Good morning, ladies and gentlemen. Welcome to the Vermilion Energy Q2, 2025 Conference Call. This call is being recorded on Friday, August 8, 2025. I would now like to turn the call over to Mr. Dion Hatcher. Please go ahead.

Thank you, Kelsey. 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 McQuade, Vice President, North America; Lara Conrad, Vice President, Business Development; and Kyle Preston, Vice President of Investor Relations. Please refer to our advisory and forward-looking statements in our Q2 release. It describes forward-looking information, non-GAAP measures and oil and gas terms used today. And it relies on risk factors and assumptions relevant to this discussion. Vermilion delivered strong second quarter results. Production for Q2 averaged 136,000 BOEs per day, representing a 32% increase from the prior quarter, mainly due to a full quarter contribution from the Westbrick acquisition that closed in February. Subsequent to the second quarter, we closed both of the previously announced Saskatchewan and U.S. asset sales for a combined gross proceeds of $535 million, which has been allocated to debt reduction. These divestments were a key component of Vermilion's broader strategic transition towards becoming a global gas producer. Enabling us to enhance operational scale and long-duration assets and better position the company for sustainable, profitable growth. Vermilion now has a production base of approximately 120,000 BOEs per day, 70% weighted to natural gas with over 90% of our production coming from our global gas assets, which include liquids-rich gas in Canada and high netback gas in Europe. We expect over 80% of our future capital investment will be directed towards these global gas assets, which will be the primary growth drivers within our portfolio. We generated $260 million of fund flows from operations and $144 million of free cash flow in Q2 after deducting E&D capital expenditures. Capital expenditures were down from the previous quarter due to the seasonality of drilling activity in Western Canada and a deferral of some E&D capital associated with the Saskatchewan and U.S. assets. Activity during Q2 was focused on our global gas assets in the Mica, Montney, Alberta Deep Basin and Germany. At Mica, Vermilion completed 5 and brought on production and 11 liquids-rich Montney wells. Montney production averaged approximately 15,000 BOEs per day in Q2, which includes production from new wells and increased takeaway capacity from the operated infrastructure expansion that was completed earlier this year. Production from our 2 most recent pads continues to be in line with our expectations. Our operations teams are always focused on continuous improvement. And through these efforts, we were able to achieve a new cost benchmark for our Montney wells with our drilling completions, equipment tie-in costs coming in at approximately $8.5 million per well for the 2 most recent pads. These cost reductions were mainly driven by reduced trucking due to our water infrastructure, reduced tester costs due to optimized flowback and lower drilling costs due to faster fuel times. This is a reduction of $0.5 million per well from our prior target and over $1 million per well compared to just 1 year ago. We are confident we can turn our new cost benchmark of $8.5 million per well into our program average, which will reduce future development costs and improve full cycle returns on our Montney development. With the second expansion phase that Mica and now complete, our Montney team is now planning for the third and final expansion phase. We plan to invest approximately $100 million in the additional infrastructure and gathering pipelines over the next few years, along with drilling another 40 wells over this time frame to reach our targeted production rate 28,000 BOEs per day by 2028. Once we get to this level, we anticipate drilling approximately 8 wells per year to maintain this production level for over 15 years, which translates to generating approximately $125 million to $150 million of annual free cash flow assuming a price of $70 WTI and $3 AECO. In the Deep Basin, we executed a 1 rig program during the quarter and drilled 4, completed 3 and brought on production 3 liquids-rich wells. We plan to add 2 rigs and execute a 3-rig program during the second half of '25 as we ramp up activity heading into the winter. We're very pleased with how the integration of Westbrick assets has unfolded, and we continue to identify further upside. Including proving up new locations, reducing our service costs, and processing costs. As a result, in Q2, the first full quarter of operating these new assets, the team has identified another $100 million of synergies that now brings a total to date over $200 million on an NPV10 basis of synergies post-acquisition. This clearly demonstrates the benefit of our dominant and continuous Latin basin and the Deep Basin and our continued focus on enhancing profitability. Following the divestment of our Saskatchewan and U.S. assets and the continued integration of the Westbrick acquisition, we have taken additional steps to further streamline the business by reorganizing our Canadian business unit. This has led to dedicated technical corporate teams concentrating exclusively on our liquids-rich assets in the Deep Basin and the Montney. In Germany, we drilled, completed, and brought on production 2 oil wells. These high-return wells have initial rates in the 100 to 200 barrels of oil per day range, but they represent low-risk waterfall development opportunities in Germany. Facility and tie-in activity on the Osterheide deep gas well was completed at the end of Q1 and the well averaged approximately 1,100 BOEs per day in Q2, which is above our original constrained expectations due to stronger-than-anticipated seasonal demand. We continue to advance the permitting and infrastructure expansion plans for the first Wisselshorst well, which remains on schedule for tie-in and start-up during the first half of '26. The team continues to work on the full field development plans for our deep gas prospects in Germany, where we are excited about the long-term growth potential from this asset. These prolific wells, combined with strong European gas prices currently over $15 per MMBtu will translate to significant free cash flow for Vermilion in the future. In addition to the organic development in Germany, we will continue to evaluate opportunities in our core European operations, specifically pursuing European gas acquisition opportunities that complement our existing portfolio and enhance value for our shareholders. We also achieved a significant milestone on the sustainability front, achieving our Scope 1 emission reduction target 1 year ahead of plan. In 2021, we set a target to reduce Scope 1 emissions intensity by 15% to 20% compared to the 2019 intensity levels. We achieved this target of a 16% reduction at the end of 2024. Moving forward, we are well positioned for our 2030 target, a goal of reducing Scope 1 plus Scope 2 emission intensities by 25% to 30% versus our 2019 levels. The first half of 2025 was 1 of the busiest times in Vermilion's history as we executed on our portfolio enhancement strategy. We successfully closed our largest ever production acquisition and divested our North American oil-weighted assets. Through these high-grading initiatives, Vermilion now has a much more focused and resilient asset base underpinned by high return development opportunities, unique exposure to premium price European gas, and a lower cost structure. We believe this more efficient, more resilient business will drive significant shareholder value over the longer term. I am especially proud that during this very busy period of integration and divestment, we remain focused on operational excellence. Since the start of the year, we have identified Montney drill cost, equipment timing savings, and synergies related to the Westbrick acquisition were combined $300 million on an NPV10 basis with only 154 million shares outstanding, that equates to approximately $2 per share of value. We also maintained a strong safety record across our operations through this period, a true testament to our commitment of sending everyone home safe every day. Second half of '25 will be an active period as we add 2 additional rigs to our Deep Basin program and commence drilling 2 wells in the Netherlands. Factoring in the timing of the July divestments combined with the planned seasonal turnaround activity and some shutting gas to the low summer AECO prices, we expect Q3 production to average between 117,000 to 120,000 BOEs per day. Our full year production guidance of 117,000 to 122,000 BOEs per day and capital guidance of $630 million to $660 million remain unchanged. However, we do have the flexibility to decrease spending if necessary. We expect to end 2025 with approximately $1.3 billion of net debt. That's a decrease of $750 million from Q1, reflecting the inorganic deleveraging from asset divestments and organic deleveraging over the balance of the year. We continue to balance debt repayment and shareholder returns, currently 60% and 40% of excess free cash flow, respectively. We expect to be in a position to increase shareholder returns as debt trends towards the $1 billion level. In periods of commodity volatility, we're able to lean on our hedge book, where we have over 50% of our corporate production hedged for 2025 and over 40% hedged for '26. In particular, we are very well protected during the current period of weak AECO pricing with approximately 60% of our Q3 Canadian gas hedged at an average floor price of $2.65 per Mcf. It's worth noting our realized gas price in Q2 was $4.88 per Mcf versus AECO of $1.69. This shows the competitive advantage of our unique gas portfolio. For context, our European gas volumes represent 20% of our gas production, but that gas was sold directly into the European market for a price that was 10 times higher than April in Q2. As we look at the next few years, our efforts will continue to focus on our key growth assets, Montney, Deep Basin, and Germany. In the Montney, we will build the final phase of our infrastructure to support our target production rate of 28,000 BOEs per day, 1/3 of that volume being liquids. We expect to hit that target by 2028. In the Deep Basin, we'll focus on optimizing our development of a larger, high-graded asset base, while in Germany, we will continue to progress our deep gas exploration program, where we expect to grow production to over 10,000 BOEs per day in the coming years. Over this period of investment, we will continue to prioritize free cash flow generation, supporting both organic debt reduction and continued shareholder returns. We look forward to the coming quarters for the picture of Vermilion as a global gas producer will become clearer following this busy period of A&D activity. We believe the company is now better positioned to drive long-term shareholder value with a more focused on a longer-duration asset base and an improved cost structure, combined with structural tailwinds for natural gas around the world. With that, we'll now move to the Q&A.

And your first question comes from Greg Pardy from RBC Capital Markets.

Thank you, Dion, for the overview. I wanted to ask you about two points you mentioned in your opening remarks. Regarding the streamlining of the portfolio, there has definitely been progress in certain areas. However, you still have several smaller assets or less core operations, including some in Europe. I’m interested in what’s next for reshaping the portfolio and where those efforts will be focused.

Thanks, Greg, for the question. Yes, no, I think you're right. If you think about Canada, of course, we've exited U.S. and we've exited Saskatchewan and I think we're going to see the benefits with improved capital efficiency and lower cost structure as we look forward. As we look to Europe, we have announced earlier this year that we're exiting Hungary, and we're well in the progress of making that happen. We did also have some interest in Slovakia, which we decided not to pursue. And so that is another couple of jurisdictions that we're deciding not to allocate capital to go forward. And then finally, Croatia, of course, is an area where we've had some success. We've drilled some good wells. We have some production. And also on the SA 7 block, we did have some exploration success, but that is yet another area that we're looking at to although we've got a very strong technical team, and I think a pretty interesting land base. We'll test the market maybe on some retention value for that asset, especially given the capital allocation decisions we have in front of us with the success in Germany, some of the drilling opportunities in Netherlands, and of course long suite of projects that we've got in North America. So we're not done yet, Greg, to answer your question. And I think you're going to see a continued focus on making the business more streamlined, which will improve our capital efficiency and our cost structure.

Okay. Regarding shareholder returns, if you were at $1 billion today, how might that impact the value? I'm trying to understand where the payout ratio might go. Is there a preference for dividends or buybacks? I’m assuming maybe buybacks given your valuation, but I’m curious about your thoughts on this.

Yes. No, thanks. I'm going to pass it over to Lars to walk us through that.

Thank you, Dion. Regarding shareholder returns, we have been quite open and transparent over the past couple of years. We have been returning 50% of our excess free cash flow. Last year, we made a significant acquisition with Westbrick, which was primarily funded through our balance sheet at the time of the acquisition, along with the asset sales Dion mentioned in the U.S. and Saskatchewan. Because this acquisition was cash-funded, we lowered the return of capital to 40% of excess free cash flow. We have been repurchasing some shares this year and are comfortable with the 40% level as we reduce our debt and aim to achieve 1x leverage. In terms of dividends, we still favor steady annual increases, but we do not expect the 20% to 25% hikes seen in previous years. Therefore, we will prioritize share buybacks with any additional return of capital beyond the dividend.

And your next question comes from Menno Hulshof from TD Cowen.

I'll start with a question on the Westbrick synergies. Can we perhaps get a more detailed breakdown on what drove the increase to the estimate, the $200 million? And if there is upside beyond your new estimate, where is that most likely to come from?

Thanks, Menno, for that. I can't wait to talk about it, but I'm going to pass it over to Randy to walk us through some of those synergies that we're seeing.

Yes, as Dion mentioned, we have identified approximately $200 million in net present value synergies. We anticipate realizing about two-thirds of this amount over the next five years. In the Q1 announcement, we detailed the first $100 million, which was primarily related to development and operational synergies, including drilling extended reach wells to optimize production and reduce operating costs. The additional $100 million we are announcing in the Q2 call pertains to the reorganization of the Canadian operations, driven by efficiencies from combining Westbrick with our existing teams. We are also looking at reduced drilling and service costs due to the scale of our combined programs, along with decreased processing fees through ongoing negotiations with third parties. Overall, we estimate around $30 million in annual savings, which is quite significant. We plan to allocate about one-third of this to capital expenditures and two-thirds to operational expenses. We are pleased with the progress made so far, and the team continues to work on integrating Westbrick. We expect to uncover more synergies as we further integrate the companies.

Thanks, Randy. Yes, to summarize, I think we're really seeing, like if you looked at that image we published at the time of the announcement on December 23, the sheer synergies around land touching each other, offsetting infrastructure. And so the team is having more time to work with it. And we're talking, again, $30 million a year of savings, which EMP bill, and all that, as Randy was saying, is how we got to that $200 million number, but great work by Randy and the team to start to realize some of these synergies.

Yes, it's undeniable that it's a very strong number. Moving on, could you provide an update on the acquisition potential in Europe? Are there any packages expected to come to market soon? Also, a refresher on your funding approach would be helpful.

Thanks, Menno. We still see the potential. As a reminder, we're 5% of the market in Netherlands and Germany, and a lot of that other 90%, 95%, I should say, is owned and controlled by the majors, and then they position their intention to over time to divest. The one, of course, we've talked about the most is in the Netherlands, and I think that is still their intention to divest of those onshore assets, and we're quite well positioned given our history there, and we're the second-largest operator. As to funding, and Lars, feel free to jump in here. The unique thing about these opportunities, and I think Corb was the poster child where the headline number to acquire those assets at the time was $600 million, but the cash to close when you closed 15 months later, it was about $200 million. So when we think about our ability to do deals in Europe, we are deleveraging by the day with approximately $750 million off the balance sheet here this year. But also the time to close and the type of assets that we would buy, which are typically high free cash flow generation, we feel really, really comfortable about our ability to be able to finance those. But Menno, give me a thumbs up or good there Menno.

And your next question comes from Chris Worley from Hughes Fund Management.

I want to ask a little bit about Q3 CapEx. There was a lot of CapEx from Q2 that's clearly getting deferred. It looks like. So can you just kind of talk through what happened with those deferrals? And maybe like which parts of the development plan got deferred and sort of like how well those deferred dollars get spent in Q3 and Q4?

I'm going to pass it to Lars for a couple of comments. There is some seasonality we've discussed, particularly in Canada where things tend to slow down during breakup. We are adding two additional rigs in the Deep Basin and currently drilling in the Netherlands. I believe you will notice a change in that activity. Now, I'll pass it over to Lars for more details.

Yes. Thanks, Dion. Chris, maybe just a couple of data points as well to level set, and then I'll provide a little bit of perspective here. So Q2 was a strong quarter. As you heard from Randy, a really successful integration. We're starting to see the synergies come to fruition as well. What we did in the second quarter is we started to pull back on investment in some of the non-core assets that were announced as being sold. So Saskatchewan and the U.S. to help prioritize debt reduction. I don't think that can be understated as well or overstated in terms of our net debt number at Q1. We're now at $1.4 billion. That's a combination of both the disposition proceeds and the fact that we were able to defer some capital on those non-core assets. So just to level set here, we have invested $297 million year-to-date. As you referenced, Q2 was a lower spend quarter with $115 million spent. You have lower activity levels due to spring breakup here in Western Canada. We are on track to spend $630 million to $660 million for the year. That includes $23 million on the sold assets. When we look at our current forecasting, we're trending to be at the lower end of that guidance range, so closer to the $630 million level, which includes the $23 million of investment on sold assets. That number is $100 million lower than our previous guidance. What that means going forward here for the second half and into 2026 is a capital run rate in the low-600s is not a bad way to think about annual spend. And then just in terms of the third quarter coming up here, we provided some guidance in the release here to expect production in that range of 117,000 to 120,000 barrels a day to put that into context. 2024 production was 84,500 on $623 million of capital. We're guiding to 117 million to 120 million for the third quarter here, and an annual run rate in the low $600s of capital. So I think that just speaks to the stronger capital efficiencies we're seeing in the business, some of the synergies that Randy alluded to coming through here in the actual numbers. And then I know this wasn't your question, Chris, but the last thing I would just point out as well, when you look at our OpEx and G&A cost structure, we are now forecasting that to be a $4.50 reduction from our original 2025 guidance that came out pre the Westbrick acquisition. You're seeing it on the capital efficiency side, you're also seeing it on the operational efficiency side. So hopefully, that helps frame it, Chris.

Thanks, Lars. To summarize, production is up, now only 35% year-over-year. Capital efficiency has significantly improved and our cost structure is lower. This is why we're excited as a management team as we start to look out in the future years. I think we've got a much more concentrated focused asset base, and that's where we're excited about the sustainable profile that we're seeing with our excess free cash flow, especially as we think about the ramp-up in Montney, the pivot as we become free cash flow positive on the 2028 timeline and then the build up in Germany. But with that, Chris, back to you.

I will now turn it over to Kyle Preston for additional questions.

Yes, thanks, Kelsey. So we did have a few questions coming online here. I think a couple of them have already been addressed by the questions we've received so far, but there was 1 other outstanding here. Your Q2 corporate realized gas price premium relative to AECO was lower than the previous quarters. Can you help me understand this?

Yes. Great. Thanks, Kyle, for the question here. So yes, as the individual referenced here, we've reported a realized gas price of $4.88 for the quarter at the corporate level. The equal benchmark, which a lot of us are familiar with was $1.69, so just about 3 times premium to that. So the thing to keep in mind is when we report that corporate realized price, it is a blend of the production that we are selling in Europe, combined with the Canadian gas production. That is a very unique feature to Vermilion. The gas that we produce in Europe, we received local prices for that. What we have found here in the last couple of years is European gas prices are very highly correlated to global LNG prices. So you are getting that global LNG price today through the Vermilion production profile. Just to sort of reiterate these numbers that were in our release here for the second quarter of 2025, the TTF price in Europe averaged CAD 16.27 versus that AECO price of $1.69. In the second quarter, we produced just over 390 million a day of gas in Canada. Just to remind you, those come from our liquids-rich gas assets in Canada. On average, those gas wells are contributing about 30% liquids as well. And then we produced about 105 million a day of gas in Europe. What you're getting today with Vermilion is you're getting that LNG price exposure through our European gas production. Here in North America or Western Canada, you're getting a very material exposure to Canadian gas that is well hedged with a very high liquid weighting as well. In fact, for the second quarter here, our Canadian revenues on the continuing operations around that global gas business were about 60% driven by the liquids. I think those are just some nuances that are good to stop and walk through because they are very unique to Vermilion in the sense that we are giving you that global gas exposure through indigenous production in Europe as opposed to contracts that can be risky to get gas exposure from Western Canada to Europe or Asia for that matter.

That's all we have for online questions, operator.

Thank you. Turn it back over to you.

Well, thanks again for participating in the Q2 conference call and I appreciate everyone's time.

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