Vermilion Energy Inc. Q3 FY2022 Earnings Call

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. Thank you. Mr. Dion Hatcher, you may begin your conference.

Well, thank you, Elaine. 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. The 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 outlines 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. The 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 0.8 times. As we outlined last quarter, with our formal return of capital framework, our intention is to return more free cash flow to our shareholders as debt decreases. In Q3, we paid a cash dividend of CAD0.08 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 the Leucrotta acquisition that closed at the end of May. As I mentioned on the previous slide, our net debt to trailing fund flow ratio decreased to 0.8 times. 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, and we intend to maintain this discipline going forward. We operated with a leverage ratio near one times 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 one times fund flow implies an absolute debt target of $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 CAD 120 per MMBtu in late August, following various supply disruptions and growing concerns regarding Europe's ability to meet winter energy demand. The energy security and inflation situation have become focal points for many countries and citizens around the world, especially in Europe. The energy security situation in Europe, which is the result of policy decisions over multiple years, has 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 Russian 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, bringing the total supply loss to 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 CAD 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 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 represents 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 when China had lower demand due to stringent COVID lockdown policies. In addition, Nord Stream 1 was not in operation, supplying Europe for over half of the injection period. With 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 one-third of the world's current LNG supply. Another way to think about it is that you would need to double the US 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 recent weeks, the Qatar Energy Minister stated that negotiations with European countries on new LNG supply are challenging due to Europe's unwillingness to commit to long-term contracts, which are typically 15 to 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 our strong Q3 financial results, and we expect it to be a key driver for future results. The chart on the left of Slide 6 shows historical and forward prices 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 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 have become a front-and-center concern for 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. Natural gas is an important energy source that should be produced locally where possible to ensure security of supply. This is consistent with Europe’s recognition of 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 the 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 the subject company between 2018 and 2021. We have provided an estimate for the 2022 windfall tax impact of $250 million to $350 million within our Q3 release. There continue 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 $650 million to $750 million, again, over two years based on the current strip pricing. This estimate is inclusive of the incremental core 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. The 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 one month due to unexpected maintenance and repairs on the third-party contracted rig. The 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, three wells were drilled in Hungary, but none of these wells encountered commercial hydrocarbons. 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 German program continues into early 2023 for a total of six 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 of horizontal well length drilled between the two wells. The 360-degree well path with planned sidetracks in the B-17 well resulted in accessing new reserves. The wells have produced over 300,000 barrels cumulative to date; our Wandoo crude currently sells at approximately US$14 premium to Brent, resulting in a Q3 Australian operating netback of approximately $96 per BOE. At current pricing, these two wells have generated approximately $30 million of operating cash flows, recovering 40% of the invested capital in the first two 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 and a delayed start-up of our Turner wells in the US. In Canada, we ramped up our Southeast Saskatchewan drilling program. We brought on production 14 wells and completed the six wells of our first Montney pad at Mika, which were drilled in Q2. In the United States, we completed and brought on production the remaining five wells of the six-well Turner program. Three of the wells were drilled with extended reach two-mile laterals, and we executed lower intensity fracs across the wells, resulting 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 farmout 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. At River Basin assets, similar to other North American assets, we have multiple stacked targets including the Parkman, the Niobrara, and the Mowry, 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 six-well drilling program that was initiated by Leucrotta on the Alberta Lands. We successfully completed the wells executing over 1,000 fracs. While testing was limited due to player restrictions, 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 three-well pad in Alberta in Q4. Late in the third quarter, we received approval to restart one 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 remain 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 US wells. The closing of the Corrib acquisition is nearing the final stages, and we now anticipate the 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 Vermillion and 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 the windfall tax, we will 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 are having 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. We will take our first question from Greg Pardy from RBC Capital Markets.

Hi, team. It's Robert Mann here on behalf of 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 it does not close for some reason? If so, how would the unwind work?

Okay. Well, thanks, Robert. I'll pass it to Lars just to discuss the financial question and then to 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, now that we would have to factor in the windfall tax obligation, which we will incorporate into the final purchase price effective January 1, 2022. So, a payout at some point in the second half of 2023. The thing that I would highlight is that this 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, do you want to follow up on the second part of the question?

Yes. As it relates to the timing of the close, we certainly do expect this deal will close. Originally, we did expect it to 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, the effective date. So the timing of the close really doesn't impact the financial contributions of the acquisition. To 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. 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 of 2023.

That's great. Thank you. 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 pre-tax cash flow? Does the 10% to 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% to 11% for the full year would be a reasonable range. Keep in mind that does not include any contribution from the acquired core interest. 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.

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, and 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? 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?

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

Good morning, Menno. On the first part of your question, no formal submission has been made regarding 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 going to be retroactive in nature as well as potential exposure to a two-year period. 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 we run includes a strong balance sheet in terms of being able to support that return of capital. 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, yeah, 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 will reevaluate the merits of capital allocation as we go into 2023, incorporating this new information as well as working through the budget and other variables.

Thanks, Lars.

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

Thanks, Menno, and maybe I’ll take this opportunity just to zoom out and talk a little bit more about the windfall tax, and then pass it over to Lars to talk about some of the mechanics. It's been an interesting time with the policy in Europe during this energy crisis. The discussions range from price caps to windfall taxes on 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 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, we put meaningful capital at risk to provide secure energy in Europe. Over that time, we've worked hard across our operations to be best-in-class. For our shareholders, we took some risk and we've deployed capital into that market, with guarantees of return, even during some tough periods with the commodity price crash, and between 2014 and 2019, as well as, of course, COVID here in 2020. From 1997, we were 6,000 barrels a day. If we look at where we're going to be in 2022, we're in excess of 31,000, and that production that we have in those jurisdictions highlights the need to import energy from other areas, which, from a full cycle emission point of view, is lower. There's also the economic benefits of producing in Europe. We are displacing the need to import energy, which means there’s deployment. There’s support of the service sector, and there are the royalties and taxes that we pay to both communities and the federal level. If you look at 2022 across our portfolio, 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, that's in excess of the $500 million of corporate cash flows we generated in 2020. As we think about the policies in Europe, we want stable and predictable policies, and a recognition of our business being cyclical, which means there are periods of low prices and high prices. The high prices are needed to offset the lows, and the benefits of having producers like Vermilion in that market ensure secure, lower-emission energy. But with that, that's our view; just strategically looking at some of the challenges in the near term. 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.

Yes. Menno, I'll 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 are defined in the regulation as taxable profits exceeding 120% of the annual average during the 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, those measures will be applicable. That's where we're basically applying the EU framework at this point to estimate that $650 million to $750 million of two-year cumulative impact. I think in short order, we should have a little bit more certainty on at least 2022 in terms of that deadline.

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

No, that was great. Thank you.

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

Hi, good morning and thanks for taking my questions. The first one really relates a little 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 over to Bryce Kremnica, our VP of North America, just to touch on inflationary pressures in North America.

Yes, thanks for the question, Dennis. Overall inflation in North America on the capital side is in the range of about 20%. Notably, on the OpEx side, it's much lower, in the 5% range; this is a testament to all the work the team has 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 Saskatchewan is probably up the most at around 30%. We've done a lot 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 to help manage costs. So we will continue to do the same. With respect to Mica, we have 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 costs going forward into 2023.

Thanks, Bryce. We're noticing that it’s interesting how our model allows us to deploy capital across various areas of the business. We have put considerable thought into strategies like summer drilling in Saskatchewan when costs tend to be lower in the Powder River Basin, utilizing crews from Alberta. We are managing the situation carefully but are still experiencing inflation, as Bryce pointed out.

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

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.

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 about 5% up to 10%. As you suggested, that's due to limited activity in Europe, and we've gotten a little bit of help from the exchange rate that makes that even lower. So, that's fully baked into our plans next year. Because of the longer timelines in Europe, 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.

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

Yeah, Travis, 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.

Yeah. You can see there in the second half of 2022, European gas hedges got up to that 60% level. For 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 more focused on being opportunistic if we do go higher than that versus risk mitigation at this point.

Okay. Perfect. I appreciate it.

Thanks, Dennis.

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

Yeah. Thanks. Most of my questions were answered with the questions and discussion on the Windfall, so that was super helpful. But maybe just in the context of the complexities of the windfall tax and how you guys are thinking about stressing that into 2023. 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 2023 and possibly 2024. 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 strong macro backdrop on pricing?

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

Yes. In terms of the first part of your question, Travis, 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 has been extremely rapid. As you introduce new legislation impacting 27 member states, there are a lot of moving parts in terms of what that is ultimately going to look like within each of the countries that adopt it. We're monitoring it as the rest of the market is in terms of what's available in the public domain. What we felt was important was to provide some disclosure here in terms of the impact could be over that two-year period. We will look to update that disclosure as we go forward and as we get clarity at the end of the year. Thanks, Dion. With respect to capital allocation, if the status quo remains, we will factor in any windfall tax beyond 2023 into our decisions. But we have an incentive to allocate more capital to Europe to support energy security supply response, and we believe we have a role to play in that. We’ll have to ensure that we factor in anything here. At this point, it is a temporary windfall tax, with a scope limited to 2022 and 2023. If it were extended, we would need to factor that into our decisions. But we're committed to being in Europe for the long term.

Thanks, Lars.

Thanks, guys.

Thanks, Travis.

We will take our next question from Nilay Mehta from Hudson Bay. Please go ahead.

Hey, guys. Can you hear me?

Yes.

Hey. Thank you. 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 you want to focus on the strength of the balance sheet first and foremost, and then look to sort of reintroduce the dividend at some point. I know in the prepared remarks, you guys expect 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, do you have a better sense of where 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 600 to 700 range or whatever over two years. What was the thought process of spending it now, given that we're almost this part in the quarter? Is the tax that retracted for 2022? Is that going to have to be paid like the day of the decision? Therefore, there was a thought that, that would impact the net debt higher because that's going to be the cash flow from that, like a one-time 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? What's the mechanism there for the windfall tax payments?

Okay. Yes. Just to clarify, we suspended the share buybacks. We are paying and continue to pay the dividend. Our strategy is to provide ratable 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.

Yes. The $1.2 billion debt target was 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 at exit 2022 net debt. In terms of the accounting for the windfall tax, it's going to be subject to when legislation gets finalized. If that comes to fruition, we would expect that to trigger an accrual for the windfall tax 2022 exposure in the fourth quarter of this year. That will get reflected in 2022. We've embedded that into that $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. And then just to sort of, I guess, relate a little bit of a follow-up. Some of the countries that have come with a policy are still outstanding, mostly Ireland and Germany. On the countries that have come in so far on their policies for windfall tax, how does it compare to what you guys were thinking relative to what the EU was implementing? Is it in line with that or better, etc.? Are there any offsets that you guys have in those countries that may be factored into your estimates right now, or at this point, are there no offsets in the estimates? Lastly, just back to the accounting and how it's paid, and all that stuff, again, back to like if you're exiting with $1.6 billion this year on net debt, and you're looking at production into 2023. Given the total size of the windfall tax is estimated and the net debt exiting this year, does it still seem feasible for you to reach your net debt target next year of sub-$1 billion, and you're back in that range of free cash flow generation and able to pay out 50% or so of the free cash flow into 2023 once the buybacks are resumed?

Yeah. I'll paraphrase the question here. Some of these we can discuss at a later time if needed. But I'll pass to Lars here to comment on maybe some of the offset mechanisms of the windfall tax, and secondly, how we're thinking about debt targets for next year.

Yeah. Just back to the windfall tax, without getting into each of the countries that will have windfall tax exposure, there are varying degrees there in terms of certainty about how the framework will be employed. At this point, we have factored in all information that we have today into that estimate of $650 million to $750 million. There are quite a bit of nuances once you get into each country, both from a front office and back office perspective in terms of how the calculation will ultimately unfold. Back to your follow-up question on debt here: if you start from that $1.6 billion at the end of 2022, this is fully burdened with our estimate for the Corrib closing cost as well. If that gets pushed to 2023, that transitions between 2022 and 2023. In terms of net debt balance, a good landing spot could be targeting an undrawn credit facility revolver, in terms of setting ourselves up strongly for 2024 and then navigating uncertainties linked to windfall tax and commodity price volatility. The pause we wanted to take here in the fourth quarter is to work through those decisions and what's right for capital allocation. We have a firm belief that by taking a pause in Q4, the fact that free cash flow will accrue to shareholders indicates that we will end with a lower debt balance, which we believe to be a better position as opposed to a lower share count. If that allows us to accelerate buybacks in 2023, we think that is a prudent decision here in the short-term.

Thanks, Lars. Got it. Thank you. Just a final question on the capital returns. I know it's part of the energy space, but Vermilion had been a story about capital return as well. The pause here due to the windfall tax situation raises concerns among shareholders. How critical does the capital return policy remain in Vermilion's story, given this pause? I assume it's still part of the long-term track record?

Yes, I can take this one. If you look back on the history of the company, we have paid over $40 a share in dividends. Our focus is to have a strong balance sheet, and as debt levels decrease, we aim to return increasing amounts of cash flow to our shareholders. Over the longer term, we've consistently done that, with 25% to 26% of free cash flow returned to our shareholders for capital in Q3. The pause in Q4 does not indicate a change in our commitment to return capital to our shareholders. We've maintained a long-term track record of doing that. The decision was to gather more data and focus on ensuring a lower year-end debt target. We look forward to releasing our budget in early January, at which point we'll provide more details around spending and free cash flow levels along with thoughts on capital return.

Got it, thank you.

Great questions. 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 want to say thank you again for participating in our Q3 release.

That will conclude today's conference. Have a good day. You may now disconnect.