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…

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,…

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.