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. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star then the number 1 on your telephone keypad. If you would like to withdraw your question, please press the star key, then the number 2 on your telephone keypad. Thank you. Mr. Dion Hatcher, you may begin your conference.
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 Kirwan, 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 in Events and Presentations. Please refer to our advisory on 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 outlines the risk factors and assumptions relevant to this discussion.
As shown on slide 2, we generated CAD 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 CAD 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 CAD 1.4 billion, representing a debt to trailing twelve-month fund flow ratio of 0.8x. As we outlined last quarter with our formal return of capital framework, it 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 CAD 72 million. Combined, this amounts to CAD 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 CAD 611 million and CAD 426 million, respectively. Q3 production averaged 84,237 BOE 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 the 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 to 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 two 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 CAD 1 billion or less. Contributing to our strong Q3 financial results was 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 need 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. The chart on slide five 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.
As 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 of Russian gas. This is a very large undertaking as Russian gas represented approximately 18 BCF per day of Europe's gas supply. Europe achieved higher LNG imports by outbidding the rest of the 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 in operation and 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 a third of the world's current LNG supply. Another way to think about it is you would need to more than double the US LNG export capacity to replace the Russian volume supplied to Europe. 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 recent weeks, the QatarEnergy 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 Vermilion's strong Q3 financial results, and we expect to be a key driver for future results. The chart on the left of Slide 6 shows the 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 a quarter 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's an opportunity to increase gas production with government support and the appropriate regulatory frameworks in place. High European gas prices and their 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 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, with natural gas as an important energy source that should be produced locally where possible to ensure a secure supply. This is consistent with Europe having 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 for the subject company between 2018 and 2021.
We have provided an estimate for 2022 windfall tax impact of CAD 250 million-CAD 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 two-year exposure for 2022 and 2023 if the tax was implemented as framed by the EU, would be approximately CAD 650 million-CAD 750 million, again over two 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 CAD 2.1 billion and free cash flow of CAD 1.6 billion, or over $9 per share, which implies a free cash flow yield in excess of 30%. Getting back to our Q3 results, we've provided a brief summary of our operational highlights on Slides 8 through 11. Production from our international operations averaged 27,095 BOE 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 the 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 one month due to unexpected maintenance and repairs on the third-party contracted rig. The drilling program was a success and the wells were run 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 production to be restored by the end of the year. During the quarter, three wells were drilled in Hungary, but none of these wells encountered commercial hydrocarbons. The capital spend on this program was minimal, 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 one well in the Netherlands, one well in Germany, and two wells in Croatia.
The Netherlands and Germany 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 B-17 and B-18 wells for a total of 6,500 meters horizontal well length drilled between the two wells. The 360-degree well path with planned sidetracks on the B-17 well resulted in accessing new reserves. The wells have produced over 300,000 barrels cum to date. Our Wandoo crude currently sells at an approximately $14 US premium to Brent, resulting in a Q3 Australian operating netback of approximately $96 per BOE. At current pricing, these two wells have generated approximately CAD 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 BOE per day in Q3, a decrease of 2% from the prior quarter, primarily due to third-party downtime in Canada and 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.
Three of the wells were drilled with extended reach two-mile laterals, and we executed lower intensity fracs across the wells, which resulted in approximately CAD 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 farm-in partners drilled and completed two commitment wells testing the Parkman formation. The performance of those wells has exceeded our internal type curves, which we will continue to monitor while assessing the potential of this play on our lands. Powder River Basin assets, similar to other North American assets, has multiple stacked targets, including the Parkman, the Niobrara, and the Mowry, which represents significant upside beyond the Turner.
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 Leucrotta on the Alberta lands. We successfully completed the wells, executing over 1,000 fracs. Well testing was limited due to flare 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 a 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 7,000-8,000 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 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 on-stream 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 January 1, 2022 until close will accrue to Vermilion and be netted off the final purchase price. We plan to announce our 2023 budget in early January, 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 confirm timing on the Corrib acquisition close. We will remain disciplined in 2023 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 ongoing 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 10 times larger than our recent Netherlands drills. We're having a very encouraging dialogue with local and state officials in Germany about the prospect of accelerating drilling into late 2023. That concludes my prepared remarks, and with that, we'd like to open it up for questions.
Thank you. If you would like to ask a question, please signal by pressing star one on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, press star one to ask a question. We'll pause for just a moment to allow everyone an opportunity to signal for questions. We will take our first question from Greg Pardy from RBC Capital Markets. Please go ahead.
Hi, team. It's Robert Mann 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? 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?
Okay. Well, thanks, Robert. I'll pass it to Lars just to discuss the financial question and then Darcy to address the timing.
Hi, 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. Note that we would have to factor in the windfall tax obligation, which we will incorporate into the final purchase price effective January 1, 2022. 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.
Thanks, Lars. Darcy, you wanna follow up on the second part of the question?
Yeah. As it relates to the timing of the close, you know, we certainly do expect that this deal will close. Originally, we did expect that it would close in 2022, and that is still a possibility, but we think it's likely to slip now into Q1 in 2023. All the parties continue to work together to complete this transaction. We're all working through the administrative delays related to finalizing the 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. The timing of the close really doesn't impact the financial contributions of the acquisition.
To kind of put things in perspective, when we last did a deal in Ireland to acquire an additional 1.5% stake in Corrib, it took approximately 18 months to close. We're used to this kind of longer closure period taking place in Europe. We do expect to fully close in the first quarter of 2023.
Thanks, Darcy.
That's, yeah, that's great. Thank you. 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 pre-tax cash flow? Does the 10%-11% range in 2022 still seem reasonable?
Thanks, Robert. I'll pass it back to Lars for that one.
Yeah. Hey, Robert. For 2022, I think forecasting a cash tax rate of 9%-11% for the full year would be a reasonable range. Keep in mind, that does not include any contribution from the acquired Corrib interest. For 2023, pre any kind of windfall tax inclusion, 14%-16% cash tax would be a reasonable estimate. That does include the contribution of the 36.5%, acquired working interest from Equinor.
That's great. Yeah, thank you. Thanks for taking my questions. I'll turn it back to the operator now.
Thanks, Robert.
Our next question will come from Menno Hulshof from TD Securities. Please go ahead.
Thanks, good morning, everyone. I'll start with the suspension of the NCIB for Q4. Does that mean you're simply not electing to buy back stock this quarter? Or was there a filing submitted to formally suspend it? I'm just not clear on the mechanics of that. 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 CAD 350 million per annum, that there would still be enough to go around for at least some buyback activity. Any thoughts on that front would be helpful as well.
Thanks, Menno. I'll pass over to Lars to address those questions.
Morning, Menno. On the first part of your question, no formal submission has been made in regards to the NCIB. 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 gonna be retroactive in nature, as well as potentially exposure to a two-year period as well. 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 is a pause that is worthwhile over the longer term. In terms of the second part of the question, you know, 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. We'll reevaluate the merits of capital allocation as we go into 2023, incorporating this new information that we have, as well as we work through the budget and those other variables.
Thanks, Lars.
Yeah, thanks for that. Then on windfall taxes, do you now have a better sense of how each of the individual countries are gonna manage the EU proposal? What is your best guess on when we have announcements from each country in which you operate? Is there any risk that these announcements get pushed into 2023?
Thanks, Menno. Maybe I'll take this opportunity just to zoom out and talk a little bit more about the windfall tax, and I can pass it over to Lars after that to talk about some of the mechanics. You know, it's been interesting times with the policy in Europe. During this energy crisis, it's discussions from price caps to windfall taxes in oil and gas companies. I think it's important to note that, you know, the current situation is not solely the result of the war. The policies that ultimately resulted in declining supply and increasing demand have created a pretty tight market. You think about Vermilion over the last 25 years, going back to 1997, you know, we put meaningful capital at risk to provide secure energy in Europe. Over that time, we've worked hard on our operations to ensure we're best in class.
For our shareholders, you know, we took some risks and we've deployed capital into that market. Without the, you know, guarantees of return and also during some pretty difficult periods here with the commodity price crash in between 2014 and 2019 as well as of course, COVID here in 2020. You know, from 1997 we were 6,000 barrels a day, and if we look at where we're gonna be in 2022, we're in excess of 31,000. You know, those production that we have in those jurisdictions displaces the need to import energy from other areas, which of course from a full cycle emission point of view is actually lower. 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 employment, there's support of the service sector, and then there's the royalties and taxes that we pay to both communities and federal level. If we look at 2022 across our portfolio, like we're looking at cash taxes plus royalties in excess of CAD 550 million, and that's prior to the additional windfall tax. To put that in perspective, I mean, that's in excess of the CAD 500 million of corporate cash flows we generate in 2020. I mean, our ask, you know, 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 cyclical and there's periods of low prices and there's periods of high prices and, you know, we need those periods of high prices to offset the lows of course. Then third, again, the benefits of having producers like Vermilion in that market, you know, day in, day out, to ensure there's secure lower emission energy. With that, I mean, that's our view is just strategically looking at some of the, you know, things that we'll continue to navigate in the near term here. I'll pass it over to Lars to talk about some of the mechanics of the individual jurisdictions and how it will be applied.
Yeah, Menno, I'll just take this chance to reiterate what Dion commented on. We have this disclosure in our press release as well. 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. You know, 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 states as well as the financial years, which the measures will be applicable, that's where we're basically just applying the EU framework at this point to get that estimate of CAD 650 million-CAD 750 million of two-year cumulative impact. You know, I think in short order here, we should have a little bit more certainty on at least 2022 in terms of that deadline.
bit of a long answer there, Menno, but hopefully that answers your question.
Yeah. No, that was great. Thank you.
Thank you.
Our next question will come from Dennis Fung from CIBC World Markets. Please go ahead.
Hi, good morning, and thanks for taking my questions. 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.
Thanks, Dennis. I'll pass it over to Bryce Kremnica, our VP of North America, just to touch on inflationary pressures in North America.
Yeah, thanks for the question, Dennis. Yeah, 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's done 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's probably up the most in the 30% range. You know, 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 when we kicked off the program to help manage costs, so we'll continue to do the same. With respect to Mowry, you know, 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. We have a good handle on our costs going forward into 2023.
Thanks, Bryce. Yeah, we're seeing. Again, it's interesting. I think that's one 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. Again, very thoughtful there, but we are seeing inflation and doing our best to manage it as Bryce noted.
Great. Maybe in terms of kind of an add-on to that question, 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?
Yeah, 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.
Yeah. Dennis, 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%-10%. You know, as you suggested, that's kinda due to limited activity in Europe and, you know, we've gotten a little bit of help as well from the exchange rate that even makes that a little bit lower. So, you know, that's kind of fully baked into our plans next year. Because of the longer timelines 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.
Thanks, Darcy.
Great. 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 curve. Wanted to kind of understand if anything had changed on that side. Thanks.
Yeah, Travis, you know, we were quite active in August with some of these higher prices. With that, I'll pass it over to Lars to talk to you on our strategy and some of the recent hedges we were able to execute.
Yeah. You know, 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 to. 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.
Okay, perfect. Appreciate the questions.
Go ahead. Thanks, Dennis.
We will take our next question from Travis Wood from National Bank Financial. Please go ahead.
Yeah, thanks. I think most of my questions were answered around Menno's questions in the discussion on windfall, so that was super helpful. Maybe just in the context of, you know, the complexities of the windfall tax and maybe just how you guys are thinking about stressing that into 2023. Then as you think about capital allocation, you know, the language was looking to spend more on European gas projects. You know, if you see this, you know, or policy language potentially push this into 2023 and possibly 2024, would that change your decision to continue to add volumes or, you know, cash flow out of the region just to offset some of the future tax?
Kind of how are you thinking about balancing that against a really strong kind of macro backdrop on pricing?
Thanks, Travis. I'll pass it over to Lars to address that.
Yeah. In terms of the first part of your question there, Travis, around sort of the complexities around the windfall tax. You know, 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 an EU-led windfall tax regime. The velocity, the pace, the scope of this legislation, I don't know if it's unprecedented, but it has been extremely rapid. As you introduce new legislation that's gonna 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.
You know, we're monitoring it as the rest of folks are in terms of what's available in the public domain. Just wanna emphasize that, you know, 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 two-year period. 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.
Thanks, Lars. You know, with respect to capital allocation.
Yeah. I mean, I think we understand that. Is there, you know, if you took 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, you know, or not avoid, I won't use that word, but to mitigate some of the tax impact in the short term?
Thanks, Travis. I'll pass it back to Lars to talk about capital allocation and how we're thinking about that.
Yeah. You know, Travis, we, as Dion mentioned earlier, we've been navigating operations in Europe for 25 years here. You know, I think it has been a very good place to do business. Absolutely, we're gonna have to factor in any kind of windfall tax that would go beyond 2023 into our capital allocation decisions. You know, 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 2022 and 2023. If it were to extend beyond that, we'd have to factor that into our decisions. You know, we're in Europe for the long term.
Thanks, Lars.
Okay. Thanks, guys.
Thanks, Travis.
Once again, if you would like to ask a question, please press star one. If you're using a speakerphone, please make sure your mute button is turned off to allow your signals to reach our equipment. We will take our next question from Neela Mehta from Hudson Bay. Please go ahead.
Hey, guys, can you hear me?
Yes.
Hey, thank you. Yeah, I just want to revisit the windfall tax. I know that's getting a lot of questions this morning. I guess, just wanna better understand, I know you're saying obviously you wanna focus on the strength of the balance sheet first and foremost, and then, you know, look to sort of reintroduce the dividend at some point. I know in the prepared remarks, you guys expected to end the balance sheet or debt a little higher than expected. Kinda, I know it was 1.2 at the year-end. Can you give a better sense of where do you think that lands?
Another way to sort of dig around that too 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 CAD 600-CAD 700 range or whatever over two years, and then, you know, what was the thought process of spending it now, given that we're, you know, almost this part in the quarter, is the tax that's retroactive for 2022, is that gonna have to be paid like the day of the decision? And therefore, there was a thought that that would impact the net debt higher because, you know, that's needed the cash flow from that at like a one-time payment, or is it gonna be paid over time, for the retroactiveness of 2022?
How does that also get paid for 2023? Is it as it's earned? Like, what's the mechanisms there for the windfall tax payments?
Okay. Yeah, no, I can, you know, so a couple things there. Yeah, just to clarify, I mean, we suspended the share buybacks. We are paying and continue to pay the dividend. You know, again, our strategy is to provide ratable increases of the dividend over time.
Right.
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.
Yeah. I'll address that as well as your question around debt balance. You know, I think that the CAD 1.2 billion debt target was gonna 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 CAD 1.6 billion of exit 2022 net debt. 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. That would get reflected in 2022. We've embedded that into that CAD 1.6 billion net debt estimate. In terms of 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.
Thanks, Lars.
Thanks. Then just to sort of, I guess, related and a little bit of follow-up. I think you sounded like a couple of the countries have sort of come to a policy and you're outstanding on a couple other ones. I think mostly it's 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? Are there any offsets that you guys have in those countries that may or are factored into your estimates right now? At this point, there are no offsets in the estimates?
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, you know, 1.6 this year on net debt and you're looking at sort of production, you know, into 2023, if it's at similar levels, I guess, and kind of what people have out there for estimates, looks like the cash flow generation should be fairly robust.
Given the total size of the windfall tax you've estimated and the net debt exiting this year, is it still feasible for you to reach your net debt target next year that's sort of sub CAD 1 billion and you're back to sort of within that range of free cash flow generation and being able to pay out, you know, 50% or so of the free cash flow into 2023 once the buybacks are resumed?
Yeah, I'll just paraphrase the question here. Some of these, again, we're eager to meet with you offline if we can get into some of the more modeling questions. I'll pass it to Lars here and just to comment on maybe some of the offsets, the mechanics of the windfall tax, and just secondly, how we're thinking about debt targets for next year.
Yeah. Just back to the windfall tax. Without getting into each of the four countries that will have windfall tax exposure, there are varying degrees there in terms of certainty in terms of how the framework is gonna be employed. I would say at this point, we have factored in all information that we have today into that estimate of CAD 650-CAD 750. There are 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. Just back to your question, or follow-up question on debt here.
If you start with that CAD 1.6 billion at the end of 2022, just as a reminder, we have fully burdened that with our estimate for the Corrib closing cost as well. If that gets pushed to 2023, that's something that'll shift between 2022 and 2023. In terms of net debt balance target or 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, you know, the uncertainties that are there regardless of windfall tax in terms of commodity price uncertainty.
That is the pause that we wanted to take here in the fourth quarter, 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 free cash flow 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. 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.
Thanks, Lars.
Got it. Yeah, thank you. I guess maybe just a final one on that last one you said obviously accruing to shareholders. I guess a big part of the Vermilion story, and I know it's sort of big part of the industry space in general, has been sort of the capital return story. I guess the pause near term, given sort of the windfall tax situation, and, you know, I don't know if there's any related on the production or cost side as well, if any reason there. You know, how important does the capital return story remain as part of Vermilion's sort of shareholder, you know, story in general? Just given that the pause is happening here and obviously there's, you know, gonna be a reaction from shareholders to that so.
Yeah, I can take this one. I mean, I think if you look back on the history of the company, we paid over CAD 40 a share of dividends. We, you know, our focus is to have a strong balance sheet and as debt levels decrease, to return increasing amounts of cash flow to our shareholders. Again, over the longer timeframe, we've consistently done that. I think to Lars' point, you know, 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. Again, really just that trade-off of near term gathering more data as well as prioritizing year-end debt balance. I think it just positions us to be that much stronger going into 2023.
If you look at, you know, where our debt level is gonna 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, you know, releasing our budget early in the new year. That I think then would provide a, you know, appropriate time to really get into the details around spending levels, free cash flow levels, our thoughts on return of capital. But you know, 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.
Got it. All right. Thank you, guys. I'll follow up later offline. Thanks.
Great. Okay, we appreciate it. Thank you.
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.
I just wanna say thank you again for participating in our Q3 release.