Vermilion Energy Inc. Q4 FY2021 Earnings Call

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

Good morning, everyone. 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 referring to a PowerPoint presentation to discuss the Q4 2021 and year-end results we announced this morning, which is available on our website under Invest with Us and Events and Presentations. Please take note of our advisory on forward-looking statements at the end of the presentation, which details the forward-looking information, non-GAAP measures, and oil and gas terms we will use today, as well as the risk factors and assumptions connected to this discussion. Before diving into the specifics of our presentation, I want to address the ongoing situation in Ukraine. The invasion of Ukraine by Russia has led to immense suffering and tragic consequences for its people. Everyone at Vermilion shares in the sorrow over these events. Our thoughts and prayers are with the Ukrainian people, and we hope for a swift negotiated resolution to the conflict. Vermilion plans to make a donation to support the Ukrainian people. Now, let's move to Slide 2, where I will summarize our Q4 2021 results. We achieved record fund flow from operations of $322 million in Q4, primarily driven by robust commodity prices. All global benchmarks we track saw increases in the fourth quarter, with European natural gas prices being notably strong, rising approximately 88% from the previous quarter. The TPS benchmark averaged around CAD 39 per mmbtu in Q4, peaking close to CAD 80 by the end of December due to colder weather, supply restrictions, and geopolitical tensions. We remain optimistic about European gas, especially following the recent geopolitical developments that make the market more vulnerable to short-term price spikes. I will elaborate on our perspective regarding European gas later in the presentation. In Q4, we invested $146 million in exploration and development expenditures, resulting in $176 million of free cash flow, which was primarily directed toward lowering our net debt to $1.6 billion. Our net earnings rose to $345 million in Q4, an increase of $492 million compared to the previous quarter, predominantly due to higher fund flows from operations and reduced unrealized hedging losses recorded on a mark-to-market basis. Production remained steady from the prior quarter, as gains from our Netherlands and Irish business units countered natural declines in North America and planned downtime in Australia. Moving on to our operational highlights on Slide 3, production from our international assets averaged 29,123 BOEs per day in Q4, accounting for about one-third of our 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, showcasing the benefits of our diversified asset base. Our international production was bolstered by continued strong performance from the Nijega well in the Netherlands, and production increased at core following a successful turnaround in the previous quarter, with peak performance achieved during Q4. Additionally, we began the drilling of our 3-well 2022 program in Germany and completed a small European gas acquisition to reinforce our interests in the area. We anticipate this acquisition will reach payout in the first half of 2022. While this acquisition is relatively modest, it exemplifies our strategy of low-risk, high-return opportunities in Europe. In Croatia, we secured approval for the spatial plan on the SA-10 gas plant and are progressing with design and regulatory work to prepare for the 2023 tie-in of two gas wells we drilled in 2019. As shown on Slide 4, our North American operations averaged 55,295 BOEs per day in Q4. During the quarter, we drilled and brought 7 gross, 7 net light oil wells in southeast Saskatchewan into production. In Central Alberta, we launched 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 most of this program in Q4 ahead of the busy winter season, we secured preferred service providers and reduced costs, saving around $85,000 per well. The wells will start production in early 2022. For the U.S., similar to 2021, we plan to move an experienced drilling crew from Alberta down to Wyoming for the Turner drilling program, where we will drill 6 wells, including 3 2-mile wells that are significantly more economical than the 1-mile laterals. Looking back at 2021, which I will discuss further on Slide 5, we entered the year with a heavily leveraged balance sheet at 4x net debt to trailing fund flows, with our primary objective being debt reduction. To achieve this, we announced a modest capital program focused on maintaining liquidity, maximizing free cash flow, and reducing debt while positioning the company for long-term success. Operationally, we achieved an average annual production of 85,408 BOEs per day, at the top end of our revised guidance of 84.5 to 85.5. We have met or exceeded market expectations for seven consecutive quarters, reflecting our strong execution and shift to a more optimized capital program. With favorable commodity prices, we recorded a record $920 million in fund flows and $545 million of free cash flow in 2021. This strong free cash flow generation allowed us to make notable progress in reducing debt, decreasing it by $365 million throughout the year, and finishing 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 reduced net debt by over $500 million from our peak level of $2.2 billion in Q2 2020. Alongside accelerated debt reduction, we announced over $700 million in strategic acquisitions, including a consolidation deal in the U.S. and a high-return deal in Ireland for our operated natural gas assets, all achieved without selling assets in a distressed market or issuing equity, which helps maximize per-share value for our long-term shareholders. Regarding our year-end reserve update, our total proved plus probable reserves increased by 3% from the previous year to 481 million BOEs. This increase is largely due to strategic acquisitions and positive revisions driven by stronger commodity prices. We added proved plus probable reserves at a cost of $10.91 per BOE, resulting in a total proved plus probable operating recycle ratio of 4.1x for 2021. This strong ratio mirrors our low costs against top decile operating netbacks stemming from exposure to premium global commodity prices. As we forecast, our operating netback is expected to exceed $110 per BOE in 2022 using the current commodity strip. When including acquisitions, we replaced 140% of our production on a proved plus probable basis and raised our reserve life index to over 15 years. The increase in reserve life index stems from our decision last year to optimize our production base to enhance free cash flow. 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 demands low capital reinvestment due to their lower decline profiles and strong capital efficiencies. Additionally, our globally diversified assets enable us to balance high-return production deals with longer-life inventory acquisitions. On Slide 7, we outline the Corrib acquisition we announced on November 29, 2021. To recap, we consolidated an additional 36.5% working interest in our operated Corrib project in Ireland for around $600 million, alongside anticipated contingent payments. This acquisition is highly beneficial across all relevant per-share metrics and is expected to significantly bolster our free cash flow profile and capacity to return capital to shareholders. It’s important to note that the transaction has an effective date of January 1, 2022, meaning all incremental free cash flow from this asset will start accruing to Vermilion from that date. At the time of the announcement, we projected 2022 free cash flow from this asset at $361 million, but due to rising euro gas prices since then, we now estimate the 2022 free cash flow at about $500 million, which equates to over 80% of the estimated purchase price. The anticipated payback period has now fallen below two years, with a rate of return exceeding 50%, up from 41% at the announcement time. The closing procedures for the Corrib acquisition are progressing as expected; we recently obtained competition clearance from the Competition and Consumer Protection Commission and anticipate closing the deal in the second half of 2022. On Slides 8 and 9, I will provide insights into our outlook for European gas. Prices have experienced a significant rise recently, with the forward curve remaining strong. The forward price for the remainder of 2022 is above $60 per mmbtu and around $30 in 2023. With around 22% of our production focused on European gas, these prices have a substantial impact on Vermilion's fund flows, as each dollar increase translates to roughly $39 million of unhedged fund flows from operations. We continue to hold a positive outlook on European gas prices both in the near and long term. In summary, storage levels are low, domestic production is decreasing, and gas usage for power generation is on the rise, increasing reliance on LNG. Moreover, the current geopolitical context suggests a risk premium in European gas prices is likely to persist for some time. Slide 9 offers additional context for the underlying fundamentals we believe will support persistently high European gas prices. To frame the market, Europe consumes between 45 to 50 Bcf of gas daily, with demand expected to grow due to planned coal and nuclear plant closures and delays in large-scale renewable energy developments. Natural gas is now recognized by the EU as a crucial transition fuel, leading to increased use in the power sector. A report from the EIA shows that domestic supply has been on the decline for the past decade, with North Sea and onshore production shrinking. The Dutch government's commitment to closing the Groningen field in October 2022, historically Europe's largest gas field, adds to this issue as it produced over 2 Bcf daily a few years ago. Europe’s dependence on Russia and LNG imports is growing, with Russia supplying 40% of continental Europe's gas. Recent events have prompted Europe to acknowledge the necessity to diversify its energy sources, leading to the suspension of approval for Russia's Nord Stream 2 pipeline into Germany, which underscores the importance of LNG in Europe’s gas supply. The LNG market is becoming increasingly competitive due to rising global demand, while new LNG export capacity additions are limited in the coming years. Capital-intensive new LNG projects will require long-term contracts for development to proceed. Given these circumstances, we anticipate continued volatility and structurally high European gas prices for years ahead. We updated our mid-cycle euro gas price assumption to $12.50 per mmbtu from $8.50, which remains significantly below the current strip for 2022, 2023, and 2024. On Slide 10, we discuss our hedging strategy. We aim to hedge 25% to 50% on a rolling four-quarter basis and are currently about 35% hedged for 2022. This includes 70% of the core acquisition volumes we hedged at the time of the transaction to ensure a less than two-year payout. We have positioned ourselves favorably in light of high WTI and Brent prices. We continue to see volatility in euro gas prices, with a plan in place to layer in additional European hedges, the most recent of which was a swap at CAD 95 per mmbtu for summer 2022. Our 2023 production has less than 10% hedged, which, if prompt prices maintain, will allow us to achieve similar cash flow levels as expected in 2022, considering the hedge loss. Slide 11 summarizes our current pro forma financial forecast based on forward strip pricing as of March 2. We estimate pro forma fund flows from operations at $2.3 billion or $3.2 billion on an unhedged basis. After accounting for E&D capital expenditures, this translates to free cash flow of $1.9 billion or $2.8 billion on a non-hedged basis. As mentioned earlier, we have less than 10% of our 2023 production hedged, and we will continue directing the majority of free cash flow toward debt reduction. Based on this forecast, we anticipate ending 2022 with net debt of about $400 million and a net debt to trailing fund flow ratio of 0.2x, which is impressive given we were 4x leveraged a year ago while balancing debt reduction with $700 million in acquisitions. Our assets can generate significant free cash flow, aligning well with investor focus on returns of capital. Moving to Slide 12, our overarching priority over the last two years has been debt reduction. We committed to reinstating a dividend upon reaching our targeted net debt to fund flow ratio of 1.5x. We fulfilled this promise today by declaring a quarterly dividend of $0.06, which is modest and represents less than 2% of our projected fund flows for 2022. Going forward, we will continue prioritizing free cash flow for debt reduction until we reach a mid-cycle debt target of $1.2 billion. As this target approaches in the second half of 2022, we will consider increasing capital returns to shareholders through dividend hikes, share buybacks, special dividends, or a combination of these strategies. Given the current valuation, buybacks are appealing, especially since we haven’t issued equity over the past two years. We will also remain opportunistic for acquisitions that strengthen our portfolio and provide long-term value to shareholders. Based on our forecasts, we expect to exit 2022 with total debt near $400 million and anticipate being effectively debt-free by 2023. Vermilion is in a robust financial position. As shown on Slide 13, Vermilion continues to yield the highest free cash flow among peers, roughly twice the average for 2022 and 2023 according to RBC estimates. Our 2022 free cash flow per share exceeds $11, factoring in hedges, and with current prices, the free cash flow yield is above 40%, despite a strong outlook for continued free cash flow in the coming years. Before we enter the Q&A session, I’d like to conclude with remarks regarding our recent leadership changes and my perspective on the company’s future. As stated in our press release, our Executive Chairman, Lorenzo Donadeo, is set to retire from Vermilion effective September 1, 2022. Many of you know that Lorenzo co-founded Vermilion and has been crucial in shaping our company and creating substantial shareholder value over his nearly 1.5-decade leadership. He has provided guidance as our Chairman of the Board for the past six years. Bob Michaleski will take over as Lead Director starting May 12 and will become independent Chairman upon Lorenzo’s departure in September. I want to extend my gratitude to Lorenzo and Curtis Hicks for their mentorship during what have been challenging years, positioning the company for future success. Personally, after 16 years at Vermilion, I am honored and excited to be taking on the role of President. I have had the privilege of working on most of our assets and, more importantly, with many talented employees. With our new leadership team, engaged workforce, diverse portfolio, commitment to ESG, and stronger balance sheet, I believe Vermilion is superbly positioned to advance our long-term strategy of delivering value to our shareholders. That concludes my prepared remarks, and now I’d like to open the floor for questions.

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 anyone envisioned sort of prices and netbacks that you're realizing there. I know you do have around $1 billion in capital loss pools before the acquisition here, 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.

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

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 going 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 in terms of the next few years.

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

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 work closely with regulatory bodies and work through the established, well-established permitting process. If you look at our plans for the near term, we've got 2 wells planned for the Netherlands in the mid-year, and we like that area. There are 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 that tested at 15 million and 17 million a day, and we're working to get that infrastructure in place. We've shot 3 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 of supply are likely going to increase in the upcoming weeks and months.

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 the pro forma where the balance sheet gets to by the end of this year. The 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?

I'll pass this one to Lars, again.

Yes. Patrick, Lars here, again. And just a bit of background as well in terms of why our priorities are in the order that 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 in the second half of this year, you can look to us to augment that return of capital through those methods.

I want to start by extending my best wishes to Lorenzo as he embarks on his next adventure. It has been a pleasure working with him. Dion, you have mentioned security and supply. My question is whether you have been approached by politicians or regulators, given that you are one of the very few onshore gas players in Europe. Are there any incentives for you to begin increasing production, or do you believe it is still too early for such discussions?

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.

Okay. Okay. And then just two 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.

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 scream the highest of those opportunities.

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 production look shape-wise over the course of this year?

I'll just talk a little bit to our corporate first, and I can pass it over to Darcy to talk about 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 what 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, in 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 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 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. Sas kicks off June 1. So again, second half volume and then these Australian wells, which are very impactful wells that typically are in excess of 1,500 BOEs 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.

So, Greg, we have a plan for a two-well drilling program in Australia this year, and we've contracted a jack-up rig for this program. That rig will move from the nearest port to our Wandoo facility, positioning us first in line for it. The cyclone season in Australia usually lasts until the end of March. Once we get through that season and find a favorable weather window, we will send the rig to the field to begin the drilling program. This means we can expect first production from these wells around early Q2, but realistically, it will be late Q2, around the end of June. As Don mentioned, these are high-quality wells, and we anticipate that they will be capable of yielding over 1,500 barrels a day IPs. However, we plan to restrict production to optimize our crude marketing agreements, and this program has very strong economics. Therefore, you can anticipate a ramp-up in Australian production in the latter half of the year.

And just a reminder, the premium has actually increased to $14. It's been a good market for us. With that, we'll open it up to the next question.

I might have misheard this, but I thought you mentioned a $95 per mmbtu gas swap. Can you confirm if I heard that correctly and explain how that was structured? Are you seeing other opportunities to make similar deals?

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 Europe right now.

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 we would like to 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 2022 hedge at CAD 95 mmbtu was done as an outright swap and is part of the execution of that strategy.

Terrific. That's super helpful. And I'll just pivot over to Hungary and Slovakia since they bump right up against 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?

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

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

Thank you. For our CEE business unit, looking at our activities planned for 2022, I'll begin with Croatia. We plan to drill two wells, following up on the earlier mentioned tests at rates of 15 million and 17 million a day. In Hungary, our focus is on the gas plant that is being relocated to Croatia, and we are handling the necessary permitting and regulatory processes to get it installed and operational in 2022. So from the perspective of Croatia, everything is progressing well. For Hungary, we have three wells planned; two of these are in a permitting stage known as Kadarkút, which is focused on oil production. We have conducted 3D seismic surveys in that area and are predicting a production trend exceeding 10,000 barrels a day. We are optimistic about the potential of those two wells. Additionally, we plan to test a shallow gas concept with one well, which is relatively inexpensive at just over $1 million. While there is some risk associated with these wells, if successful, we see it as an opportunity to incorporate more European gas into our portfolio. Looking to the future years, particularly 2023 and beyond, our progress may depend on the results we achieve this year. However, we are genuinely excited about the potential, especially with the recent 3D seismic work we undertook. Darcy, would you like to address the geopolitical risk and its potential impact on our business?

Yes, thanks, Dion. Menno, as you mentioned, both Hungary and Slovakia share borders with Ukraine. We don't have any immediate plans for activities in Slovakia; however, we do have a couple of wells planned in Hungary this year. I would like to highlight that Hungary is a NATO country, and the current concerns coming from that country indicate that they are aligned with the broader European stance on condemning Russia's actions. Therefore, the geopolitical risk of this spilling over into Hungary is likely no different from any other NATO country at this time. We are aware of a humanitarian crisis at the borders, including Hungary, but I don’t believe that it has any significant effect on our current small operations there, which include one gas flow operating at a minor rate. Thus, I don’t foresee any issues for us. However, it is something we will need to keep monitoring as the year progresses and as the situation develops.

First one I wanted to ask was about Ukraine. You were doing some work there. Did you have employees in the 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?

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

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 move forward if Biden and NATO decide to cut off exports from Russia of oil and products going forward?

Thanks, Josef. I would say not at this time. We continue to meet frequently with all the jurisdictions in which we operate. However, there are currently no plans to further enhance development. The year 2040 is still a long way out, and we believe we have ample time to produce those reserves, along with some opportunities for drilling. Our current focus has been on workovers and waterflood management. This asset has a very low decline for us and generates significant free cash flow. Thus, that is its role in our portfolio. Each year, during the budgeting process, we look to allocate capital to our highest rate of return projects. France will be one of those considerations, but at this time, there are no changes to the plans established by those governments regarding 2040.

And one last one, if I can. Corrib in Ireland, is there 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?

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 or looking at compression optimization to try 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 by patch pay and 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 is, 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.

I want to thank everyone for participating in our Q4 '21 results conference call. Enjoy the rest of your day.

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