those wells and really doesn't impact our expectation around online time. We expect to get those wells drilled kind of through the first half of 2027 and expect them tied in and producing by second half of 2028.

So maybe I can summarize that. Like I think the takeaway, it's quite interesting. We're excited about Germany, but the simple math is the 1.6 net wells that we drilled with Osterheide and the Wisselshorst well that will come on mid next year, that's going to add about 25 million a day of gas, which is, again, about 25% of our production. The 2 wells that Darcy just walked us through, the 2 Wisselshorst follow-up wells, that will be 1.3 net wells.

So once those are on in the second half of '28, that will be another 20-plus million a day of gas. So if you zoom out 3 net wells, it's going to add about 45 million a day of gas, which is almost half of all our European gas production. So again, that's why we're excited about Germany, just materiality of these wells and kudos to the team to be able to get the rig we wanted and do all the preplanning to really reduce that cycle time. So thanks for that, Darcy.

And then the next one here for Darcy, jumping to the Netherlands. A couple of discoveries in the quarter. Could you give a bit more background on what we're seeing there?

Yes. So in the Netherlands, we drilled 2 successful wells in a field called Oppenhuizen. We discovered gas in 2 zones in each of those wells. We discovered gas in the Rotliegend and Zechstein formations, 2 of the primary formations that we do chase in the Netherlands. We've discovered about 16 Bcf gross of recoverable gas and the F&D costs for those wells are less than $1.50 per Mcf.

We talked about tying those wells in Q4 of this year. So both wells are tied into existing facilities now. We're currently producing the first of those 2 wells at a rate of about 15 million cubic feet per day, limited by surface constraints at that location. And we intend to kind of bring the second well on as capacity opens up there.

Okay. And then the last one here over to Randy. You noted the Q3 drilling program in the Deep Basin has exceeded expectations so far. Can you provide a bit more color on what we're seeing to date in the results?

Sure. Yes. So yes, as Lars had mentioned, we completed 12 wells in Q3. Of these 12 wells, 6 of them tested at over 10 million a day of gas production. And then we also had some strong liquid rates from the other wells in the program. With our focus on profitability, most of these wells were deferred and will be coming on production over the next month. So we'll have a better sense of performance, but those initial test results definitely exceeded our expectations.

And then when we think about it on the capital front, the program also did come in under budget, and that's really what we're starting to see is the cost benefits of running a consistent 3-rig drilling program, which we plan to, as we noted in the call, through '26 and into '27. So overall, very pleased with the results of this program.

Thanks, Randy. Dion, back to you. That's all we have for additional questions.

Thanks, Travis. So with that, I'd like to thank everyone again for participating in our Q3 results conference call. Enjoy the rest of your day.

Thank you. Ladies and gentlemen, this does conclude your conference call for today. We thank you very much for your participation, and you may now disconnect. Have a great day.