Vermilion Energy - Earnings Call - Q2 2025

Transcript

Speaker 1

Thank you, Kelsey. Good morning, ladies.

Speaker 2

Good morning, ladies and gentlemen. Welcome to the Vermilion Energy Q2 2025 conference call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. 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.

Speaker 1

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 HSC; Randy McQuaig, Vice President, North America; Laura Conrad, Vice President, Business Development; and Kyle Preston, Vice President, Investor Relations. Please refer to our 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 it outlines the 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 divestitures 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 toward 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 Mountain, Alberta Deep Basin, and Germany. At Mica, Vermilion completed five and brought on production in 11 liquids-rich mountain wells. Mica Mountain 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 two 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 Mica Mountain wells, with our drilling, completions, equipment tie-in, and costs coming in at approximately $8.5 million per well for the two 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 drill times. This is a reduction of a half million dollars per well from our prior target and over $1 million per well compared to just one 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 Mica Mountain development.

With the second expansion phase at Mica now complete, our Mica Mountain 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 timeframe to reach our targeted production rate of 28,000 BOEs per day by 2028. Once we get to this level, we anticipate drilling approximately eight wells per year to maintain this production level for over 15 years, which translates to generating approximately $125 to $150 million of annual free cash flow, assuming a price of $70 WTI and $3 AECO.

In the Alberta Deep Basin, we executed one rig program during the quarter and drilled four, completed three, and brought on production of three liquids-rich wells. We plan to add two rigs and execute a three-rig program during the second half of 2025 as we ramp up activity heading into the winter. We're very pleased with how the integration of the Westbrick Energy Ltd. 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 the total to date to over $200 million on an MPV10 basis of synergies post-acquisition.

This clearly demonstrates the benefit of our dominant and continuous land base in the Alberta 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 Energy Ltd. acquisition, we have taken additional steps to further streamline the business by reorganizing our Canadian business unit. This has led to dedicated technical and corporate teams concentrating exclusively on our liquids-rich assets in the Alberta Deep Basin and the Mica Mountain. In Germany, we drilled, completed, and brought on production of two 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.

The facility and tie-in activity on the Ossenheid deep gas well was completed at the end of Q1, and the well averaged approximately 1,100 BOE 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 Westeifel Horst well, which remains on schedule for tie-in and startup during the first half of 2026. 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 Energy 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 emissions reduction target one 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 with a 16% reduction at the end of 2024. Looking 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 one of the busiest times in Vermilion Energy's history as we executed 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 Energy now has a much more focused and resilient asset base underpinned by high-return development opportunities, unique exposure to premium priced 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 Mica Mountain, drill cost, equipment tie-in savings, and synergies related to the Westbrick Energy Ltd. acquisition worth a combined $300 million on an MPV10 basis. With only 154 million shares outstanding, that equates to approximately $2 per share of value.

We also maintain a strong safety record across our operations through this period, a true testament to our commitment to sending everyone home safe every day. The second half of 2025 will be an active period as we add two additional rigs to our Alberta Deep Basin program and commence drilling two wells in the Netherlands. Factoring in the timing of the July divestitures, combined with the planned seasonal turnaround activity and some shutting in gas to 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 divestitures 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, and we expect to be in a position to increase shareholder returns as debt trends towards a $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 2026. 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 AECO in Q2. As we look out over the next few years, our efforts will continue to focus on our key growth assets: Mica Mountain, Deep Basin, and Germany. In Mica Mountain, we will build out the final phase of our infrastructure to support our target production rate of 28,000 BOEs per day, a third 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, where the picture of Vermilion Energy as a global gas producer will become clearer following this busy period of A&D activity. We believe the company is now in a better position to drive long-term shareholder value with a more focused, 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.

Speaker 2

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Should you have a question, please press the star followed by the one on your touch-tone phone. You will then hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press the star followed by the two. If you are using a speaker phone, please lift the handset before pressing any keys. One moment, please, for your first question. Your first question comes from Greg Party from RBC Capital Markets. Please go ahead.

Yeah, thanks. Good morning. Thanks, Dion, for the rundown. I wanted to ask you two things, which you definitely touched on in your opening remarks. Maybe just in terms of streamlining the portfolio, like there's definitely been coring up in areas. You still have a number of areas, perhaps, you know, maybe they're smaller assets or less core, even some of the stuff in Europe and so on. I'm just curious, what's next in terms of shaping, you know, reshaping the portfolio and where would that be?

Speaker 1

Thanks, Greg, for the question. Yeah, no, I think you're right. If you think about Canada, of course, we've exited the 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 you 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've decided not to pursue, and that is another couple of jurisdictions that we're deciding not to allocate capital to going forward. Finally, Croatia is an area where we've had some success. We've drilled some good wells. We have some production. Also, on the SA7 block, we did have some exploration success, but that is yet another area that we're looking at.

Although we've got a very strong technical team and I think a pretty interesting land base, will it, 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 the Netherlands, and of course, the long suite of projects that we've got in North America. We're not done yet, Greg, to answer your question, and I think you're going to see continued focus on making the business more streamlined, which will improve our capital efficiency and our cost structure.

Okay, thanks for that. Maybe just shifting into the shareholder returns, let's say you were at $1 billion today, then perhaps given the value, I'm just trying to get a better sense as to where would the payout ratio presumably go, and then is there a bias towards dividends or buybacks? I'm assuming maybe the buyback just given your relative valuation, but curious there.

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

Speaker 0

Yeah, thanks, Dion. Good morning, Greg. Yeah, on the shareholder return front, you know, I think we have been pretty clear and transparent the last couple of years here, and we were at 50% of excess free cash flow being returned. We did a very material acquisition late last year, announced late last year with the Westbrick acquisition, funded with the balance sheet primarily at the time of the acquisition, and then with the dispositions that Dion mentioned in the U.S. and Saskatchewan. It was a cash, as a result of it being a cash-funded acquisition, we reduced the return of capital to 40% of excess free cash flow. We have been buying some shares this year, and we're quite comfortable with that 40% level as we chip away at the debt, look to get back to one-times leverage.

I think on the dividend front, we still like the idea of ratable per annum increases. I don't think there'll be the 20 to 25% increases that you saw the last couple of years, and we will look to prioritize share buybacks with that incremental return of capital over and above the dividend.

Okay, makes sense. Thanks very much.

Thanks, Greg.

Speaker 2

Thank you. Your next question comes from Manu Halshav from TD Cowen. Please go ahead.

Speaker 0

Thanks, and good morning, everyone. 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 of $200 million? If there is upside beyond your new estimate, where is that most likely to come from?

Speaker 1

No, thanks, Manu, 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. Hi there. As you mentioned, we're, you know, as Dion mentioned, we've got about $200 million of MPV synergies identified. We expect to achieve about two-thirds of that in the next five years. In terms of the details that you're looking for, like in the Q1 announcement, it was very much the first $100 million that we announced. It was around development and operational. That would have been drilling the extended reach wells with the combined land base, optimized production, and then our operating cost reductions that we've seen.

This next $100 million that we've seen here or announcing in the Q2 call was focused on or related to the reorganization of the Canadian or the restructuring of the Canadian organization, and that was based on the efficiencies that we've identified with the combination of Westbrick Energy Ltd. and the existing teams that we had in place. The other synergies that we're looking at are related to the reduced drilling costs, service costs that we get with the bigger program and more consistent program, and then the processing fees, a reduction in processing fees that, you know, as we continue to negotiate with every third party. Overall, I think when we look at it, we kind of estimate it to be about $30 million a year of savings, so quite significant. We would allocate about a third of that on the CapEx side, two-thirds on the expense side.

I think we're very happy with the work that's been done to date. The team continues to work as we integrate Westbrick Energy Ltd. We're very pleased with the acquisition, and we would expect to see more synergies as we continue to integrate. Thanks, Randy. In the summaries, I think we're really seeing, like if you looked at that image we published at the time of the announcement on December 23, just the sheer synergies around land touching each other, offsetting infrastructure, and the teams having more time to work with it. We're talking again, $30 million a year of kind of savings, which the MPV, all that, as Randy was saying, is how we got to that $200 million number. Great work by Randy and the team to start to realize some of these synergies.

Speaker 0

No question that it's a very strong number. Maybe just moving on to, you touched on this in your opening remarks, just on acquisition potential. Can we get an update on the opportunity set in Europe? Do you envision any packages coming to market anytime soon? Maybe a refresh on how you would go about funding it would be helpful as well.

Speaker 1

No, thanks, Manon. We still see the potential. As a reminder, we're 5% of the market in the 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 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 was about $200 million.

When we think about our ability to do deals in Europe, we are deleveraging by the day with approximately $750 million off balance sheet here this year, but also the time to close and the type of assets of whose would buy, which are typically high free cash flow generation, we feel really, really comfortable about our ability to be able to finance those. Lars, anything? No, give me the thumbs up. We're good there, Manon.

Speaker 0

Terrific. Thank you. I'll turn it back.

Speaker 1

Great. Okay, thank you.

Speaker 2

Thank you. As a reminder, if you wish to ask a question, press star one. Your next question comes from Chris Worley from Hughes Fund Management. Please go ahead.

Speaker 1

Hey guys, thanks for taking my question. 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. Can you just kind of talk through what happened with those deferrals and maybe which parts of the development plan got deferred and how will those deferred dollars get spent in Q3 and Q4?

Speaker 0

Thanks for that. I'm going to pass it to Lars. A couple of comments there before I do is, there is some seasonality as we talked about with in Canada, the breakup and things do tend to slow down here. We are picking up rigs, two additional rigs here in the Deep Basin and drilling in Netherlands right now. I think you'll see that cadence change. Back with that, I'm going to pass it to Lars to talk more about that. Yeah. Thanks, Dion. Good morning, Chris. Maybe just a couple of data points as well to level set, and then I'll provide a little bit of perspective here. 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 we printed a $2.1 billion net debt number at Q1. We're now at $1.4 billion. That's a combination of both the disposition proceeds as well as the fact that we were able to defer some capital on those non-core assets. Just to level set here, we have invested $297 million year to date. As you referenced, Q2 was a lower spent quarter with $115 million spent. You have the lower activity levels due to spring breakup here in Western Canada. We are on track to spend $630 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. As I referenced, when you combine that with the proceeds from the dispositions, that's what's allowing us to delever from that $2.1 billion level to $1.3 billion while high grading the asset base. Looking ahead, Chris, a capital run rate in the low $600 million is not a bad way to think about annual spend as a proxy for the business. 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 now guiding to 117,000 to 120,000 for the third quarter here and an annual run rate in the low $600 million of capital. 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. I know this wasn't your question, Chris, but maybe 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.

Hopefully that helps frame it, Chris, just in terms of that lower Q2 spend and what that means going forward here for the second half and into 2026.

Speaker 1

Yeah, no, thanks, Lars. To summarize, production's up now only 35% year over year. Capital efficiency is 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 why we're excited about the sustainable profile that we're seeing with our excess free cash flow, especially as we think about the wrap-up in Montney, the pivot as we become free cash flow positive on the 2028 timeline, and the build-up in Germany. With that, Chris, back to you. Thanks.

Speaker 0

No, thanks, guys. That was super helpful.

Speaker 2

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

Speaker 1

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

Speaker 0

Yeah, great. Thanks, Kyle, for the question here. As the individual referenced here, we've reported a realized gas price of $4.88 for the quarter at the corporate level. The AECO benchmark, which a lot of us are familiar with, was $1.69. Just about a 3X premium to that. 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 receive local prices for that. What we have found here the last couple of years is European gas prices are very highly correlated to global LNG prices. 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 $16.27 Canadian versus that AECO price of $1.69. In the second quarter, we produced just over 390 million a day of gas in Canada. I'll just remind you, those come from our liquids-rich gas assets in Canada. On average, those gas wells are contributing about 30% liquids as well. We produced about 105 million a day of gas in Europe. Really 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 or on 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.

Speaker 1

Thanks, Lars. I think that's it. We had all we had for online questions. Operator.

Speaker 2

Thank you.

Speaker 0

Well, with.

Speaker 2

Yep, turn it back over to you.

Speaker 1

Thanks again for participating in the Q2 conference call, and we appreciate everyone's time.

Speaker 2

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.