Vermilion Energy Inc

TSX:VET

Earnings Call Transcript 2021-Q4

[Operator]

Good morning, afternoon, evening. My name is Paula, and I will be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy 2021 Year-End Earnings Conference Call. Today's call is being recorded. [Operator Instructions]

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

[Anthony Hatcher, executive]

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 and 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 Q4 2021 and year-end results we announced this morning. Presentation can be found on our website under Invest with Us and 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.

Before I begin the formal part of the presentation, I would like to start off with a comment on the current situation in Ukraine. Invasion into Ukraine by Russia is causing great hardship and tragic outcomes for the Ukrainian people. All of us at Vermilion are saddened by these tragic events. Our hearts, thoughts and prayers are with the Ukrainian people, and our hope is that a negotiated settlement can be achieved quickly. In the near future, Vermilion will be making a donation to support the Ukrainian people.

Now I will resume the formal part of the call on Slide 2, with a summary of our Q4 2021 results. We generated record fund flow from operations of $322 million in Q4, which was mainly driven by strong commodity prices. All of the global benchmarks that we have exposure to increased in the fourth quarter. European natural gas prices were exceptionally strong, increasing approximately 88% compared to the previous quarter.

The TPS benchmark averaged approximately CAD 39 per MMBtu during the fourth quarter and reached close to $80 towards the end of December due to colder weather, supply constraints and geopolitical tension in the region. We remain structurally bullish on European gas due to the recent very concerning geopolitical events in the market is even more susceptible to short-term price spikes. I will provide more insights on our outlook for European gas later in the presentation.

During the fourth quarter, we invested $146 million in E&D capital expenditures, resulting in $176 million of free cash flow, which was mainly used to reduce net debt to $1.6 billion. Our net earnings increased to $345 million in Q4, representing a $492 million increase compared to the prior quarter. This increase was mainly due to higher fund flows from operations and lower unrealized hedging losses, which is accounted for on a mark-to-market basis. Production was relatively flat from the prior quarter as production from our Netherlands and Irish business units offset natural declines in North America and the planned turnaround in Australia.

Moving on to our operational highlights on Slide 3. Production from our international assets averaged 29,123 BOEs a day in Q4, representing about 1/3 of the total corporate production. Given the strong European gas and premium Brent oil prices, our international assets contributed 65% of our fund flows and 76% of our free cash flow, which illustrates the advantages of our international diversified asset base.

International production benefited from continued strong performance from the Nijega well in the Netherlands. Production increased at core following a successful turnaround in the prior quarter, with the plant operating at peak performance during Q4.

Elsewhere in Europe, we commenced drilling of our three-well 2022 program in Germany and completed a small European gas acquisition to further consolidate our interest in the region. We expect this acquisition to reach payout in the first half of 2022. Although this is a relatively small acquisition, it provides another example of the low-risk, high-return and high-netback consolidating opportunities we have for [ potential ] access to in Europe.

In Croatia, we received approval for the spatial plan on the SA-10 gas plant, where we continue to advance both design and regulatory work in preparation for the 2023 tie-in of the 2 standing gas wells, which we drilled in 2019. These wells tested at 15 and 17 million standard cubic feet per day, respectively.

As outlined on Slide 4, production from our North American operations averaged 55,295 BOEs a day in Q4. During the fourth quarter, we drilled and brought on production 7 gross, 7.0 net light oil wells in southeast Saskatchewan. In west-central Alberta, we commenced our condensate-rich manual gas program, where we drilled 14 gross, 11.5 net wells and completed 9 gross, 8.9 net wells.

By executing the majority of this program in Q4, ahead of the busy winter season, we were able to secure our preferred service providers and reduce overall costs, resulting in approximately $85,000 of savings per well. The wells were brought on production in early 2022.

In the U.S., similar to 2021, in Q2, we plan to move an experienced drilling crew from an Alberta program down to Wyoming for the Turner drilling program. We plan to drill 6, 5.9 net wells, including 3, 2.9 net 2-mile wells, which are significantly more economic than the 1-mile laterals.

I want to step back and provide you an overview of what we accomplished in 2021, as outlined on Slide 5. We entered 2021 with an overleveraged balance sheet at 4x net debt to trailing fund flows, and our #1 priority -- financial priority was to reduce debt. With this goal and focus, we announced a modest capital program aimed at preserving liquidity, maximizing free cash flow and reducing net debt while positioning the company for long-term success.

On the operational front, we delivered average annual production of 85,400 BOEs a day, which was at the top end of our upwardly revised guidance range of 84,500 to 85,500 BOEs a day. We have met or exceeded market expectations for 7 consecutive quarters, which is a reflection of our strong execution and shift to a more load-leveled, optimized capital program.

With the help of strong commodity pricing environment, we generated a record $920 million of fund flows, $545 million of free cash flow in 2021. As a result of this strong free cash flow generation, we were able to make significant progress on debt reduction. We reduced our net debt by $365 million in 2021 and exited the year with a net debt to trailing fund flow ratio of 1.8x, less than half of what it was at the start of the year. We have now reduced net debt by over $500 million from our peak debt level of $2.2 billion in Q2 2020.

In addition to accelerating debt reduction in 2021, we announced over $700 million of strategic acquisitions, including an inventory consolidation deal in the U.S. and a high-return, low-risk acquisition to consolidate our operated natural gas assets in Ireland. We did all this without selling assets into a distressed market or issuing equity. This ensures we maximize per share value for our long-term shareholders.

Shifting to our year-end reserve update. Our 2021 total proved plus probable reserves increased 3% from the prior year to 481 million BOEs. The increase is mainly due to strategic acquisitions and positive economic revisions resulting from stronger commodity prices. We added total proved plus probable reserves in 2021 at an FD&A cost, including future development costs of $10.91 a BOE, resulting in a total -- 2021 total proved plus probable FD&A operating recycle ratio of 4.1x.

This strong recycle ratio was a reflection of our low FD&A costs, combined with our top-decile operating netbacks, which come from our exposure to premium global commodity prices. To put this into better perspective, we are currently forecasting a pro forma operating netback of over $110 per BOE in 2022 using the current commodity strip.

Including acquisitions, we replaced 140% of our production on a proved plus probable basis, and increased our total proved plus probable reserve life index to in excess of 15 years, as shown on Slide 6. However, the reason for the increase in reserve life index is the decision we made last year to rightsize our production base in order to optimize our free cash flow.

You will note that over the past 12 years, we have consistently maintained a 1P and 2P reserve life index of approximately 8 and 13 years, respectively. Our conventional and semi-conventional asset base requires low capital reinvestment due to the lower decline profiles and strong capital efficiencies. Our globally diversified asset base provides the flexibility to combine high-return PDP deals with longer-life inventory acquisitions.

Slide 7 provides a summary of the Corrib acquisition we announced on November 29, 2021. As a reminder, we consolidated an additional 36.5% working interest in our operated Corrib project in Ireland for a total consideration of approximately $600 million, including the anticipated contingent payments. The acquisition is highly accretive to all pertinent per share metrics and is expected to significantly enhance our free cash flow profile and ability to return capital to our shareholders.

An important point to understand is that the transaction has an effective date of Jan 1, 2022, which means all of the incremental free cash flow generated from this asset accrues to Vermilion from Jan 1 forward. At the time of the deal announcement, we estimated a 2022 free cash flow from this asset at $361 million.

However, with the increase in Euro gas prices since that time, we now estimate the 2022 free cash flow at approximately $500 million, which represents over 80% of the estimated purchase price. The anticipated payback period is now less than 2 years and the rate of return is in excess of 50% compared to 41% at the time of the announcement.

The closing procedures for the Corrib acquisitions are moving along as planned. We recently received competition clearance from the Competition and Consumer Protection Commission. We will continue to anticipate a deal close in the second half of 2022.

On Slides 8 and 9, I will spend a few minutes talking about our outlook for European gas. Prices have increased substantially in recent months, and the forward curve remains strong. The forward price for the balance of 2022 is over $60 per MMBtu and about $30 in 2023.

With approximately 22% of our production base being European gas, these prices are very, very impactful to Vermilion's fund flows. We have significant leverage to higher European prices, as every dollar increase adds approximately $39 million of unhedged fund flows from operations. We continue to be bullish on European gas prices in the near and long term.

In summary, storage levels are low, domestic production is declining and the use of gas for power generation is increasing, all of which is creating greater dependence on LNG. Lastly, the geopolitical backdrop we are seeing in the region today and the risk of ongoing conflict likely means there will be a risk premium in European gas prices for some time.

Slide 9 provides some more context on the underlying fundamentals that we believe support a structurally higher European gas price. To put the market into context, Europe consumes 45 to 50 Bcf a day of gas, and we expect demand to grow with the planned closure of coal and nuclear plants and the extended time lines to construct large-scale renewable energy projects in Europe. Natural gas is now recognized by the EU as a necessary transition fuel. And as a result, the use of gas in the power sector is rising.

As you can see in the plot from the EIA, domestic supply has been declining for the past decade. The North Sea and onshore production is in decline. The Dutch government has committed to shutting in the Groningen field in October 2022. This is the largest gas field in Europe that was producing over 2 Bcf a day a few years ago.

Europe is depending more on Russia and LNG imports. Today, Russia supplies 40% of Continental Europe's gas. Due to the recent events, Europe now recognizes the need to diversify its energy sources. Approval of Russia's Nord Stream 2 pipeline into Germany is now officially suspended.

That leaves LNG as a critical part of Europe's gas supply. LNG is a very competitive market due to increasing global demand, and there's a limited amount of new LNG export supply capacity being added over the next few years. New LNG projects are very capital-intensive and will require longer-term contracts to ensure development proceeds.

Given all these factors, we expect to see increased volatility and structurally higher Euro gas prices for many years to come. We recently updated our mid-cycle Euro gas price assumption to $12.50 per MMBtu from $8.50. This updated price is still 90%, 80% and 70% below current strip for '22, '23 and 2024, respectively. Our mid-cycle WTI oil price remains at $55 and AECO at $2.50.

Moving on to hedging on Slide 10. We target to be 25% to 50% hedged on a rolling 4-quarter basis. And for 2022, we are approximately 35%. That includes the 70% of the Corrib acquisition volumes that we hedged at the time of the transaction to create additional certainty for a less than 2-year payout. We are underweight oil, and the majority of our 2022 oil position was added over the past 3 months through participating structures, allowing us to benefit from high WTI and Brent prices.

Euro gas prices continue to be volatile and have increased since our press release. We have a plan to layer in additional European hedges. Our most recent transaction for the summer '22 was a swap at CAD 95 per MMBtu. As you can see on the plot on the right, in 2023, we now have less than 10% of our production hedged. Should prompt prices hold, this positions us well to achieve similar cash flows in 2022, especially when you factor in the hedge loss in 2022.

Slide 11 provides a summary of our current pro forma financial forecast based on forward strip pricing as of March 2. We currently estimate pro forma fund flows from operations of $2.3 billion or $3.2 billion on an unhedged basis. After deducting E&D capital expenditures, this translates to a free cash flow of $1.9 billion or $2.8 billion on an unhedged basis. As noted on the last slide, we have less than 10% of our 2023 production hedged.

We will continue to allocate the majority of our free cash flow to debt reduction. Based on this forecast, we estimate 2022 year-end net debt of approximately $400 million, with a net debt to trailing fund flow ratio of 0.2x. This is quite remarkable when you consider we were 4x leveraged just over a year ago, and that we balanced our focus on debt reduction while announcing $700 million of acquisitions. As you can see, our assets have the ability to generate significant free cash flow, and we believe align well with investors' focus on return on capital.

Moving to Slide 12. Our priority over the past 2 years was debt reduction. And our message was that we would reinstate a dividend once we had a line of sight to our targeted net debt to fund flow ratio of 1.5x. We've delivered on this commitment with the reinstatement of a $0.06 quarterly dividend declared today. This is a modest dividend that represents less than 2% of our forecasted 2022 fund flows.

Going forward, we will continue to prioritize free cash flow to debt reduction until we reach our next mid-cycle debt target of $1.2 billion of total debt. With this debt target approaching in the second half of 2022, we will look to increase the amount of capital returned to shareholders, either in the form of an increase to the base dividend, share buybacks, issuance of a special dividend or a combination of these options. At the current valuations, buybacks are compelling and even more impactful as we did not issue equity over the past 2 years.

In addition, we will continue to be opportunistic for compelling acquisitions that enhance our portfolio and create long-term value for our shareholders. Based on our forecast, we expect to exit 2022 with a total debt of $400 million and would be effectively debt-free in 2023 under the status quo. Vermilion is in a very strong financial position.

As shown on Slide 13, Vermilion continues to trade at the highest free cash flow yield among our peers, approximately twice the average in 2022 and 2023 based on these estimates from RBC. Our 2022 free cash flow per share is over $11, including the hedges, and at the current price, the free cash flow yield is over 40%. This is despite the outlook for strong free cash flow in years to come.

Before we open it up for Q&A, I want to make some closing remarks on our recent leadership changes, in my view, on the company going forward. As you would have read in the press release, our Executive Chairman, Lorenzo Donadeo, has announced his intention to retire from Vermilion effective September 1, 2022. As many of you are aware, Lorenzo was the co-founder of Vermilion and instrumental in creating what Vermilion is today, along with creating significant value for our shareholders during his tenure. He served as our leader for nearly 1.5 decades and has provided his guidance as our Chairman of the Board for the past 6 years.

Mr. Bob Michaleski will be appointed Lead Director effective May 12, and will assume the role of independent chairman on Lorenzo's departure effective September 1. I would like to thank Lorenzo as well as Curtis Hicks for their mentorship and leadership during these difficult past few years, which has positioned the company for long-term success.

Personally, after 16 years with the company, I'm truly honored and excited to become the president. I'm fortunate to have worked on the majority of our assets and, more importantly, had the pleasure to work with many of our talented employees. With our new leadership team in place, engaged staff, diversified portfolio, focus on ESG, and a much stronger balance sheet, I believe Vermilion is very well positioned to move forward with our long-term strategy of creating value for our shareholders.

That concludes my prepared remarks. And with that, I would like to open it up for questions.

[Operator]

[Operator Instructions] We'll take our first question from Patrick O'Rourke with ATB Capital Markets.

[Patrick O'Rourke, analyst]

Just a few questions for you here this morning. First one is with respect to cash taxability of the business. I know, Ireland, for example, is an asset where we never thought it would hit cash taxability. But I don't think we really -- anyone envision sort of prices and netbacks that you're realizing there.

I know you do have, in and around pre the acquisition here, about $1 billion in capital loss pools. But maybe could you give us the outlook in terms of cash taxability for the business over the next few years? I know it's jurisdictionally complicated.

[Anthony Hatcher, executive]

Thanks, Patrick. I'll pass it over to Lars to talk about that.

[Lars Glemser, executive]

Patrick, thanks for the question. In terms of 2022 cash taxability, the way to think about it is a range of approximately 9% to 11% for full year 2022. That includes the pro forma impact of the Corrib acquisition for the full year. We are not forecasting to be cash taxable in Ireland just because of the vast investments that were made historically.

In terms of go forward, I think that's an appropriate cash tax range to think about things. Obviously, things are very fluid right now with strip pricing. But that's a good range to think about it in terms of the next few years here.

[Patrick O'Rourke, analyst]

Okay. And then in terms of the outlook and the ability from a regulatory, from an operational and a geological perspective, is there any ability to accelerate operations in the Netherlands to kind of cash in on the strong pricing that you're seeing in Europe right now? Or is it going to kind of be steady state?

I know that, historically, permitting has been a little bit slower than I think you have hoped for, and obviously, a little bit different than we see here in Canada and North America. But is there any ability to accelerate or increase that production in the near term?

[Anthony Hatcher, executive]

Well, thanks, Patrick. And this is Dion. I'll take this one. I mean, those discussions, I think, were occurring before the current situation. We worked closely with regulatory bodies and worked through the established -- well-established permitting process. If you look at our plans for the near term, we've got 2 wells planned for Netherlands in the midyear, and we like that area. There's some additional targets out of those wellbores, as well as it's an area we've had some success with some larger discoveries.

And then we've got 3 wells that are in the later stages of permitting, which we would hope to drill in the first half of 2023. As a reminder, in CEE, we do have the 2 wells there that tested at 15 million and 17 million a day, and we're working to get that infrastructure in place. We've shot 3D seismic there. And we plan to drill 2 more wells on that permit, which is to follow up on those successful gas wells.

So I think the conversation continues to evolve. It's quite fluid right now. But security of supply is something that is prevalent, and I think these discussions will continue as we go forward. So no near-term changes that I can speak to, but I think the conversations and, again, the need for security supply are likely going to increase in the upcoming weeks and months.

[Patrick O'Rourke, analyst]

Okay. And then a final question here, and then I'll hang up and listen. But in terms of the return of capital mechanism, I think you guys had some really good metrics and disclosure here about, pro forma, where the balance sheet gets to by the end of this year.

Payout ratio on that dividend is pretty small. Can you maybe give us your thoughts on how you're thinking of potential return of capital mechanism, whether it be dividend increases, how the kind of trajectory and cadence of that would look and/or special or variable dividends or buybacks?

[Anthony Hatcher, executive]

I'll pass this one to Lars again.

[Lars Glemser, executive]

Yes. Patrick, Lars here, again. And just to -- a bit of background as well in terms of why our priorities are in the order they are. The priority today is to continue allocating free cash flow beyond that base dividend to debt reduction. And that will be until we reach that next debt target of $1.2 billion.

That debt target is fully burdened with the acquisitions that we announced in 2021. We did in excess of $700 million of acquisitions while we were deleveraging, and we did that without issuing any shares. And I think that's something with hindsight now that was very key to our success in 2021, and we want to continue on that and make sure that we're in a position to be opportunistic when compelling acquisitions are available.

Now as we get to that $1.2 billion target, we will look to augment the return of capital to shareholders. Right now, what we're contemplating are increases to the fixed dividend. To put it into perspective, a 10% increase to that dividend would equate to about $4 million per annum of increased dividend. And then I think when we want to return capital beyond that, we'll look at some of the variable structures.

At this point, share buybacks are screening very high in terms of what that next mechanism would be just based on the valuation that we're seeing here. So I think that as we have line of sight to that $1.2 billion target second half of this year, you can look to us to augment that return of capital through those methods.

[Operator]

And moving on, we'll go to Greg Pardy with RBC Capital Markets.

[Greg Pardy, analyst]

So I wanted -- well, I guess the first thing I should be doing is just wishing absolute best wishes to Lorenzo in his next adventure. So it's been great to work with him.

But Dion, you've talked about security of supply. I guess the question is this, have you already been approached, either by politicians or regulators or what have you, because you're, again, one of the very few onshore gas players in Europe in terms of either -- not so much in terms of accelerating activity, but even being incentivized to start to grow production? Or do you think it's too early with where we sit today for those types of messages to be sent?

[Anthony Hatcher, executive]

Thanks, Greg, for the question. I think it's too early. I mean the situation is very, very fluid. And so at this point, our plan is to work on our inventory. We're actually adding some staff in the Netherlands unit to further enhance our technical capabilities, which are already strong. But it's just too early, and so we're ready and prepared for those discussions when they do occur. And again, no easy answers here, unfortunately, given the current situation.

[Greg Pardy, analyst]

Okay. Okay. And then just 2 quick ones. I just want to make sure I heard Lars correctly then. So when you hit the $1.2 billion, are you going to look to increase the dividend and then go to a share buyback? Or is everything on the table at the same time? I just want to make sure I got it straight.

[Lars Glemser, executive]

Yes. I would say, at that point, Greg, everything is on the table. The one thing that we are going to do with the fixed dividend is maintain a sense of discipline there in terms of not exceeding 5% to 10% of cash flows at that mid-cycle price deck. So we think that, that's going to instill a level of discipline.

And then when there is capital to return above and beyond that, that's when we would look at some of the variable structures. And right now, we feel that buybacks would screen the highest of those opportunities.

[Greg Pardy, analyst]

Okay. Okay. Great. And the last question for me is, it's a small chunk of production, but what is the profile -- what does the production profile look like with Australia? You mentioned the planned turnaround in the fourth quarter and so forth. But how does that -- how does that production look shape-wise over the course of this year?

[Anthony Hatcher, executive]

I'll just talk a little bit to our corporate first, and I can pass it over to Darcy to talk about the ABU. I mentioned earlier those Mannville wells. We did get a good jump on the North American program in which we kicked off the 14 drills and 9 completions last year. So that allowed us to bring those wells on early in Q1. So I think where you're going to see, from a North American point of view, some good production there.

Internationally, we did have strong production on that Netherlands Nijega well as well as strong run rates in Ireland. And finally, the Australia, we do budget for cyclones there, and we haven't seen that to date. So I think Q1 is trending well, Greg.

As a reminder, we do schedule a lot of our planned turnaround activity in Q2 and, to some degree, in Q3. So I think you'll see us on the upper end of the range in Q1 and potentially on the lower end of range in Q2 just with those planned activities that we want to do outside of the weather season to get those done.

In the second half of the year, before I pass it over to Darcy, I think what you'll see is with our U.S. program kicking off in April, that's really a second half volume. Our SARS kicks off June 1. So again, second half volume and then these Australia wells, which are very impactful wells that, typically, in excess of 1,500 barrels a day. Again, that volume would contribute in the second half of the year. But with that, I'll pass it over to Darcy to talk about the ABU profile.

[Darcy Kerwin, executive]

Yes. So Greg, as you know, we have planned a two-well drilling program in Australia this year. We've got a jack-up rig contracted for that program. That rig will mobilize from [ Daintree ], which is the closest port to our Wandoo facility. So we're first in line for that rig. The cyclone season in Australia kind of runs out to March, end of March. And as soon as we get past that kind of cyclone season and see a good weather window, we'll mobilize that rig out to the field to kick off that drilling program.

So that would mean first production from those wells coming on kind of early Q2 right there -- or sorry, late Q2, kind of June, end of June or summer. Like Dion said, they're a highway of great wells. We hope those wells will be capable of producing kind of over 1,500 barrels a day IPs, and we'll restrict that to optimize our crude marketing agreements. And then that program has quite robust economics, so you can expect to see the Australian production kind of ramp up towards the second half of the year.

[Anthony Hatcher, executive]

Thanks, Darcy. Thanks, Greg. And just a reminder, that crude is -- we're actually -- the premium has actually increased to $14. It's been a good market for us.

[Operator]

[Operator Instructions] Next, we'll go to Menno Hulshof with TD Securities.

[Menno Hulshof, analyst]

I might have misheard this, but I thought I heard you say that you did a $95 per MMBtu gas walk. Can you just -- if I heard that correctly, can you just elaborate on how that was structured, and whether you're seeing other opportunities to strike those sorts of deals?

[Anthony Hatcher, executive]

No, you heard that correct, Menno. We did layer in a $90-plus hedge for the summer. But I'm going to maybe pass it over to Lars. We've been doing a lot of work on this. We have a plan in place. But Lars can elaborate a little more on our strategy with respect to these volatility and, obviously, high prices we're seeing in Europe right now.

[Lars Glemser, executive]

Yes. So Menno, just to recap as well. We're about 55% hedged for European gas full year 2022. What we did as an executive team and then a subset of that is we met about a month ago to ensure that we were ready to be prepared for any kind of volatility in that European gas market. What we have concluded internally is we would be comfortable going up to a 75% hedge position on European gas. So the transaction that Dion alluded to was a piece of that.

What we're looking to do is not be overly speculative in terms of trying to time the top of the market. But what we would like to do is layer in with some hedges that we are comfortable with that align with what we want to achieve from a financial priority perspective. So the summer '22 hedge at CAD 95 MMBtu, that was done as an outright swap and is part of the execution of that strategy.

[Menno Hulshof, analyst]

Terrific. That's super helpful. And I'll just pivot over to Hungary and Slovakia since they bump right up against the Ukraine. Can you just remind us of your work commitments for this region? I'm pretty sure you're not doing a whole lot this year, but maybe over the next several years, and I think they're pretty small. But if you could confirm that, that would be great. And then more generally, how are you thinking about managing geopolitical risk for that part of the portfolio?

[Anthony Hatcher, executive]

Sorry, Menno, I might have missed the last part of the question. How do you plan to?

[Menno Hulshof, analyst]

Yes, how are you thinking about managing geopolitical risk for Hungary and Slovakia specifically?

[Anthony Hatcher, executive]

Okay. Thank you. Okay. For our CEE business unit, if you look at our activities planned for 2022, I'll start with Croatia. We have the -- 2 wells that we plan to drill and follow up to you, those mentioned earlier where we tested 2 wells at 15 million and 17 million a day. Our activities in the well are focused on the gas plant, which is physically moved to Croatia. And we're doing the necessary permitting and regulatory work to -- just to get that installed and bring it online in 2022. So from a Croatia point of view, that's proceeding.

Our Hungary plans, we've got 3 wells planned, 2 of them are in a permit what we call Kadarkút, which is an oil play. We've shot 3D seismic over that region. We're north of a 10,000 barrel a day production that's on trend with us. So we like the prospectivity of those 2 wells.

In addition, we have 1 well in which we plan to test a shallow gas concept. So relatively cheap, just over $1 million, but it's something that works, and we think it will, but there's always some risks with these type of wells. But if it works, again, we would see some running rate for that as an opportunity to bring more European gas into the portfolio.

So the future years, if you look to '23, '24 onward, I think it will be partially contingent on our results this year. But again, we're quite excited with the prospectivity of what we see, especially in light of the additional 3D seismic work that we did. Maybe, Darcy, do you want to comment on the geopolitical risk and any potential impact on our business?

[Darcy Kerwin, executive]

Yes, sure. Thanks, Dion. Menno, as you correctly stated, both Hungary and Slovakia share borders with the Ukraine, we don't really have any activities planned in Slovakia in the near term, Hungary, we got a couple of wells planned this year. I would say -- I'd point out that Hungary, where we do have some activity planned, is a NATO country. I think the kind of noise is coming from that country today is that they are aligned with the rest of Europe on condemning the actions of Russia.

So I think the geopolitical risk of this overspilling into Hungary probably no different than any other NATO country today. We do hear a bit of a humanitarian crisis at the border of -- all the Ukrainian's borders, including Hungary. But I don't see that, that has really any impact to our current small operations in Hungary, with 1 gas flow there that's producing at small rate. So I don't really see any issues for us. It's something we'll have to continue to monitor though as we move through the year and as the situation continues to evolve.

[Anthony Hatcher, executive]

Thanks, Darcy.

[Operator]

Moving on. We'll go to Josef Schachter with Schachter Energy Research.

[Josef Schachter, analyst]

First one I wanted to ask was about Ukraine. You were doing some work there. Did you have employees in country, either expats or locals? And have you been able to get them out of the country, if you did have any working for you?

[Anthony Hatcher, executive]

We -- just to clarify, we do not have operations in Ukraine. We did have a permit there, at one point, and we relinquished it quite a while ago. So no lands, no permits and no staff in Ukraine.

[Josef Schachter, analyst]

Okay, super. The second question for me. France, with the operations you have there. You've talked about some of the other countries, and that will take some time for them to realize they need to speed up any potential for domestic increases. Are there any big upsides in terms of your operations in France that could be reactivated or moved forward if Biden and NATO decide to cut off exports from Russia of oil and products going forward?

[Anthony Hatcher, executive]

Thanks, Josef. I would say, not at this time. I mean, we continue to meet frequently with our -- again, like all jurisdictions which we operate in. But at this point, there's been no plans to further enhance the development. 2040 is a long way out, and so we have, we believe, sufficient time to produce those reserves, and we have some opportunities to drill.

Our focus right now has been on workovers, waterflood management. It's a very low decline asset for us and generates significant free cash flow. So at this point, that's the role it's playing in our portfolio. As we every year go through the budgeting process, we would look to allocate capital to our highest rate of return projects fundamentally. And so France will be one of those considerations. But at this point, no changes to the plans staged by those governments with respect to 2040.

[Josef Schachter, analyst]

And one last one, if I can. Corrib in Ireland, is there a land in the area that you've done seismic on that potentially might give you some potential for more drilling and extension of the life of the project?

[Darcy Kerwin, executive]

Yes. Thanks, Josef. It's Darcy here. I'll take your question. So in Corrib, I'll start with the existing assets. We do see and are working on some optimization potential within the existing Corrib field, both with the gas plant part of the assets, so looking at compression optimization, trying to lower the inlet pressure to that plant to be able to extend the field life there.

We also see some workover opportunities within that field that the team is currently looking at some potential bypass pay in a couple of the wells that we would look to activate again, we think, extending the life of that field.

Thirdly, this is something that's a little bit further out. But the team will be looking at it as within our existing Corrib acreage. There are some other targets that have some seismic that we will look at. And again, the idea there would be to extend the life and the increase of production from that field. And then, finally, there's some acreage around us that's owned by other operators that if they have success, could potentially tie-in and then further extend the life of the infrastructure there.

[Operator]

And that does conclude the question-and-answer session. I'd like to turn it back to the presenters for any additional or closing comments.

[Anthony Hatcher, executive]

Well, I want to thank everyone for participating in our Q4 '21 results conference call. And with that, I hope you enjoy the rest of your day.

[Operator]

Thank you. And that does conclude today's call. We'd like to thank everyone for their participation. You may now disconnect.