Vermilion Energy Inc

TSX:VET

Earnings Call Transcript 2022-Q3

[Operator]

Good morning, afternoon, evening. My name is Elaine, and I will be your operator today. At this time, I would like to welcome everyone to the Vermilion Energy Q3 Conference Call. As a reminder, today's conference is being recorded. [Operator Instructions] Mr. Dion Hatcher, you may begin your conference.

[Anthony Hatcher, executive]

Well, thank you, Elaine. Well, good morning, ladies and gentlemen. Thank you for joining us. I'm Dion Hatcher, President of Vermilion Energy. With me today are Lars Glemser, Vice President and CFO; Darcy Kerwin, Vice President, International, HSE; Bryce Kremnica, Vice President, North America; Jenson Tan, Vice President, Business Development; and Kyle Preston, Vice President of Investor Relations.

We will be referencing a PowerPoint presentation to discuss the Q3 2022 results. Presentation can be found on our website under Invest with Us and Events and Presentations. Please refer to our advisory and forward-looking statements at the end of the presentation. It describes the forward-looking information, non-GAAP measures and oil and gas terms used today and outline the risk factors and assumptions relevant to this discussion.

As shown on Slide 2, we generated $508 million of fund flow in Q3, which is a 12% increase over the prior quarter and is another quarterly record for Vermilion. For perspective, this quarterly fund flow is more than we generated for the full year of 2020. Free cash flow of $324 million was down slightly from the previous quarter due to higher capital expenditures associated with our Australia drilling program, which we successfully completed during the quarter. Majority of Q3 free cash flow was allocated to debt reduction.

Our net debt decreased by 11% to $1.4 billion, representing a debt to trailing 12-month fund flow ratio of 0.8x. As we outlined last quarter, with our formal return of capital framework is our intention to return more free cash flow to our shareholders as debt decreases. In Q3, we paid a cash dividend of CAD 0.08 per share and repurchased 2.3 million shares under our NCIB for $72 million. Combined, this amounts to $85 million returned to our shareholders, representing 26% of Q3 free cash flow.

Pro forma Q3 fund flow and free cash flow incorporating the incremental 36.5% ownership in Corrib was $611 million and $426 million, respectively. Q3 production averaged 84,237 BOEs per day, which was in line with the prior quarter as we previously guided to, reflecting planned turnaround activity in Canada and the forest fire-related downtime in France, which offset the new production added from Leucrotta acquisition, which closed at the end of May.

As I mentioned on the previous slide, our net debt to trailing fund flow ratio decreased 0.8x. As can be seen on Slide 3, this is our lowest leverage in over 10 years. We have made significant progress on debt reduction in the last 2 years. We intend on maintaining this discipline going forward. We operated with a leverage ratio near 1x or below for 10 straight years from 2003 to 2013. We will target lower leverage going forward. While commodity prices have helped drive this ratio lower, we'll manage our debt targets based on mid-cycle pricing assumptions, which at 1x fund flow implies an absolute debt target of $1 billion or less.

Contributing to our strong Q3 financial results was a robust European gas prices, which nearly doubled in Q3 compared to the prior quarter. As shown on Slide 4, TTF reached an all-time high of $120 per MMBtu in late August, following various supply disruptions and growing concerns regarding Europe's ability to meet winter energy demand. Energy security and inflation have become focal points for many countries and citizens around the world, especially in Europe. Energy security situation in Europe, which is really the result of policy decisions over multiple years have been amplified by the ongoing and devastating conflict in Ukraine.

Prior to 2022, Europe relied on Russia for approximately 40% of its gas supply, but Russia imports have significantly decreased in recent months, as key infrastructure was taken offline. Damage to the Nord Stream 1 pipeline in the Baltic Sea in late September has removed approximately 6 Bcf of supply capacity, which brings the total supply loss of 10 Bcf per day year-over-year. At this time, it is uncertain if or when this capacity will come back.

Despite these challenges, Europe managed to source enough gas over the summer months to essentially fill storage ahead of the winter heating season, even with partial Russian gas supply, prices averaged approximately $60 per MMBtu for the injection season period. We will discuss some of the underlying fundamentals driving European gas and outline why we are bullish on this commodity. It is important to understand how Europe was able to fill storage this past year and how the situation may be different next year.

Chart on Slide 5 illustrates the year-over-year change in LNG imports versus China and the rest of the world. As you can see, over 50% of Europe's increase in LNG imports this year was due to reduced LNG demand in other countries. Global LNG supply did not materially increase. It was rerouted to Europe. European LNG imports were up significantly, as Europe started to wean itself off from Russian gas. This is a very large undertaking, as Russian gas represent approximately 18 Bcf per day of Europe's gas supply.

Europe achieved higher LNG imports by outbidding the rest of world for LNG. However, this was also during a period where China had lower demand due to stringent COVID lockdown policies. In addition, Nord Stream 1 was an operation at supplying Europe for over half of the injection period. Storage essentially full. Europe is expected to have enough gas to meet demand this winter assuming average weather conditions. However, refilling storage capacity next year may prove to be more difficult with Nord Stream 1 presumably offline and Chinese demand potentially returning to pre-COVID levels.

Europe has become structurally more dependent on LNG imports to meet current natural gas needs. To put it in perspective, the volume of Russian gas that was supplied to Europe before the war represents approximately 1/3 of the world's current LNG supply. Another way to think about it is you would need to more than double the U.S. LNG export capacity to replace the Russian volumes supplied to Europe. The increased LNG demand will require direct competition with Asia, where LNG demand is also expected to increase over the coming decades.

There's very limited new LNG supply coming online over the next few years. New projects require significant capital underpinned by long-term contracts, which many European countries have been reluctant to commit to. In the recent weeks, the Qatar Energy Minister, and note Qatar is the largest supplier of LNG in the world, stated that negotiations with the European countries on new LNG supply are challenging due to Europe's unwillingness to commit to long-term contracts, which are typically 15, 20 years. Investments of this scale are expected to structurally change long-term pricing of European gas to higher than what it was before the war.

Given this global LNG backdrop and the underlying supply and demand fundamentals developing in Europe, we expect LNG and European gas prices to remain elevated. As I mentioned in my earlier remarks, European gas was a meaningful contributor to remain strong Q3 financial results, and we expect to be a key driver for future results. The chart on the left of Slide 6 shows historical and forward price for TTF, JKM and AECO. The blue bar is Vermilion's average corporate realized price premium to AECO.

On a pro forma basis, including the Corrib acquisition volumes, European gas represents about 1/4 of Vermilion's production base and contributes over 40% of our fund flow. Vermilion has approximately 3.8 million net acres of undeveloped land in the prospective basins across Europe. And we believe there is an opportunity to increase gas production with government support and the appropriate regulatory frameworks in place.

High European gas prices and the prospect for higher energy costs in the years ahead has become a front and center concern of all stakeholders in Europe, including politicians. For the past several months, there have been various government policy issues, ideas debated on how to contain energy prices in Europe, ranging from voluntary demand reduction to price caps to windfall taxes. Vermilion has been actively engaged with government officials in the countries where we operate to identify opportunities where we can contribute to domestic gas needs.

Natural gas is an important energy source that should be produced locally where possible to ensure security of supply. This is consistent that the Europe haven't recognized natural gas as a transition fuel. Late in the third quarter, the European Union announced several proposals in an attempt to address high energy costs. One of the proposals, which was subsequently approved, is a temporary windfall tax measure aimed at EU companies with activities in the hydrocarbon sector. This windfall tax is calculated as a percentage of earnings above a baseline of 120% of the average of taxable earnings of a subject company between 2018 and 2021.

We have provided an estimate for 2022 windfall tax impact of $250 million to $350 million within our Q3 release. There continues to be many unknown variables related to the final implementation of the tax. However, our current estimate of the potential 2-year exposure for 2022 and 2023 if the tax was implemented as framed by the EU would be approximately $650 million to $750 million, again, over 2 years based on the current strip pricing. This estimate is inclusive of the incremental Corrib working interest.

As shown on Slide 7, we have updated our 2022 pro forma financial outlook to incorporate this windfall tax and now forecast pro forma fund flow of $2.1 billion and free cash flow of $1.6 billion or over $9 per share, which implies a free cash flow yield of in excess of 30%.

Getting back to our Q3 results, we provided a brief summary of our operational highlights on Slides 8 through 11. Production from our international operations averaged 27,095 BOEs per day in Q3 and increased 1% from the prior quarter. Production increased in Australia and Germany, which has more than offset fire-related downtime in France and natural decline in other jurisdictions. Most notable activity in our international operations in Q3 was a successful completion of an offshore drilling program in Australia.

As highlighted last quarter, this program was scheduled to start earlier in the second quarter, but was delayed approximately 1 month due to unexpected maintenance and repairs on the third-party contracted rig. Drilling program was a success and the wells were brought on production in September. In Europe, we focused on restoring production in France that was impacted by the forest fire and expect most of the products to be restored by the end of the year. During the quarter, 3 wells were drilled in Hungary, but none of these wells encounter commercial hydrocarbons.

The capital spend on this program was minimum, while the findings will further enhance our knowledge and understanding of the geology in this region. Elsewhere in Europe, we continued with support work for our Q4 drilling campaign, which will include 1 well in the Netherlands, 1 well in Germany and 2 wells in Croatia. The Netherlands and German program continues into early 2023 for a total of 6 wells combined.

As mentioned, we had a very successful drilling campaign in Australia. We drilled the B17 and B18 wells for a total of 6,500 meters horizontal well length drilled between the 2 wells. The 360-degree well path with planned sidetracks in the B-17 well resulted in accessing new reserves. The wells that produce over 300,000 barrels cumu to date. Our Wandoo crude is currently sells an approximately $14 U.S. premium to Brent, resulting in a Q3 Australian operating netback of approximately $96 per BOE.

At current pricing of these 2 wells have generated approximately $30 million of operating cash flows, recovering 40% of the invested capital in the first 2 months on production. As in previous years, we will limit the production of these wells to manage our marketing contracts. We are currently evaluating the results to identify potential new targets and plan for our next drilling campaign, which we expect to occur in 2024 or 2025.

Production from our North American operations averaged 57,142 BOEs per day in Q3, a decrease of 2% from the prior quarter primarily due to third-party downtime in Canada, a delayed start-up of our Turner wells in the U.S. In Canada, we ramped up our southeast Saskatchewan drilling program. We brought on production 14 wells and completed the 6 wells of our first Montney pad at Mica, which were drilled in Q2.

In the United States, we completed and brought on production the remaining 5 wells of the 6-well Turner program; 3 of the wells were drilled with the extended reach 2-mile laterals and we executed lower intensity fracs across the wells, which resulted in approximately $2.7 million of total cost savings.

While the initial production from these wells is lower than our previous higher intensity completions, we are monitoring performance to determine the impact on longer-term decline profiles, well recovery and overall capital efficiencies. One of our farming partners drilled and completed 2 commitment wells testing the Parkman formation. The performance of those wells has exceeded our internal type curves, which we will continue to monitor while accessing the potential of this play on our lands. At River Basin assets, similar to other North American assets has multiple stack targets including the Parkman, the Niobrara and the [indiscernible], which represents significant upside beyond the turn.

As a reminder, we closed the Leucrotta acquisition at the end of May and took over operations during the 6-well drilling program that was initiated by the Leucrotta on the Alberta lands. We successfully completed the wells executing over 1,000 fracs. While testing was limited due to fire restrictions; however, we are nearing completion of the initial build-out of the facility and are excited to bring the wells on production shortly. We will be kicking off another 3-well pad in Alberta in Q4. Late in the third quarter, we received approval to restart 1 mile well in BC, which is now producing over 1,000 barrels a day for over the last month, which is in line with our expectations.

We have prepared detailed development plans for both our Alberta and BC lands. Although our preference is focused on the BC development, we will continue to maintain flexibility in terms of infrastructure development across the asset, including a drill-to-fill option on the Alberta lands, utilizing the existing infrastructure, which will result in approximately 7,000 to 8,000 BOEs a day of production in 2023. This option manages our near-term capital by deferring additional Alberta infrastructure and instead building out the BC infrastructure where the majority of our drilling inventory is located.

As part of our corporate allocation, we are optimistic that we can also increase capital to European gas drilling in 2023. Our 2022 capital budget and production guidance remains unchanged. However, we expect annual production to be at the lower end of the range due to the fire-related downtime in France and delayed downstream timing of the Australia and U.S. wells. Closing of the Corrib acquisition is nearing the final stages and we now anticipate acquisition to close in Q1 2023 due to administrative delays.

As previously noted, all free cash flow generated by the acquired interest in Corrib from Jan 1, 2022 until close, where accrue to Vermilion will be netted off the final purchase price. We plan to announce our 2023 budget in early January, and as we require additional time to assess the impact of windfall tax, we'll work with our regulators in Europe to facilitate additional drilling and continued timing -- confirmed timing on the Corrib acquisition close. We will remain disciplined in '23, as we continue to focus on debt reduction.

At this time, we anticipate a capital budget similar to 2022 investment levels with potentially a greater portion allocated to European gas. We have the ability and desire to drill more wells in Europe. And if I'm going to go discussions with regulators are productive, we would look to allocate additional capital to the region in 2023. In particular, we have several large gas prospects in Germany, targets that are approximately 10x larger than our recent Netherlands drills. We have -- we're having a very encouraging dialogue with local and state officials in Germany about the prospect of a sell and drilling into late 2023.

That concludes my prepared remarks. And with that, we'd like to open it up for questions.

[Operator]

[Operator Instructions] We will take our first question from Greg Pardy from RBC Capital Markets.

[Unknown Analyst]

It's Robert [indiscernible] on here for Greg Pardy. My first question is just surrounding the Corrib deal. Could you provide some guidance around what the net cost or benefit would be, if it closed in the first quarter of 2023. And what the probability of the deal is, if the deal does not close for some reason? And if so, how would the unwind work there?

[Anthony Hatcher, executive]

Okay. Well, thanks, Robert. I'll pass it to Lars just to discuss the financial question and then Darcy to address the timing.

[Lars Glemser, executive]

Robert, as Dion mentioned, we have factored in the windfall tax impact of the 36.5% interest on Corrib into our analysis here. As opposed to giving a hard number, what I would guide to is a payout at some point in the second half of 2023, now that we would have to factor in the windfall tax obligation, which we will incorporate into the final purchase price effective Jan 1, 2022.

So a payout at some point in the second half of 2023. The thing that I would highlight then is that includes the hedges that we put in place as part of the original transaction, as you get into 2024, you would then have all of that European gas benefiting cash flows on an unhedged basis.

[Anthony Hatcher, executive]

Thanks, Lars. Darcy, do you want to follow up on the second part of the question?

[Darcy Kerwin, executive]

Yes. As it relates to the timing of the close, we certainly do expect that this deal will close. Originally, we did expect it close in 2022, and that is still a possibility, but we think it's likely to slip now into Q1 of 2023. All the parties continue to work together to complete this transaction, we're all working through the administrative delays related to finalizing documents with the government and our partners.

I think it's worth noting that all cash flows are accruing to our benefit as of January 1, 2022, effective date. So the timing of the close really doesn't impact the financial contributions of the acquisition and kind of put things in perspective, when we last had a deal in Ireland to acquire an additional 1.5% stake in quarter, it took approximately 18 months to close. And so we're used to this kind of longer closure period taking place in Europe. So we do expect to fully close in the first quarter [ 2023 ].

[Unknown Analyst]

That's great. And just switching gears here a little bit, if I can. How should we be thinking about cash taxes in 2022 and 2023, not including the windfall tax as a percentage of pretax cash flow? Does the 10% to 11% range in '22 still seem reasonable?

[Darcy Kerwin, executive]

Thanks, Robert. I'll pass it back to Lars for that one.

[Lars Glemser, executive]

Robert, for 2022, I think forecasting a cash tax rate of 9% to 11% for the full year would be a reasonable range. Keep in mind that does not include any contribution from the acquired Corrib interest. And then for 2023, pre any kind of windfall tax inclusion, 14% to 16% cash tax would be a reasonable estimate. That does include the contribution of the 36.5% acquired working interest from Equinor.

[Operator]

Our next question will come from Menno Hulshof from TD Securities.

[Menno Hulshof, analyst]

Thanks, and I'll start with the suspension of the NCIB for Q4. Does that mean you're simply not electing to buyback stock this quarter? Or was there a filing submitted to formally suspend it? I'm just not clear on the mechanics of that? And then the second piece of that is why suspend it at all? It feels like if the upper end of the windfall tax range is $350 million per annum, that there would still be enough to go around for at least some buyback activity. So any thoughts on that front would be helpful as well.

[Anthony Hatcher, executive]

Thanks, Menno. I'll pass it over to Lars to address those questions.

[Lars Glemser, executive]

On the first part of your question, no formal submission has been made in regards to the NCIB. And so what we really wanted to accomplish with this press release was being transparent with shareholders in terms of taking a pause here in the fourth quarter to reassess the impact of a windfall tax that is likely going to be retroactive in nature as well as potentially exposure to a 2-year period as well.

So we wanted to take some time to prioritize that. When we do our analysis around the appropriate way to return capital over the longer term, every scenario that we run includes a strong balance sheet in terms of being able to support that return of capital over the longer term. If we end up taking a quarter to ensure that we don't put that strong balance sheet at risk, we think that, that is a pause that is worthwhile over the longer term.

In terms of the second part of the question, yes, I think that really factors into taking a pause here in the fourth quarter just to make sure that we do prioritize the balance sheet. And we'll reevaluate the merits of capital allocation, as we go into 2023 here, incorporating this new information that we have as well as we work through the budget and those other variables.

[Menno Hulshof, analyst]

Yes. And then on windfall taxes, did you now have a better sense of how each of the individual countries are going to manage the EU proposal? And what is your best guess on when we have announcements from each company in which you operate? And is there any risk that these announcements get pushed into 2023?

[Anthony Hatcher, executive]

Thanks Menno and maybe I'll take this opportunity just to zoom out and talk a little bit more about the windfall tax and I can pass over to Lars after that to talk about some of the mechanics. It's been interesting time with the policy in Europe. It's -- during this energy crisis, it's discussions from price caps to windfall taxes and oil and gas companies. I think it's important to note that the current situation is not solely the result of the war, and really the policies that all resulted in declining supply and increasing demand have created a pretty tight market.

If you think about Vermilion over the last 25 years, going back to '97, we put meaningful capital at risk to provide secure energy in Europe. And over that time, we've worked hard our operations to ensure we're best-in-class. So for our shareholders, we took some risk and we've deployed capital into that market. And without the guarantees of return and also during some pretty difficult periods here with the commodity price crash -- and between 2014 and 2019 as well as, of course, COVID here in 2020, from '97, we were 6,000 barrels a day. And if we look at where we're going to be in 2022, we're in excess of [ 31,000 ] and those production that we have in those jurisdictions that places the need to import energy from other areas, which, of course, from a full cycle emission point of view was actually lower.

And then you get to the economic benefits of producing in Europe. I mean we're displacing the need again to import energy, which means there's direct deployment. There's support of the service sector, and then there's the royalties and taxes that we pay to both communities and the federal level. If you look at 2022 across our portfolio, like we're looking at cash taxes plus royalties in excess of $550 million, and that's prior to the additional windfall tax. With that in perspective, I mean that's in excess of the $500 million of corporate cash flows we generate in 2020.

So I mean, our ask from -- as we think about the policies in Europe is really we want stable and predictable policies and two, I'd say, a recognition of twofold. Our business is difficult, and there's periods of low prices, and there's periods of high prices. And we need those periods of high prices to offset the lows of course.

And then third, again, the benefits of having producers like Vermilion in that market day in and day out to ensure their secure lower emission energy. But with that, I mean, that's our view is just strategically looking at some of the things that we'll continue to navigate in the near term here, but I'll pass it over to Lars to talk about some of the mechanics of the individual jurisdictions and how it will be applied.

[Lars Glemser, executive]

Yes. Menno, I'll just take this chance to reiterate what Dion commented on. We have this disclosure in our press release as well. But -- so the EU regulation requires member states to levy that minimum 33% tax on in-scope companies for 2022 and/or 2023 surplus profits. Surplus profits defined in the regulation as taxable profits exceeding 120% of the annual average during that 2018 to 2021 period.

EU member states are required to implement the tax or some kind of equivalent national measure by December 31, 2022. So we're within weeks of having that finalization. At the end of the day, depending on the national measures that are adopted by the EU member state as well as the financial years, which measures will be applicable that's where we're basically just applying the EU framework at this point to get that estimate of $650 million to $750 million of 2-year cumulative impact. So I think in short order here, we should have a little bit more certainty on at least 2022 in terms of that deadline.

[Anthony Hatcher, executive]

A bit of a long answer there Menno, but maybe that answers your question.

[Operator]

Our next question will come from Dennis Fong from CIBC World Markets.

[Dennis Fong, analyst]

The first one really relates a little bit more towards North American operations. Just wanted to understand a little bit in terms of how you're moderating the potential cost inflation impacts, especially given ramping activity both within Mica and then if I think about Powder River Basin as well.

[Anthony Hatcher, executive]

Thanks, Dennis. I'll pass over Bryce Kremnica, our VP of North America, just to touch on inflationary pressures in North America.

[Bryce Kremnica, executive]

Yes. Thanks for the question, Dennis. Yes, overall inflation in North America on the capital side of things is in the range of about 20%. Notably on the OpEx side of things, it's much lower in the 5% range, testament to all the work the team started on managing OpEx and managing contracts.

Just jumping over specifically to the Powder River Basin. Inflation there is about 20%, up year-over-year. When compared to Canada, our Alberta assets are up about 20%, and then Saskatchewan is probably up the most in the 30% range. So we've done lots of great work in the Powder River Basin executing our cost reduction strategies over the last few years, and we continue to do that.

This year, we brought a warm crew down from Alberta have only kicked off a program to help manage costs. So we'll continue to do the same. And then with respect to Mica, we got a good view on our costs going into the later half of this year, as we've had active operations into Q3, and then we're starting up a new pad into Q4. So we have a good handle on our cost going forward into 2023.

[Anthony Hatcher, executive]

Thanks, Bryce. Yes. And we're seeing -- again, it's interesting. I think that's 1 of the advantages of our model, Dennis, is to be able to deploy capital in different parts of the business. And put a lot of thought into things like Saskatchewan drilling in the summer when we find costs are lower in the Powder River Basin, again, using crews from Alberta. So again, very thoughtful there, but we are seeing inflation and doing our best to manage it, as Bryce noted.

[Dennis Fong, analyst]

Great. And maybe if I wouldn't mind on -- in terms of kind of an add-on to that question, if there were -- if there was incremental activity within Europe, how would you potentially think about contracting services. I mean, obviously, it's less -- call it less busy over there, but how are you thinking about the cost impacts of accelerating activity out there?

[Anthony Hatcher, executive]

Yes. I would say it's less. I can pass over to Darcy just to touch on what we're seeing there for inflation on the services side for Europe.

[Darcy Kerwin, executive]

Yes. In Europe, certainly, we're seeing lower inflation numbers on the services side than we're seeing in North America, probably in the range of kind of 5% up to 10%. As you suggested, that's kind of due to limited activity in Europe, and we've gotten a little bit of help as well from the exchange rate that even makes that a little bit lower. So that's kind of fully baked into our plans next year. We -- because of the longer time lines in Europe too, we do tend to acquire tubulars and enter into contracts earlier. So we have a pretty good handle on what the prices look like in Europe for next year.

[Dennis Fong, analyst]

Great. And then my last question here is just around hedging. I see like a small uptick in natural gas -- European natural gas hedges as we think about 2023, as a percentage of total production. Can you just kind of reiterate your strategy there? Obviously, there's a lot of volatility in the Corrib. I wanted to kind of understand if anything has changed on that side.

[Anthony Hatcher, executive]

Yes, we were quite active in August with some of these higher prices. But with that, I'll pass it over to Lars to touch on our strategy and some of the recent hedges we were able to execute.

[Lars Glemser, executive]

Yes. So you can see there in the second half of 2022, European gas hedges got up to that 60% level. 2023, we're at about that 50% level now. Those are probably pretty good bookends to think about in terms of where we could get European gas hedging too. We feel very comfortable with where we're at for 2023 at this point, and it's probably a little bit more around looking to be opportunistic, if we do go higher than that versus risk mitigation at this point.

[Operator]

We will take our next question from Travis Wood from National Bank Financial.

[Travis Wood, analyst]

Yes. And most of my questions were answered or around those questions and the discussion on Windfall. So that was super helpful. But maybe just in the context of the complexities of the windfall tax and maybe just how you guys are thinking about stressing that into 2023. And then as you think about capital allocation, the language was looking to spend more on European gas projects.

If you see this or policy language potentially push this into '23 and possibly '24, would that change your decision to continue to add volumes or cash flow out of the region just to offset some of the future tax? Or how are you thinking about balancing that against a really strong kind of macro backdrop on pricing?

[Anthony Hatcher, executive]

Thanks, Travis. I'll pass over to Lars to address that.

[Lars Glemser, executive]

Yes. So in terms of the first part of your question there, Travis, around sort of the complexities around the windfall tax. If you just sort of rewind here, the EU approved this legislation or the framework of the legislation late September, if you think back to the early part of September, there wasn't a lot of discussion around, a, EU-led windfall tax regime. So the velocity, the pace, the scope of this legislation I don't know if it's unprecedented, but it has been extremely rapid.

And as you introduce new legislation that's going to impact 27 member states, there's just a lot of moving parts in terms of what that ultimately is going to look like within each of the countries that adopt it. So we're monitoring it, as the rest of folks are in terms of what's available in the public domain. But I just want to emphasize that this is legislation. This is a new tax that has evolved very quickly here.

What we felt was important was to provide some disclosure here in terms of what the impact could be over that 2-year period, and we'll look to update that disclosure here, as we go forward and as we get certainty kind of going into the end of the year here.

[Anthony Hatcher, executive]

Thanks, Lars. And with respect to capital allocation...

[Travis Wood, analyst]

I mean I think we understand that. But is there -- if you took the status quo and expected this to kind of roll for another couple of years, do you think that would impact the capital decisions in the region? Or is the bottom line there just too large of a number to position capital to avoid or not avoid, I won't use that word, but to mitigate some of the tax impact in the short term.

[Anthony Hatcher, executive]

Thanks, Travis. I'll pass it back to Lars to talk about capital allocation and how we're thinking about that.

[Lars Glemser, executive]

Yes. Travis, we -- as Dion mentioned earlier, we've been navigating operations in Europe for 25 years here. I think it has been a very good place to do business. Absolutely, we're going to have to factor in any kind of windfall tax that would go beyond 2023 into our capital allocation decisions. I think what you heard from Dion as well as Darcy today is, we do have an incentive to allocate more capital to Europe just in terms of we want to be part of the energy security supply response, and we think that we do have a role to play into that.

We'll obviously have to make sure that we factor in anything here. At this point, it is a temporary windfall tax, the scope of it has been limited to '22 and 2023. If we were to extend beyond that, we'd have to factor that into our decisions. But we're in Europe for the long term.

[Operator]

[Operator Instructions] We will take our next question from [indiscernible]

[Unknown Analyst]

Can you hear me?

[Anthony Hatcher, executive]

Yes.

[Unknown Analyst]

I just want to revisit the windfall tax, I know that's getting a lot of questions this morning. I guess I just wanted to better understand. I know you're saying, obviously, you want to focus on the strength of the balance sheet first and foremost, and then we look to sort of reintroduce the dividend at some point. And I know in the prepared remarks, you guys expect it to end the balance sheet or net debt a little higher than expected. Kind of, I know it was 1.2% at the year-end, can you give a better sense of what you think that lands?

And then another way to sort of dig around that. Two is just I think someone asked a little bit earlier, but in a similar manner, if you have a sense of the total magnitude potentially being in that 600 to 700 range or whatever over 2 years. And then what was the thought process spending it now given that we're almost this -- from the quarter? Is the tax that retracted for 2022? Is that going to have to be paid like the day of the decision? And therefore, there was a thought that would impact the net debt higher because that's going to need of cash flow from that like a onetime payment? Or is it going to be paid over time for the retroactiveness of 2022? And how does that also get paid for 2023? Is that as it's earned? Like what's the mechanism there for the windfall tax payments?

[Anthony Hatcher, executive]

Okay. Okay. Yes. No, I can -- so a couple of things there. Yes, just to clarify, I mean, we suspended the share buybacks. We are paying and continue to pay the dividend. And again, our strategy is to provide variable increases of the dividend over time. With respect to the mechanics of when the windfall tax would be accrued and paid, I'll pass it back to Lars to talk about that.

[Lars Glemser, executive]

Yes. And I'll address that as well as your question around debt balance as well. I think that the $1.2 billion debt target was going to be a nice landing spot at the end of 2022 in terms of being able to go lower than that in 2023 as well as being able to return capital. Our estimate now that incorporates the windfall tax would be about $1.6 billion of exit 2022 net debt.

And that's a segue into the third part of your question in terms of the accounting for the windfall tax. Ultimately, it's going to be subject to when legislation gets finalized. As I mentioned earlier, there is a mandate right now for member states to have legislation in place by the end of this year, assuming that comes to fruition, and that is met. We would expect that to trigger an accrual for the windfall tax 2022 exposure in the fourth quarter of this year. So that will get reflected in 2022.

We've embedded that into that $1.6 billion net debt estimate. In terms of when that was cash -- or when that tax would be payable, that will be variable depending on the country, but I would expect it to range anywhere from early to late first half of 2023.

[Unknown Analyst]

And then just to sort of, I guess, related a little bit of a follow-up. I think you sounded like a couple of the countries that have sort of come to a policy and outstanding on a couple of other ones, I think mostly that Ireland and Germany. On the countries that have come in so far on their sort of policies or on windfall tax, how is it compared to what you guys were thinking and relative to kind of what the EU was implementing?

Is it sort of in line with that or better, et cetera? And are there any offsets that you guys have in those countries that may are factored into your estimates right now? Or are there -- at this point, there are no offsets in the estimates. And then also, just back to the accounting and how it's paid and all that stuff, like, again, back to like if you're exiting with $1.6 billion this year on net debt and you're looking at sort of production into 2023, if it's a similar level, I guess, and kind of what people have out there for estimates, it looks like cash flow generation should be fairly robust. And given the total size of the windfall tax is estimated and the net debt you're exiting this year, does the -- is it still feasible for you to reach your net debt target next year, that's sort of sub-$1 billion and you're back to sort of win that range of free cash flow generation and being able to pay out 50% or so of the free cash flow into 2023 once the buybacks are resumed.

[Anthony Hatcher, executive]

Yes. I'll just paraphrase the question here. And some of these, again, we can eager to meet with you off-line, if you can get into some of the more modeling questions. But I'll pass to Lars here around just to comment on maybe some of the offset mechanics of the windfall tax. And just secondly, how we're thinking about debt targets for next year?

[Lars Glemser, executive]

Yes. So just back to the windfall tax, without getting into each of the 4 countries that will have windfall tax exposure, there are varying degrees there in terms of certainty in terms of how the framework is going to be employed. I would say at this point, we have factored in all information that we have today into that estimate of $650 million to $750 million. There's quite a bit of nuances once you get into each country, both from a, I'd call it a front office as well as back office perspective in terms of how the calculation is ultimately going to unfold.

And then just back to your question -- follow-up question on debt here. So if you start with that $1.6 billion at the end of 2022, just as a reminder, we have fully burdened that with our estimate for the core of closing cost as well. If that gets pushed to 2023, that's something that will shift between '22 and '23.

In terms of net debt balance, debt target for 2023, that's something that we'll work through here. A good landing spot could be targeting an undrawn credit facility revolver, in terms of setting ourselves up strongly for 2024 and then navigating the uncertainties that are there regardless of windfall tax in terms of commodity price uncertainty, but that is the pause that we wanted to take here in the fourth quarter is just to work through those decisions and what's the right capital allocation.

We have a firm belief that by taking a pause here in the fourth quarter, the fact that, that free cash flow, it is still going to accrue to shareholders. It will accrue to shareholders through a lower debt balance in terms of where we exit this year, as opposed to a lower share count. And if that puts us in a position to accelerate buybacks in 2023, we think that that's a prudent decision here in the short term.

[Anthony Hatcher, executive]

Thanks, Lars.

[Unknown Analyst]

Yes. And then I guess maybe just a final 1 on that last one. You said obviously accruing to shareholders. I guess, a big part of the Vermilion [indiscernible] in general has been sort of the capital return story. And I guess the pause near term given sort of the windfall tax situation. And I don't know if there's any related on the production or cost side as well, if that any reason there.

But how important does the capital returns remain as part of Vermilion's sort of shareholder story in general, just given that the pause is happening here. And obviously, there's going to be a reaction from shareholders to that.

[Anthony Hatcher, executive]

Yes, I can take this one. I mean I think if you look back on the history of the company, we paid over $40 a share of dividends. Our focus is to have a strong balance sheet and as debt levels decrease to return increasing amounts of cash flow to our shareholders. And again, over the longer time frame, we've consistently done that.

I think to Lars' point, we were about 25%, 26% of free cash flow return to our shareholders for return of capital in Q3. We hit the pause in Q4. And again, really just that trade-off of near-term gathering more data as well as prioritizing year-end debt balance. And I think it just positions us to be that much stronger going into 2023.

If you look at where our debt level is going to be and where the strip pricing is currently for all commodities, again, we think we're positioned well. The next step for us is to continue to work through this in December, and we look forward to releasing our budget early in the new year. And that I think then would provide an appropriate time to really get into the details around spending levels, free cash flow levels or thoughts on return on capital. But just to be clear, a pause in Q4 does not, in any way, infer or change our commitment to return capital to our shareholders. Again, we've got a long-term track record of doing that. It was truly for this quarter to pause and gather additional information and focus on a lower year-end debt target.

[Operator]

It appears there are no further questions at this time. I would like to turn the conference back over to Dion Hatcher for any additional or closing remarks.

[Anthony Hatcher, executive]

I just want to say thank you again for participating in our Q3 release.

[Operator]

That will conclude today's conference. Have a good day, and you may now disconnect.