Vermilion Energy Inc. Q4 FY2025 earnings call

• Vermilion had impactful 2025, positioning as global gas producer with top decile realized gas prices, lower cost structure, and long-duration asset base.
• Through A&D activity, portfolio focused on liquids-rich gas in Canada and premium-priced gas in Europe. In Germany, Osterheide well brought online, Bissehorst expected mid-2026; Netherlands had two wells brought on production in Q4.
• Q4 production 121,308 BOE per day ahead of guidance, driven by productive deep basin wells, Montney volumes, and Osterhout well in Germany generating $8M free cash flow in Q4.
• Strong realized gas pricing due to direct European gas exposure, market diversification in Canada, and hedging program. Operational focus on safety, production, and cost management, with Canadian unit operating costs at lowest in over a decade.
• Reserves increased 36% to 592 million BUEs, with PDP and 2P reserves growth, and significant upside in European gas reserves.

In Q4, Vermilion had production of 121,308 BOE per day, with 69% weighting to natural gas. Canadian operations saw production increase due to productive wells in deep basin, Montney volumes, and lower unit operating costs. International operations averaged 30,137 BOE per day, with new production in Netherlands and increased gas output in Germany offsetting declines in other regions. Canadian unit operating costs are the lowest in over a decade. European assets like Osterheide and Bissehorst had progress, with Bissehorst expected online mid-2026. Reserves increased by 36% to 592 million BUEs, with PDP and 2P reserves growth driven by organic development and acquisitions, offset by divestments.

• Q1 outlook 122,000 - 124,000 BOE per day factoring in Australia's cyclone-related downtime.
• Expect production in first half of 2026 in line with recent levels, lower Q3 production due to planned maintenance.
• Material free cash flow inflection starting in 2028, with ramp up in Germany volumes and Montney production contributing, and updated slide deck showing FFO for 2026 around $950 million, a 40% increase to excess free cash flow.

• Australia's WANDU platform impacted by Category 3 cyclone causing minor damage and delay of crude export lifting, with regulator interaction and planned maintenance involved.
• Negative technical revisions on 1P and 2P sides of North America and international, due to high-grading reserves book and shifting development plans.

Q: At your investor day in December, how would you frame pre-cash flow inflection in 2028 relative to what you were talking about in December?

A: When at investor day used 70 WTI, 350 ECO and 13 CAD for TTF, inflection driven by ramp up in Germany volumes and Montney production, running at about 270 per share of excess free cash flow then, and updated slide deck shows FFO for 2026 around $950 million, 40% increase to excess free cash flow.

Q: Are there opportunities to hedge further and is there a scenario where you hedge more aggressively than you have in the past?

A: About 50% hedged on European gas for 2026, 53% on oil, and 45% on North American gas, have been active hedging European gas recently, and in past have taken hedge percentage up to 70% if see opportunity to lock in revenue.

Q: On the deep basin well outperformance, 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?

A: Results from deep basin drill program continued to perform, current three rig program also exceeded expectations, speaks to depth of inventory, and based on results to date, chance for well outperformers to continue above type curve.

Q: Can you provide a little more granularity in when you expect Australian volumes to ramp back up to their previous production levels?

A: Tropical cyclone and regulator issues caused delay, managed to export over 300,000 barrels in late February, plan to have things back to normal by Q2.

Q: Could you just provide a little color behind the negative technical revisions on the 1P, 2P side of both North America and international?

A: Negative technicals result from high-grading reserves book due to M&A activity, replaced locations with better profitability, and minor negative technicals in Netherlands, Germany, and France due to shifting development plans and capital allocation decisions prioritizing Canada and deep basin in Mani and Germany.

Q: 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? And then we've got one more follow-up question here as well.

A: Look at everything, think there's interesting opportunities both in Canada and in Europe, core up portfolio, M&A will be part of that when see right opportunities. Follow-up: When these better wells were coming out of the deep basin, 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?

A: It's the rock, combination of legacy land position, high-performing teams, ability to extend wells, and optimal land position from M&A activity, nothing different in drill or completion design, really comes down to geology and optimal land position.

Q: My first one is just around Osterhide. Obviously, that's fantastic to see the incremental uplift in terms of the production. As I recall, 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?

A: Infrastructure constraints assumed not as negative as initially thought, expect production rates seen to continue flat through 2026 with some day-to-day market variation, but more capacity in system and market desire for gas, so expect durability.

Q: 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 timelines? I know that's been we'll call it a 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?

A: Messages about benefits of domestic production in Europe falling on more open ears, seen commitments from Dutch regulator to stick to timelines, progressing well on vessel source with gas plant installation and pipeline tie-in, still on schedule to start up mid year, and opportunities are bigger step out exploration type opportunities with 70% success rate in previous exploration drilling.

Q: 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 late 26 or 27 for growth in those areas.

A: No drilling activity planned in Ireland, focus on optimizing existing asset generating strong free cash flow. For Croatia, decided to divest and focus elsewhere as Germany is a better investment opportunity, so no plans to allocate capital to drilling in Croatia for growth in late 26 or 27.