International Petroleum Corporation (IPCO) Earnings Call Transcript & Summary

Okay. So a very good afternoon to everybody, and welcome to IPC's 2022 Capital Markets Day presentation. My name is Mike Nicholson, and I'm the CEO of IPC. Also joining me this afternoon to present is William Lundin; and Chris Hogue, who will go through the 2022 outlook and the details on the asset overview; they'll then pass across to Christophe Nerguararian, the CFO, and Christophe will run through the financial forecast for 2022; who will then pass to Rebecca Gordon, who is our Vice President of Investor Relations, and Rebecca will give an update on our reserves valuation. And then we'll finish with some conclusion and some concluding remarks and Q&A session. So quite a lot of material to get through. To start with, so before we get into the 2022 forecast and long-term plan, I want to spend just a couple of moments highlighting the exceptional performance the IPC delivered in 2021. Our production for the full year was just above 45,000 barrels of oil equivalent per day, and that was in excess of our high-end guidance of 43,000 BOE per day. On the cost front, excellent delivery. Our full year operating costs were $15 per BOE, and that was below our latest guidance. The capital program came in at just under $50 million, in line with guidance. And with strong production and increasing commodity prices across the entire energy complex, IPC was able to deliver its record financial performance in terms of cash flow generation. Full year operating cash flow was USD 337 million, and full year free cash flow was USD 263 million. And based upon the current market capitalization of the company, that represents an extremely attractive free cash flow yield of 26%. The free cash flow has been used to deleverage, and the balance sheet is in extremely good shape. The net debt decreased from $321 million at the beginning of the year, down to now $94 million at the end of 2021. And the leverage decreased significantly from 3x at the beginning of the year to less than 0.3x at the end of 2021. Will will get into this and Chris in their section in much more detail, but a phenomenal performance in a low CapEx year. In terms of our reserves, we managed to replace more than 90% of our 2P reserves and now have 270 million barrels of oil equivalent and a huge increase in contingent resources, above 300 million barrels of additions, lifting our 2C resources to above 1.4 billion barrels. And a continued strong strategy with respect to ESG. And we're well on track to meet our long-term targets of reducing our net carbon emissions intensity by 50% through the end of 2025. And also a very good HSE performance for the full year with no material incidents to report. So all in all, an exceptional 2021. I think as we look ahead over the next 5 years, there's an even brighter future for IPC, and we've created a phenomenal platform to create significant value for our shareholders. We're lifting our long-term production forecast up by 2,000 barrels a day from 45,000 to 47,000 barrels a day, flat over the next 5 years. And assuming average Brent oil prices, between $65 and $95 per barrel, we're in a position to generate between $900 million and $1.8 billion in free cash flow, and that represents an annual free cash flow yield on average of between 18% and 36%. And that gives us a phenomenal position to continue to return value to our shareholders, to continue to acquire and grow the business through M&A and to continue to mature the significant contingent resource base that we have, which is in excess of 1.4 billion barrels of oil equivalent. If we start now with the reserve growth position. It's been extraordinary since we started back in 2017, we had just 29 million barrels of oil equivalent. If you look at the light blue bar on the bottom of this slide, you can see that we've produced more than double our 2P reserves, 65 million barrels produced in the first 5 years. And if you add the 270 million barrels that we have at the end of last year, that's a total reserve increase, inclusive of production, of more than 11x. We've also significantly increased the longevity and the quality of our reserve base up from 8 years to 16 years. So when you see the numbers that underpin our 5-year business plan, there are significant remaining resources of close to 2/3 of that resource base at the end of the 5-year business plan. Contingent resources has been even more dramatic when IPC started. We didn't have any contingent resources. And through a series of upgrades to existing assets and through acquisition of companies, assets and land acquisitions, we've been able to significantly increase our contingent resource base from last year to 1.1 billion barrels to now in excess of 1.4 million barrels. And the biggest single increase came from our Blackrod project, which saw around 300 million barrels of oil added to the 2C resource base in Blackrod. And with the capital program that we have this year in Canada on our Ferguson project, with the Malaysian drilling program that Will is going to take you through and also the French drilling program, we've also got a lot of investment that's going on that can help mature some of that 128 million barrels of 2C resources that sits outside our Blackrod project. And that's a significant inventory of future reserve and resource replacement. Turning to the production guidance for 2022. We announced this morning, our production is expected to be between 46,000 and 48,000 barrels of oil equivalent per day. We're targeting investment in all of our areas in Canada, in Malaysia and in France. And what you can see from the chart on the right-hand side of this slide is that we're forecasting production to return back in excess of pre-COVID levels. And both Chris and Will will go through much more details on the projects that are underpinning that growth in the operations section. Turning to the cash flow generation. You can see that year after year, with the exception of the 2020 pandemic year, IPC has been able to increase our cash flow generation. And I think if you look at the forecast for 2022, you can see that we're lifting the company to new heights. If we assume much more conservative oil prices of $55 per barrel, we're estimating to generate somewhere between $220 million and $230 million of operating cash flow, and at prices of between $70 and $100 per barrel, we're looking at generating between $360 million to $375 million at $70 a barrel up to USD 600 million to USD 635 million at $100 per barrel. So a significant uptick in cash flow generation in this higher commodity price environment that we're experiencing. Turning to the investment program that we've announced today. The focus and the strategy very much remains on free cash flow generation. It's a measured capital investment program that you're going to see, and we plan to invest just under $130 million of capital expenditure. It's targeting growth in all of the key assets in all of our regions. And that program is fully funded, assuming Brent prices below $50 per barrel. Gives us also the opportunity to invest and mature in our organic growth opportunities, and we'll be talking about Blackrod later. And also, of course, the cash flow generation puts the company in a very strong position to continue to be opportunistic with respect to M&A activity. So when we look at the cash flow generation, we take off the investment that were planned for this year, we can see how much free cash flow IPC is projected to generate in 2022. At the low end of the forecast, assuming $55 per barrel Brent pricing, we expect to generate between USD 60 million to USD 65 million, so that's around a 7% free cash flow yield. You can see that's why we can fully fund the investment program at below $50 per barrel. But at higher prices of between $70 and $100 per barrel, we're looking at generating between $210 million and $480 million, which represents a free cash flow yield of between 20% and 45%. If we look at how that free cash flow generation compares to the rest of the industry. This chart shows a benchmark of global integrated E&P companies, and it's been compiled by RBC Capital Markets. And we can see that the average projected free cash flow yields across the sector ranges from a low of 6% up to a high of 20% with an average of 13%, and that's assuming oil prices of $80 per barrel. The equivalent free cash flow yield for IPC is 30%. So well in excess of double the industry average. So IPC extremes -- extreme very attractively relative to the rest of our industry peers. So what do we intend to do with the cash flow that we're generating? We're very pleased this morning to announce a new shareholder distribution framework. What we plan to do, the framework is that provided that our leverage, our net debt-to-EBITDA ratio is below 1x and the average Brent prices are in excess of USD 50 per barrel, we plan to distribute up to 40% of that excess free cash flow above $55 per barrel. And when you look at the guidance that I gave on the previous slides from $55 to $100 per barrel, that means that we're in a position to distribute between $0 million and $166 million of free cash flow. At the high end of that forecast, assuming $100 prices, that's a 17% yield. So that's the short-term 2022 position. If we now turn our thoughts to the longer-term 5-year business plan. We expect this capital program that you can see on the chart on the right-hand side, which amounts to 500 -- sorry, USD 400 million, spread over the next 5 years or $4.65 per BOE on average of sustaining CapEx. That sustaining CapEx program can keep our production flat at 47,000 barrels per day on average over the 5-year period. I think it is worth reiterating that IPC operates almost all of assets 100%. So we have full discretion on the pace of development such that if commodity prices do change, we can adjust that capital program accordingly. So with such low sustaining CapEx with a long-term OpEx forecast of between USD 15 and USD 16 per barrel, company is in a phenomenal position to generate free cash flow well in excess of our industry peers. Feeding into the long-term cash flow story, and we've touched upon this slide in many of our previous presentations, is the supply and egress position in Canada, and that's important because it feeds into Canadian crude price differentials and just under 50% of our production relates to Canadian heavy oil. What we've seen in the last couple of years is a material improvement in the egress system. In the fourth quarter of 2021, Enbridge's Line 3 came into service, and that added an additional 370,000 barrels of oil per day of pipeline export capacity. The second big pipeline project, which is under construction, is the Trans Mountain expansion project that will take Canadian crude to Vancouver to supply West Coast U.S. markets and also Asian markets, and that pipeline has around 600,000 barrels a day of additional pipeline capacity. As at the beginning of this year, that project was already 45% complete. And when you look at the projections on the top right-hand side of this chart, you can see that for the next 5 years, we have excess pipeline capacity relative to Canadian crude supply, which is the yellow line, and we have not been in that position for more than 5 to 6 years. That's extremely constructive for WCS differentials. And what we've taken the opportunity to do is to lock in for this year -- for the remainder of 2022, 60% of our differential exposure has been hedged at an average price of $13 per barrel. If you look at the chart on the bottom right-hand side of this slide, which shows Canadian storage numbers, you've seen that since Enbridge's Line 3 came onstream in the fourth quarter of last year, storage levels have dropped to recent historical lows. So that's also extremely constructive for Canadian price differentials. So turning to what that means in terms of the 5-year business plan outlook. If we first reflect back on the first 5 years of IPC's existence, we've averaged production of just under 36,000 barrels of oil equivalent per day. The average Brent price over that period was just over $60 per barrel. And IPC in our first 5 years generated in excess of $660 million of free cash flow. When we now look ahead over the next 5 years, as I've mentioned, we expect production levels to be in excess or around 47,000 barrels of oil equivalent per day. And what that translates to into our free cash flow generation in a more bearish market where crude prices average $55 per barrel over the next 5 years, we can still generate in excess of $600 million or a 12% per annum free cash flow yield. If we look at a more bullish oil price environment of $95 per barrel, around where we today, you're looking at in excess of $1.8 billion of free cash flow or an annual average free cash flow yield of 36% per annum. To put that free cash flow generation in context, it's good to compare it to IPC's current enterprise value. And if you -- if we take the net debt at the end of last year of $94 million and add that to the current market cap, which is just above $1 billion, that gives an enterprise value for the company of around $1.1 billion. And compare that to the free cash flow forecast over the next 5 years, you're looking at between $900 million and $1.8 billion between $65 and $95 per barrel. So just above $70 per barrel, we can liquidate the entire enterprise value of the company, and we'll still have remaining 2/3 of our 2P reserves, and we'll still have 1.4 billion barrels of contingent resources that are not included in the cash flow numbers. So a very strong story in terms of cash flow generation for IPC. If we now turn and look at the company through the value lens, we also look extremely favorable. Since IP (sic) [ IPC ] was started, we've been very active on the M&A front, and we've conducted 4 acquisitions in the last 4 years, and they've been extremely value accretive for all of our stakeholders. If we look at the slide and the charts on the bottom of the slide, we can see that the first acquisition, our first -- our Suffield acquisition was completed in January of 2018. We paid $420 million for that asset. It's generated through the end of last year, $200 million of free cash flow. And using our independent reserve auditors' price forecast, we're estimating that as it was today, 593 million barrel -- sorry, USD 593 million. So more than $370 million of value added. You can see a similar story for our BlackPearl acquisition, significant value added, more $1.1 billion. Likewise for Granite, in excess of $110 million. And our most recent acquisition in Malaysia, more than USD 48 million. So when you put those 4 acquisitions together, you can see that we've aggregated $1.7 billion in value-add from those for 4 acquisitions. So that's an exceptional track record since the company started. And when we put all those acquisitions together with the organic reserve replacement that we've had since we started, you can see a material uptick in our value -- in our net asset value. When we started back in 2017, we had a net asset value of USD 543 million. Rebecca will go into much more detail in her presentation, but the asset value at the end of last year is in excess of $2.5 billion. When you deduct our net debt, that brings our net asset value down to just over $2.4 billion, and that represents SEK 143 a share. Compared with our share price currently of around SEK 60 per share, that's about a 58% discount to the fair value of IPC's 2P reserves. And it doesn't assume a single new barrel of reserve added. It doesn't assume a single barrel of our contingent resources that's converted into reserves. And I think when you listen to Will and to Chris' presentation, you can see that we've got a track record of consistently adding reserves to the resource base that we currently have. Turning to the contingent resource space. We've made a lot of progress in the last 2 years and starting to unlock the option value that we have in that biggest contingent resource, which is our Blackrod project. As I mentioned in the highlights, we've materially increased our 2C resources on our Blackrod project, up by around 300 million barrels to now just under 1.3 billion barrels. For the first phase of development, previously, we estimated just under 180 million barrels of 2C resources, and that's now been uplifted to just under 220 million barrels of 2C resources. For our Phase 1 development, the latest CapEx estimate is around USD 540 million. And this -- these numbers have been independently verified by Sproule, who are our third-party resource certifier in Canada. You combine this project with the expertise that we have in Canada, where we've operated the pilots on the Blackrod project for more than 7 years. And we've got expertise from our Onion Lake Thermal project on development and operating these types of projects, puts the company in a very strong position to start to crystallize more value from this project. The team has spent significant time and money, and Chris will go into more details in his presentation, but we've got all the approvals in place for an 80,000 barrels a day production facility. The team has done an excellent job in optimizing the Phase 1 development concept for this project. And what we're now looking at is starting with a 20,000 barrels a day facility that will then ramp after a couple of years up to 30,000 barrels per day. And the numbers look very attractive. On an unrisked basis, we're looking at an NPV8 of around USD 860 million for that Phase 1 development. And if you look at the breakeven price, it's around USD 50 per barrel WTI. And if you look at the recent Rystad study, which quantified the breakevens for all of the greenfield projects that you have, including Middle East, including deepwater, including shelf and Canadian oil sands, this is just a couple of dollars per barrel above the average of all of those projects, so screens extremely favorably. What's next for Blackrod? You're going to see we plan to spend around USD 4 million on FEED studies to mature the project through 2022. We're going to continue the pilot. And the positive thing is that actually the cash flow from the pilot at these oil prices will more than fully fund those FEED studies. So very low dollars to start to continue to further crystallize the value of this significant contingent resource base. And my final slide goes hand in hand with the growth that the company has had. This is extremely important to have a very clear ESG strategy. And if we start first with the health and safety performance of the company, it's been exceptional. We didn't have any material incidents at all through 2021. We've retained all the COVID operating protocols that we've had in place, and our teams have done an extraordinary job to have no interruptions as a result of COVID through all of 2020 and all of 2021. If we look at our climate strategy, we've made a commitment to reduce our net emissions intensity by 50% through the end of 2025 from our baseline in 2019 of 40 kilograms per barrel to 20 kilograms per BOE by the end of 2025. And you can see from the chart on the bottom of this slide that we're already well on track with that with respect to our net intensity reductions through 2020. We did publish alongside our second quarter results, our second sustainability report. It's fully GRI compliant. There's a lot of credible projects that are ongoing across all of our organization. I would encourage all of our stakeholders to take a good read and see the excellent work that's been done by all of our teams across all of our units within IPC. So that concludes my part of the presentation. I'll pass across now to William Lundin, who's the Chief Operating Officer. And he'll [ walk through ] 2022 outlook before we get into more details on the assets. So Will, over to you.

Thanks, Mike, and I'm thrilled to be providing some more color on the operational side of the business today. In the upcoming slides, we're going to spend a little bit more time on the resource highlights as well as explain strategically what we set out to achieve through our 2022 guidance. And then Chris and I will get into more detail within each of the operated regions. So the growth story continues for IPC. Notwithstanding 2020, the company has managed to increase its resource position every year since spin-off from Lundin Energy back in 2017. And this has been accomplished through a combination of organic growth and high-quality asset acquisitions. And as Mike touched on, we had material reserve replacement across all operated regions with a collective proved plus probable reserve replacement ratio of greater than 90%. And our contingent resources also grew by nearly 30%. And when you combine the 2P plus 2C volumes together, it represents greater than 2,000% replacement for the group, which is really a testament to the quality of the assets and the technical personnel that exist within the company. And the core strategy within IPC is to deliver operational excellence and to maximize the value of its resource base. And we do this by working with the assets and working with the teams to define the life cycle plans for each asset whereby in the short term, we're looking to optimize existing production and in the long term, we're identifying and maturing contingent resources and undeveloped reserves to ultimately get them developed and put into production in the most effective and efficient way possible. And that's exactly what the teams have delivered through time, whether that's from the international assets that IPC acquired or within the Canadian business as can be seen on the cumulative production and reserves plots on the right-hand side of the slide. And it's also important to note that no reserve replacement is assumed within any of the valuation or cash flow projections shown today, which is a really strong position to be in as a company with greater than 1.4 billion barrels of contingent resources and a motivated team to see those resources matured into reserves. So our 2P year-end 2021 reserves position stands at 270 million barrels of oil equivalent. That's only 2 million barrels less than the prior year's volumes despite producing 16 million barrels of oil equivalent throughout the course of 2021. So the driver of that replacement mainly stems from a combination of good field performance and technical improvements. So with reference to the reconciliation table, in Canada, the bulk of the reserve replacement came from Onion Lake Thermal and Suffield, which collectively contributed around 8 million barrels of oil equivalent. At Onion Lake Thermal, technical work were performed, where the well logs were reinterpreted across the developed area, and that revealed larger oil in place, which led to greater than 4 million barrels of 2P reserve replacement for Onion Lake Thermal. And in Suffield, we had really good performance from the oil and gas side and especially from the end-to-end enhanced oil recovery project. So in aggregate, that added just shy of 4 million barrels of oil equivalent in 2P additions from the Suffield property. The rest of the reserve replacement in Canada came from a pretty even distribution across Ferguson, Mooney and the conventional assets. And in Malaysia, we acquired an incremental 25% working interest, and we also had really good field performance from the wells there, specifically from A20. And in France, we also matured contingent resources into reserves associated with the Dommartin-Lettrée field. And we had great field performance from the VGR field as well. So that added 3 million barrels of 2P reserve additions relating to our international Brent-linked assets. And whether it's 1P, 2P or 3P reserves, 60% of those volumes are within the developed category. And our 2P reserves life index is 16 years, and that's based on our midpoint production guidance. So after 5 years of production, we'll still have greater than 2/3 of our 2P reserves. And within that time frame, we could more than liquidate our enterprise value, as Mike was discussing earlier in this presentation. So our contingent resources are 1.41 billion barrels of oil equivalent. For every barrel of 2P reserves, we're more than 5x covered on contingent resources. And the growth that we saw in the contingent resources over the past year mainly came from Canada at the Blackrod project, where there is comprehensive technical work undertaken. That resulted in an increase in recovery factors for the property as well as extension of the booked volumes to the South. We also had contingent resource additions come into play in Malaysia, where we booked the PSC extension volumes and also identified a couple extra infill wells. And in France, we had a slight reduction in our contingent resources, and that was the result of our Dommartin-Lettrée field development opportunity being matured to reserves, really following through on our organic growth strategy. So in 2021, we had excellent production performance, and that came on the back end of a relatively light investment program. So that really showcases the low decline nature of the assets that we have within the IPC portfolio. And those themes that underpin the strong performance are reflected into our 2022 production guidance of 46,000 to 48,000 barrels of oil equivalent per day. And if we achieve the midpoint guidance, that will be a record-setting production level for IPC, which couldn't come at a better time in this piping hot commodity pricing environment. And the production forecast that we've put out, pardon me -- the production that we've achieved historically has always been within guidance or better than guidance since inception, and we're confident to repeat this going forward based on the diligent forecasting process carried out with operations and our production and reservoir engineers. So the investment plan this year targets production growth across all operated regions. And specifically, the capital activity in Bertam in Malaysia and Ferguson in Canada will contribute to production growth in 2022. And the rest of the investments will have more of an impact going into 2023. And I do want to point out, you can see there's a slight dip in the Q1 production guidance for 2022. And that's really the result of a couple things, which is one, from Canada, where there's cold winters there, which mainly affects some of our Suffield gas production, but that does come back through flush production when weather warms up. And there's also some production downtime associated with the ongoing drilling activity in Malaysia. And our production mix is 2/3 weighted towards oil with about 49% of the crude coming from Canada and 18% coming from the international assets in France and Malaysia. The rest of the production mix is natural gas coming from Suffield. Our operating expenditure guidance per barrel of oil equivalent for 2022 is $15.20, which is largely in line with where the 2021 levels settled at. And so our operating expenditure guidance is representative of all costs from wellhead to sales point, and it does include normal provisions for items such as maintenance and work or whether there's downtime associated with that is taken into consideration. We don't have any major turnarounds scheduled this year across any of the assets, but there are some minor process shutdowns scheduled in Bertam, and that's mainly due to the rig move and some standard inspection work. And Christophe within the financial overview section will showcase the evolution of our operating cost per BOE on a quarterly basis. Strong cost discipline is really core to the business here, and we have a really good understanding and control of the base operating costs, and we have minimal discretionary spend allocated to each of the assets. And if prices were to dip, we know exactly what needs to be done to minimize our variable expenditure, which really keeps us resilient through the volatile pricing periods that this industry can have. So development capital, I'll spend a little bit of time here, and then Chris and I will go into more detail with -- on each of the projects within the country overview sections. Our capital expenditure guidance is $127 million, and that includes decommissioning expenditure. This is a measured investment program targeting production growth across all operated regions. In Canada, we have developments planned in Onion Lake Thermal, which will primarily consist of early works for the next sustaining Pad L as well as drilling of a couple additional infill wells there. In Ferguson, we're very excited to get that development activity underway, which will bring immediate production growth at the back end of this year. There's also infill drilling going on within the Suffield oil property. And big focus for the company is at Blackrod, where we'll look to mature our commercial development concept through a front-end engineering design study. And the spend in France is mainly allocated towards the Villeperdue West development project. And in Malaysia, there's some carryover for the A15 sidetrack drilling and pump upsizing program. So this development capital and budget is fully funded by cash flow generated from the business. And by being operator, the vast majority of the assets that we have, we have the autonomy to modulate some of the investment as needed depending on the commodity and pricing environment. So at this point in time, 50% of the capital could be removed. And alternatively, there's a mature set of projects that we have in inventory that we could decide to add in. And some of those will be shown in the upcoming slide. This is really the opportunity set that exists within IPC, and it's the feedstock for organic growth. Some of those opportunities listed in the future opportunities section are execution ready, and we'll continue working across all operated regions to further define and identify projects across those assets. And it's really how the technical side of our business works, where the corporate and the asset teams are working together to mature these growth opportunities in accordance with our value process policy. And what that does, it really ensures a robust and a predictable outcome. And that business model, it ensures maximum value creation. It also is scalable, and it's something that we use as a tool when we're looking at business development opportunities, whereby if there's an asset or a company of interest, we're looking at the projects contained within that vehicle and see how they rank against our projects contained within the IPC portfolio, and they must be competitive relative to that. So 5-year outlook. We're targeting 47,000 barrels of oil equivalent per day for the next 5 years with a low sustaining capital cost of less than $5 per barrel of oil equivalent. This is just based on our 2P reserve position. And the reason for the low sustaining capital cost is really a result of the majority of our assets having existing infrastructure with excess processing capacity in place. So to mature those undeveloped reserves largely consist of putting more well stock into the ground and tying in to the existing facilities. So that creates really robust opportunities, and it also results in us having a great platform for material free cash flow generation. And so within the 5-year horizon in Canada, the spend is largely geared towards Onion Lake Thermal, which will consist of producer and injector pad development as well as some facility works. There's some ongoing activity in the Suffield gas property as well as oil drilling across Suffield oil, Ferguson and Mooney. And within the international business, we have ongoing developments in Villeperdue West for France as well as the DML development. And then in Malaysia, it only assumes we execute the A15 sidetrack drilling opportunity as well as the ESP upgrade. So there's no further activity beyond that. And that's really what underpins the 47,000 barrels of oil equivalent per day projection. Now because we're operator, as I had mentioned, we have the ability to modulate the investment. And depending on the commodity pricing environment, that is exactly what we'll do because the primary focus for the company is to really generate an optimal amount of free cash flow. With that being said, I will transition to Chris to go through the Canada section. Thank you.

Thank you, Will. Let's take a look at Canada. Canada is 80% of our production, 70% of our operating costs and 65% of our capital spending in 2022. Our assets consist of shallow natural gas, light oil, medium oil and heavy oil. On the map, you can see on the slide, they're located in 3 core assets in Southern Alberta, in mid-Central Western Saskatchewan, which is right on the Alberta-Saskatchewan border, and then again, in Northern Alberta, where we have our Blackrod SAGD development. Let's dive into a few assets here. We'll go with the Onion Lake Thermal first. So Onion Lake Thermal is a world-class thermal heavy oil development. We have 140 million 2P reserves in the development currently. The plots on the bottom left shows the asset has been built in 2 phases. In 2016, we kicked off with Phase 1. And in 2018, Phase 2 was kicked off, with the production approaching our facility capacity of approximately 14,000 barrels a day. In 2021, you can see the development maps on the right-hand side, you can see the drainage patterns associated with our Phase 1 and Phase 2. And in 2021, we added the D' prime pad, you can see the top left of that map. So that pad is online and producing as expected. And we also did an infill program of 5 infill wells that are also online and ramping up as expected currently as well. In 2022, we're going to focus on a sustaining pad, which we call our L pad that you'll see at the top right hand of those development drainage boxes. That pad is a large pad, 9 SAGD well producers, and it will be a sustaining pad. So bring wells on as required to maintain production at our facility capacity of approximately 14,000 barrels a day. Sustainability is also a big focus when it comes to our Onion Lake Thermal project, across all assets. But Onion Lake Thermal project has some ability to capture and really reduce emissions. And we've looked at a waste heat project that we're able to capture some heat out of our disposal water and return that back into the process to preheat some boiler feedwater to create steam, which is overall going to reduce our emissions through our 2022 year. Also a lot of little jewels of opportunities in there. We have a few other infill projects that we're continuing to mature, and we'll drill a couple of those wells throughout '22 as well as part of our capital budget. Again, all sustaining type production to keep it flat for many years. Suffield. So Suffield is a large, profitable, producing asset. It's mature, has great historical production. It has natural gas, and it has medium to heavy oil located on it. The previous operator never gave it the attention. It wasn't noncore -- it was a core -- it was not a core property for the previous operator. When IPC acquired it, started to give it some love and attention, we were able to start working projects through optimization. And you can see in the plot in the top -- in the bottom left that we have replaced 30 million barrels of oil equivalent of production. Let's get specifically into the natural gas asset within Suffield. So the 2 plots on the right-hand side of the slide we'll focus on. So the bottom right is a fairly lengthy in years production plot associated with Suffield natural gas. You can see prior to IPC's acquisition, it was on a decline of 9% or 10%. Once IPC started giving it again that love and attention, you can see the profile has really flattened out. And since then, it's on an average about 4% decline with some of the years, the beginning years being really flat. Why is that -- how is that happening? It was a large well stock there, shallow natural gas when gas is being produced, it brings in a little bit of mud, a little bit of water. You need to continue to work these wells to remove that water and mud from the wellbores to avoid the gas being snuffed out and keep the well gas production online. So you can see since '17, some of that optimization activity being -- gas swabs are one of our largest manufacturing process type of maintenance. You can see we've doubled the amount of activity in the field, which directly impacts the amount of production and gas that we can keep running at that facility. Again, all this is done without drilling a well. This is all done through hard work the team is focusing on optimization and good preventative maintenance. On the left plot, you can see the oil production associated with Suffield -- the Suffield asset. Again, a before and after picture of the asset not getting much attention and then the asset getting some focus. You can see that not only did it offset decline, in fact, it's increased in production since our focus on that asset. And that's done through upsizing artificial lift throughout the existing well stock, debottlenecking facilities throughout the field and also maturing, identifying and drilling certain -- drilling inventory that's there in the pools and infilling in some of our enhanced oil recovery pools, like Will mentioned earlier, like end to end. So very, very impressive results. We're operating today around 8,000 barrels a day, and we have lots of future inventory to maintain that. We'll move ourselves to Ferguson. So Ferguson is our southernmost Southern Alberta assets. It was bought in early '20, just as price was collapsing. So this jewel or gem of an asset is kind of being waiting for -- waiting for us to get after a development. Well, we're ready to get at it now. So we are commencing a drilling program on this asset in the coming months. And we have a 13-well program planned. The following years, there's also a 10- to 15-well program of inventory for the next few years afterwards as well. So you'll see this asset more than double in production in the next year to 1.5 years. Very exciting, very, very clean asset. It's a light oil asset. We don't use condensate to be able to move it to sales market. It has a very low OpEx, very high netback property, a great clean little operation. Very excited to have it in our portfolio. Our conventional and Mooney assets are described here. So we'll start with Mooney. Mooney is our -- is an ASP flood, very similar to some of the enhanced oil ASP floods that we have in Suffield. So there's some synergies that we capture between the 2 properties. This you can see on the map, is one of our Northern Alberta properties. It is only really being developed in what we call Phase 1 of our Mooney property. Phase 2 has not been touched with the enhanced oil recovery techniques that we're using. And we're looking at advancing into Phase 2 in 2022 and more than tripling the production associated with that field. Also the conventional assets, which are more located around, I guess, our flagship -- one of our flagship properties being Onion Lake Thermal. We have the synergies of using infrastructure, our teams and just being active in that area to operate these conventional assets that continue to give us inventory of drilling opportunities and reactivations that should contribute approximately 1,000 barrels a day to our 2022 production guidance. Blackrod. We've heard lots about Blackrod today. I'll dig into it with a little more depth. So Blackrod, a very large SAGD development. It's our largest organic growth opportunity that we have. It is 80,000 barrel a day approved development today. We've been operating a pilot for close to 10 years now. The pilot has had 3 iterations of well pairs, well pair 1, 2 and 3. Lots of learnings have happened from those well pairs. We've -- we drilled them longer. We went from 700 meters all the way to 1,400-meter well lengths now. What does this do? All those learnings allows us to, again, optimize the number of pads we're going to have to drill, the number of wells, roads, pipelines that we need to put in to manage the commercial development, capital cost metrics to ensure we're the top quartile SAGD project. So the well pair 3, you can see the bottom right plot there, is producing at over 800 barrels a day today. We've locked in a commercial design for drilling, for completions, for start-up, for operating to maximize the potential of that wellbore and use it as part of a commercial design. You can see the progression. We both have -- the well pair 2 was also a very successful well pair on that same plot showing the difference in well pair 2 and well pair 3 by taking into account our lessons learned, including well length, including operability, including start-up. All those types of lessons are incorporated in that to make us very confident around our ability to take this commercially and do it successfully. So Blackrod, through the maturation of well pair 3, again, the longer well lengths, the resource assessment work that we've done to really look at recovery factor to understand how the pilot has performed, we've been able to solidify approximately 1.3 billion of 2C resources associated with this asset, an amazing large resource. Phase 1, you can see is approximately 200 million barrels of 2C resource. And that's where we're going to focus our 20,000 barrel a day with an expansion to 30,000 barrels a day development plan in 2022. We'll be doing a -- spending some small, prudent dollars on keeping this asset hot and ready in terms of being part of our portfolio if at some time, we want to move this organic development forward. That's it for Canada. So I'll pass it back to Will, and thanks for your time.

Thank you, Chris. Now I'll spend some time on the international assets before transitioning to Christophe to go through the financial overview. So our lone offshore asset within IPC is in Malaysia, and the asset is located in shallow waters of about 70 meters in moderate depth. The reservoirs contain 37-degree API oil, which we produce through our wellhead platform onto a spread moored FPSO. And you can see this in the image on the slide there. That picture was recently taken and also includes the Gunnlod jack-up rig, which we contracted for our ongoing A15 sidetrack drilling and pump upgrade program. So the strategy for Malaysia is quite straightforward. It's to sustain a high level of operational excellence by maintaining high uptime. It's also to deliver our investment program as per plan and to mature organic growth opportunities so we can really unlock the full value potential of this asset. So the Malaysian business has really been a model of excellency when it comes to running an offshore asset. The teams have managed to achieve close to 100% uptime, excluding planned maintenance and planned outages, since coming onstream every single year. And that great facility performance is complemented by really strong reservoir performance where there's been a significant uplift of recoverable resources over time. And when we look at the production plot on the slide, we now have a 100% working interest within Bertam as of April of last year. And we forecast spot production rates in 2022 to return to near net 2019 production levels, which is really impressive, and this asset continues to exceed expectations with cumulative production and current 2P reserves well in excess of the 3P levels booked at PDO time back in 2012. So with this strong performance and the track record of success as well with us owning the FPSO and associated infrastructure and with there being a material amount of oil to be recovered past the current production sharing contract deadline in 2025, there's really a compelling case to extend the PSC here, and we'll continue to work with the teams on this throughout the course of 2022. Bertam development. So the A15 sidetrack, we are targeting the K10.1 formation within the Northeast region of the field. Drilling is currently underway. We recently landed the production casing, which penetrated the K10.1 reservoir, in line with prognosis. We still have to drill the lateral portion of this well as well as do the completions. So we expect first oil to come sometime by the end of Q1. And the infill programs that have been executed in Bertam have been hugely successful. We've actually produced more to date than the predrill expectations, and there's still plenty more oil production to come from those wells. So following the completion of A15, that same drilling rig will be used to upsize 3 ESPs as well as execute 1 well work over. And you can see on the graphic in light blue where the 3 ESP replacements will take place. It's a very straightforward execution plan here where we're simply retrieving the upper completions and installing a new Schlumberger ESP. So what this does, it doesn't only increase the rate potential, but it's also a form of proactive maintenance. And with the FPSO processing capacity upgrade that was successfully installed last year, that ensures that we can maximize production rates going forward from this field. And the economics for this capital activity are really, really strong. There's around a 1-year payback and a $20 breakeven, and that's based on a $55 Brent price. And with our next cargo lifting, we've secured a $5.50 premium. So this is going to really pay out in a rapid time frame. And our subsurface teams will continue to mature the infill locations that are booked within our contingent resources based on the results of this program. So in France, we have a 100% working interest within the Paris Basin and 50% working interest in non-operatorship within the Aquitaine Basin. And you can see the license packages on the slide there. These assets contain light oil as well of around 36-degree API, and the strategy here is to maintain efficient operations, which the teams have delivered year-on-year. It's also to commence the Villeperdue West development and to continue maturing our organic growth opportunities. So these are really shallow decline assets that we have here. And when you combine that with the recent development and optimization activity, you can see on the production plot, we've completely offset those declines. So majority of our production does come from the Paris Basin. And of our 2P reserves, 85% of them are within the developed and producing category. And what that does, that ensures stable cash flow generation going forward for the foreseeable future. And the teams in France have been there for a significant period of time, and it's really a benefit to have that historical knowledge and expertise, and we'll continue working with the teams to mature our organic growth development opportunities and especially located within our contingent resource volumes. So the most recent development that was undertaken by the company in France was within Vert La Gravelle, and that delivered a hugely successful result. As you can see on the production graph, the VGR113 well is continuing to exceed expectations. This well still has a 99% oil cut after being online for over 2 years. It's something truthfully that we didn't anticipate, but we'll take that any day of the week. We're very happy and pleased with the results thus far. And we're looking to replicate the success that we've had there at another field called Villeperdue. And then within Villeperdue, it's one of the main producing fields that we have within the Paris Basin, there's a lot of development upside. And we're looking to exploit that through a multi horizontal step-out well drilling program. And these formations within Villeperdue are different than those that are contained within Vert La Gravelle. So in Villeperdue, Dogger carbonate reservoir at the Jurassic level. And there's 2 producing intervals known as the R1 and the R2, and we're targeting the R2. And there's reservoir-quality extension towards the West, and there's potentially a very large unswept area there that we're targeting. And this is substantiated through 3D seismic as well as data gathered from existing well control within that field. So these 3 horizontal wells will be drilled from existing well pads, and it will provide greater than 500 barrels of oil per day to the French business. And we're really excited about this light oil opportunity. The drilling team was recently assembled. And upon a success case, there could be a lot more further upside potential within the western flanks of the field. So in summary, we're in a phenomenal position as a company, targeting record production this year with a robust business plan that underpins flat production rates for the next 5 years. This is only based on our 2P reserves with greater than $1.4 billion of contingent resources and a proven track record of reserve replacement. There's a ton of upside to outperform, and it doesn't just stop there. We also -- it's within our DNA to execute value-accretive acquisitions, and we continue to be opportunistic to grow through M&A. So with a strong balance sheet with a war chest of cash and with material cash flow being generated from our operations, we're in a really great spot to grow organically and inorganically, all whilst making shareholder distributions. So with that, it's a perfect time to transition to our CFO, Christophe Nerguararian. Thank you.

Good afternoon, and thank you, Will, for that great presentation on our operations. So moving on to the financial overview and starting before I give you all the netbacks at different oil prices, looking at the assumptions. And actually, that slide took us quite a bit of time. We wanted to show different scenarios, obviously, and the oil price has been very volatile, obviously, increasing a lot over the last few months. So we wanted to first show you a case at $55, just to evidence we are absolutely fully funded at that low level, a base case at $70, which is pretty much in line exactly in line with the actuals in 2021. The high case at $85, which is pretty much where we stand right now because, obviously, the spot price is -- of the Brent is around $19.92, but there's a steep backwardation. And so we're losing $8 approximately on the forward curve between now and the end of the year. So that high case at $85, it's pretty much in line, spot in line with where we could almost hedge the oil price, the Brent oil price for this year, and $100 because there's more and more literature and analysts forecast about a 3-digit oil price. Now in terms of differential. We remain in line with actuals from 2021. So we're using a $3 discount from Brent to WTI and another $13 discount from WTI down to WCS. And that puts us, as I said, pretty much $1 apart from where we were in 2021. That's for the oil. And so we'll show you on a netback basis, the impact of all these cases onto the group's cash flow for 2022 based on the production guidance, which was described before. Now if you move to the gas it seems a random number. But of course, as you know, there's pretty significant seasonality in gas prices everywhere, but especially in Canada and North America. And so we are taking to accounts this seasonality. And so we have the winter quarters, Q1 and Q4 in 2022, at CAD 3.5 per Mcf and $2.75 for the summer months. And then we'll show you the impact of running sensitivities of plus or minus USD 5 per barrel on the WTI/WCS differential and the same for CAD 0.50 per Mcf up or down on gas prices. So the result is that based on our production guidance of 46,000 to 48,000 barrels of oil equivalent per day with a capital program, excluding abandonment cost of $121 million and operating costs pretty much in line, flat from last year at USD 15.2 per BOE. That translates into realized prices. So revenues of -- on a netback basis. So at $45.4 per BOE, which itself translates into $21 to $21.5 per BOE netback for EBITDA and operating cash flow and $12 per BOE of free cash flow for '22. And this is the base case, so using a $70 Brent price. Now looking at how we look at realized prices across our portfolio of assets. So with the $70 Brent, we're anticipating to sell our Malaysian crude at a premium of around $3 above Brent price in 2022. It's more like $2.5, which is conservative, but we've already had booked a sale in March, $5 above the Brent price. In France, we're selling pretty much exactly on parity with the Brent. As I mentioned, with a $3 discount to get to the WTI of $67 in our base case and $54 for WCS, we've made the assumption, which is totally in line with the previous year that would be selling our Suffield oil production at around $1 discount to the WCS, which is the heavy oil benchmark Canadian price and unlike exactly on par with -- on parity with WCS. And that is the result of what we've seen and heard before that we're blending from the next few days or weeks. We're going to blend 100% of Onion Lake production, giving it the exact specs of the WCS. We would be selling on WCS or LLB, which is $0.20 premium over WCS. Looking at the gas. So we realized a gas price of CAD 3.7 per Mcf last year. And even if the market is still very supportive and constructive, we took a slightly more conservative view for 2022 to set our budget. And so we have our Echo, as I was referencing, including that seasonality between the winter and summer days in 2022 of CAD 3.13 per Mcf. And because we're selling at a so-called Empress price, which is literally on the Alberta, Saskatchewan border. Our realized price is around $0.10, $0.11 higher. So we're using $3.24 for the forecast this year. Now in terms of cash margin netback, which really are revenues less operating cost, you can see that in our base case with $45 per BOE of realized price, we would generate a cash margin netback of close to $22. So $1.5, $1.2 better than in 2021. And that is the results despite almost the exact same oil prices slightly below. This is the result of a higher content of oil in our oil and gas product mix. We're going to produce a bit more oil compared -- proportionally compared to '21 and also more. At least the guidance is $1,000 to $3,000 -- 1,000 to 3,000 barrels a day higher in our guidance compared to 2021. In terms of the previous slides, the revenues, those revenues forecast include some of the hedges we have put in place in the beginning of this year. So just to be clear, we have no hedging covenants. I'll come back to that. We don't have any more bank facilities imposing any hedge covenants. We have left all of our French and Malaysian Brent oil-linked production unhedged, fully exposed to current prices, which is obviously great given what the spot prices are. In Canada, we've done 2 things, one on the oil, one on the gas. We've decided to hedge the WTI/WCS differential at $13 per barrel for the March to December period. And so on average, we've hedged 60% of oil -- Canadian oil sales for the remainder of this year. And 13% is actually the exact average we witnessed over the last 3 years in 2019, '20 and '21, but you can see on the graph that differential has been quite volatile. And so we just wanted to provide our business and our investors, shareholders with a clear view that this $13 was going to be flat for at least 60% of our production. And on the gas side, we've hedged some of our gas production, roughly 25% in Q1, 35% in Q2 and Q3. We've left the winter, which is traditionally stronger, unhedged so far, but we reserve the right to do more. And so for Q1, this -- what you can see on this slide is the EcoHedge. But as I mentioned before, we are selling on an Empress basis. So actually, when you combine the 2, we're expecting that this 25% hedge will translate into a CAD 4.6 per Mcf realized price in Q1 and CAD 4 per MCF in Q2 and Q3. Now looking at the -- so that was for the revenues. Just to mention that those were including the hedges in place. Now on the cost side, you can see that because production is going to increase over the year and because we have some OpEx, some specific project of workovers in Malaysia for the Burton field, as Will mentioned before, the costs are a bit higher during Q1 while the production is a bit lower. So you can see this in this graph that our operating cost per barrel are going to reduce over time this year to actually go down to pretty close to USD 14 per BOE. So $1 below the annual guidance and also $1 below our 2021 realized average OpEx per barrel. Now what does it mean in terms of operating cash flow netbacks and EBITDA. Well, in a base case, we would be, again, pretty much in line, slightly better again, thanks to a bit more oil production in our product mix in 2022. So we would be generating an operating cash flow of $21.5 per BOE or $21 for EBITDA netbacks in our base case. And then you can see that when the Brent increases by USD 15 per barrel, the impact on operating cash flow netbacks or EBIT netback is around $8 per barrel. So when oil prices move up or down $15 the impact on operating cash flow netback is around $8. In terms of the profit netback, I think on this slide, I just want to mention that interestingly, we have more depletion and depreciation that we're going to spend on CapEx in dollar terms or in dollar per BOE basis, and that shows how efficient we are in our CapEx spending because we're going to maintain actually increase our production year-on-year, while we spend less than our depreciation. Now in terms of cash spending, you can see that our G&A are essentially flat, under control. It's a bit conservative here, but around $0.7 to $0.8 per BOE. Financial costs, despite the fact that we are deleveraging very fast, because we've issued bonds, which are slightly more costly than the bank facilities we had in place, our financial items are going to be around $2 per BOE. I'll come back to that. The taxes you see here are not the cash taxes. They include deferred tax and I'll come back to that. So base case, net results of $8 per barrel, in line with 2021 despite slightly higher financial costs. But in the -- actually, the actual the current scenario, which is closer to the high case, a net profit of closer to $15 per BOE. Looking at the sensitivities now on our operating cash flow or EBITDA, you can see that because we've hedged 60% of that WTI/WCS differential, even if that differential was to move plus or minus $5 per barrel, the impact on the operating cash flow netback is only $1.3 per BOE. And that's the case in all the -- this is for the base case, but that would be the same in all scenarios. And $1.3 per BOE translates into a USD 22 million plus or minus. So the impact of a $5 move of this differential is quite limited, thanks to the hedging program we've put in place. And same thing here on the gas. Should gas prices move up or down by CAD 0.50 by Mcf, the impact on operating cash flow, EBITDA on a net back basis, would be USD 0.4 per BOE or around USD 7 million. Now this slide will -- is of great interest, obviously, because now we're talking free cash flow. And so you see the cash available for investment and how it translates once we spend the CapEx into the free cash flow. Just one small note, you can see that the CapEx here on a dollar per BOE basis is reducing with higher oil prices, and that is just the result of the fact that as part of the CapEx here, we include our appraisal activity. So essentially the third well pair, which we're testing on Black Road and this well pair generates positive operating cash flow. And so the CapEx reduces when oil prices increases, not the development CapEx, but development CapEx plus our appraisal. So long story short, when the Brent price increased by $15 per barrel, our free cash flow per barrel increases roughly by $8 per BOE. And you see here the result, and we could go in a very high case, up to $27 per BOE of free cash flow. Finally, I touched upon or I gave a hint that our finance costs will be slightly higher in '22 compared to '21. And that's the result of what we've decided to do on our balance sheet. We've issued bonds a few days ago, USD 300 million of unsecured 5-year bonds at 7.25%. And we used those proceeds to fully repay and cancel our 2 previous revolving bank facilities. We had no pressure to do that. We just wanted to take a longer-term view and position, solidify further the balance sheet and be ready to move should we find an exciting M&A opportunities. And just to be complete on our new capital structure, we also have put in place a 2-year revolving credit facility with our main banking Canadian partners of CAD 75 million, which is essentially unused. Thank you very much. And from here, I will leave you in the good hands of Rebecca.

Thank you, Christophe, and welcome to the final section of our presentation today. I'll be going through the assumptions behind our reserves valuation and giving you some split of the assets in terms of value. So for this final section, I'd like to start with some of the assumptions behind our $2.5 billion worth of NPV 8. And really, one of the most important assumptions here is the long-term Brent price forecast. And as you can see, in last year's reserves evaluation, we had our reserves audited price deck, which started at actually $48 in 2021 and then move to what effectively is a $55 long-term oil price. This year, we've seen an increase, which is related to the increase in oil price of over the past year, which has gone to a $70 barrel effective medium-term forecast with $75 a barrel in 2022. And what we've seen with these forecasts is that traditionally, the oil price is running ahead of these forecasts because as you can see, with a spot price of around $90, what we have is about a 30% increase over the $75 a barrel in 2022, and actually, almost 100% increase over what was forecast to be the Brent oil price in 2022 at the beginning of last year. If we now look at what that means for our Canadian price forecast, you can see again a big increase in where the spot price is sitting versus the forecast. We've seen an increase relative to the year-end of 2020 from $38 a barrel at Western Canadian Select in 2022 to $61 a barrel. We've also seen a big increase in our Empress gas price, but only in the short term. So from CAD 3.30 per Mcf, it's moved now to $4.40. This is a short-term movement related to the gas price this year that Christophe has already talked about. And then in the long term, it reverts back to this CAD 3.50 per Mcf. And again, a spot price that sits at around $5.25 at the moment. And then when we move from pricing, which is one aspect of our reserves evaluation, we then add another component, which is our reserves price forecast, which then go into a valuation, which we published at the end of each year as part of our regulations to do with being listed in Canada. So this NPV is extremely important because it encompasses not only our technical profiles at different reserves categories but also what happens at different price decks and how this value has changed over time. So if we look at 2020, first of all, which was around $70 a barrel in this sort of medium-term forecast, so very similar to where we are today, we had a $2.4 billion NPV. We had $300 million of debt at the time, which led to a $2.1 billion net asset value. And then, of course, in 2021, we moved to the extremely penalizing forecast, which was $48 Brent in 2021, moving to a $55 a barrel long term. And the net asset value dropped to $1.3 billion, still with around $300 million worth of debt. If we now look forward and given we've got reserves replacement of 91% this year, which Will has outlined in his presentation, and an increase in price, what we've seen is, first of all, from 2021 to 2022, if we run our new technical profiles at last year's price deck, we still have an increase from $1.3 billion to $1.4 billion net asset value. And that's a combination of these 3 things: it's an increase in our reserves levels as we spoke about previously, it's the quality of our projects and it's the decrease in debt, which came from USD 321 million to USD 95 million. And then we moved from the $55 a barrel long-term oil price to what is the current reserves oil to forecast, which sits at $70 a barrel. And this then moves from USD 1.5 billion to USD 2.5 billion with a $2.4 billion net asset value. If we then look at this, this is a little bit more detail than we usually give, but we really wanted to emphasize the increase in value that we've seen and also what it means at different reserve categories compared to our enterprise value of $1.1 billion. Now Mike has spoken about our enterprise value versus our 2P NPV8, and what we've seen is that we've got a 58% discount to net asset value, which is an extreme discount. But even when we look at reserve categories such as PDP, which is basically if we do no investment programs such that was outlined today by Chris Hogue and Will as part of their presentations, if we just let the assets run down, then we still have an NPV8 PDP of $1.1 billion. And a part of that is to do with the technical strength of our assets. It's also to do with the fact that we have USD 1 billion worth of tax balances in Canada, which we can use against our taxable income there, and it's to do with the fact that with that long-term oil price forecast, we can still retain this value even at a PDP level. Going to a 1P level, we still have $1.7 billion worth of value. And then there's our NPV8 at 2P of $2.5 billion. Of that, 60% is in the developed portion of our portfolio. If we then look at how to split this 2P NPV8 in terms of SEK per share, you can see that compared to our current SEK per share oil price, Onion Lake Thermal is almost SEK 69 per share, so that is actually more than our current oil price. And that represents around 49% of that NPV8 2P value of the SEK 148 per share that we can see on the left-hand side there. Malaysia and France still have a healthy SEK 19 per share worth of value. And then the other Canadian assets combined make up the rest of our portfolio. So I hope this shows you the value of our portfolio. We do have fiscal terms available on our Internet. They've been posted today. They'll show you all of the tax balances and how to calculate in more detail if you want to look at modeling out our assets. And now I'd like to pass on to Mike Nicholson for the conclusion, and then we'll go to questions. Thank you. Mike?

Okay. Rebecca, thank you very much for your presentation. And also thank you to Will and to Chris and also to Christophe for their presentations. I think we've given a huge amount of detail, and I hope you'll all agree that IPC has had a tremendous 2021 but also is well positioned to continue to lift the company to new heights. So just as a recap in the 2022 highlights, we're lifting production forecast this year to 46,000 to 48,000 barrels of oil equivalent per day. We're still maintaining good cost discipline. The OpEx per barrel is still relatively low at just over $15 per BOE. And we've got a balanced CapEx program that you've heard from both Will and Chris that's attacking growth on all of our core assets in Canada, in Malaysia and in France, $127 million program for 2022. And that's still with the strong commodity price environment allows us to generate significant free cash flow. The program is fully funded down to below $50 per barrel. And as you look at commodity prices going from $55 up to $95 per barrel, we're looking at a range in operating cash flow from the low side down to $222 million up to $635 million at the high side of that forecast. And in terms of the free cash flow generation, you're looking at $60 million on the low side and up to $480 million on the high side, and that represents close to 45% to 46% free cash flow yield close to current oil prices. Simply phenomenal. We haven't got, as you've heard in Christophe's presentation, any benchmark hedges in for the Brent or the WTI. We felt it's prudent to lock in 60% of our WCS exposure, and we've been able to do that at good prices of $13 per barrel, which as you've seen from Christophe's presentation, is great by historical standards. And we've also locked in a material proportion of our gas for this year given the strength we've seen in North American natural gas prices, hedging 30% of our production at a very favorable CAD 3.70 per Mcf. The balance sheet starts 2022 in great shape, given the good performance from last year. Net debt is down at $94 million, and if we look at the cash flow generation at the high end of our forecast, where current oil prices stand, we should be net debt-free sometime in the second quarter. And the leverage is also very low at around 0.3x net debt-to-EBITDA. Phenomenal reserve replacement ratio and a low CapEx year in 2021, above 90%, keeping our reserves flat at essentially 270 million barrels of oil equivalent with a 16-year reserve life, so a low decline quality 2P reserve base. Material uplift from the great work that we've seen in Canada by our Blackrod team, adding 300 million barrels of oil and lifting our contingent resource base up to now in excess of 1.4 billion barrels of oil equivalent. And when we take just the 2P reserve book, and as you've heard from Will and from Chris, you've seen year after year, we are able to find more oil and increase the size of the fields that we own and operate. If we assume a static reserve position and not a single dollar value attached to that material contingent resource base using our latest reserve auditors price deck as Rebecca has shown, which is anchored off a $70 long-term oil price from 2024, you see IPC's 2P share value stands today at SEK 143 a share. So we're currently trading at a close to 58% discount to that 2P net asset value with a material upside in the resource base of the company. And finally, well on track with our sustainability strategy, with our commitment to reduce the net emissions intensity by 50% through the end of 2025. So that's the short-term performance. And as we look ahead over the next 5 years, I think IPC has never had such a bright future. We're lifting the long-term 5-year forecast of oil production now up to 47,000 barrels of oil equivalent per day. Between oil prices of $65 per barrel on the low side and $95 per barrel on the high side, we expect to generate aggregate free cash flow over the 5-year period of in excess of $900 million in the low side, which is an 18% free cash flow yield, well above industry averages at higher prices or in the high side environment in the more bullish scenario in excess of $1.8 billion or a 36% per annum annual free cash flow yield. And that really provides an amazing platform to continue to grow the company, to continue to add value for all of our stakeholders, whether that be in the form of returning capital to our shareholders in the form of further M&A. You've seen that in our DNA. You've seen the $1.7 billion of value that we've created in our first 5 years but also the work that the team in Canada have done in maturing our significant contingent resource base. I think the company is in great shape to generate a lot more value in the next 5 years. So that concludes the presentation part. Enough time for us talking. I think we can pass across now, and Rebecca will moderate the Q&A session. So Rebecca, across to you.

Yes. Maybe we start with the questions from the -- yes. Let's see here. Yes.

[Operator Instructions] Our first question comes from the line of James Hosie from Barclays.

Just a couple of questions for me. First, on your shareholder return plans going forward. Should we expecting you to be announcing some forward returns quarterly basis through this year? And then just on the Blackrod project, I just wonder if you could give us the time scale for when you may be looking to commit to that capital expenditure of just over $0.5 billion and the time frame to getting up to the 20,000 to 30,000 barrels a day Phase 1 production.

Yes. James, let me take those questions. So yes, I think what we've said with the capital returns framework for the time being, obviously, we did announce the share repurchase program that commenced back in December of last year. If we assume an average SEK per share repurchase price of between, say, SEK 60 to SEK 80 a share, that's around $65 million to $85 million this year in potential share repurchases. So I think we've got enough time to continue with the plans that we have in place. So it's likely to be later in the year before we announce any additions to the current program that we have in place. And the details in the MD&A, what we said in terms of the potential timing to first oil is in the range of 5 to 6 years. So really, the immediate priorities Chris mentioned in his presentation is spending the small dollars right now. We're moving forward with the FEED studies, which is around $4 million in investment, and that allows us to define much better the costs and the execution schedule and to start to move the project forward to the next stage.

Okay. So of that, the spend uptick first production of $540 million, would that potentially get start getting spent through 2023 and '24? Or does it come later than that?

Yes. I mean the majority would start potentially, James, in 2023, but the majority would be '24 and beyond.

And we have 1 more question from the line of Mark Wilson from Jefferies.

Very clear presentation. I'm just wondering, the 47,000 barrels of oil a day potentially suggest like there may be some upside risk to that. As an example, and maybe to be specific, oil Onion Lake Thermal, we spoke about that producing at 14,000 capacity, but the slide shows at about 12,000 capacity. So could you just speak to the upside potential maybe against those longer-term areas? And for instance, on Onion Lake, is there latent capacity yet to be added?

Yes. It's a very good question, Mark. And the short answer is yes. And it really depends on how much capital we decide to allocate to facility expansion. As Chris set out in his presentation, we've currently got around 14,000 barrels a day of capacity. We've obviously invested in the D-prime ramp-up last year and the 5-well infill program, and Chris highlighted that there's another couple of infill wells to come this year. So that should start to push us up towards that 14,000 barrels a day facility capacity. We're obviously going to be starting with the investment on the next sustaining path, which is L. We won't see much production from that this year. But again, as we move into 2023, that should be -- give us the flexibility to stay much closer towards that 14,000 barrels a day capacity limit. And then it's a decision on do we allocate more capital and to expand the facilities further. And of course, we've got the potential to add up to another 2,000 to 3,000 barrels a day of facility capacity. And that's currently baked into our long-term reserve forecast. So the short answer is there is room to look to expand Onion Thermal by another 2,000 to 3,000 barrels a day within the 5-year window that we're talking about.

Okay. That's very clear. And then two, how do you balance the view of further M&A versus the investment into Blackrod? Should the fleet program be successful in giving you a commercial path there?

I mean I think the short answer, Mark, is we can do both. If you look at the cash flow numbers, I mean, between $75 and $95 Brent, we're going to be generating $1.3 billion to $1.8 billion in free cash flow. And with the bond issue, we've got $200 million sitting on the books right now. So you're looking at $1.4 billion to $2 billion of cash available to the company. So we're certainly able to look to continue to add value accretive acquisitions through M&A and should we choose to do so and move forward with Blackrod. But for the time being, the focus is very much the small dollars to continue to mature the Blackrod contingent resource space. But as you've seen from the numbers today starting to crystallize some of that option value.

[Operator Instructions] And there seems to be no further questions, I'll hand it back to the speakers.

Thanks, operator. We do have a few questions on the web here, so I'll just direct these through. Perhaps, Mike, you could take this first one. Are there any specific reasons why IPC production couldn't grow at a faster pace? So technical labor force limitations, infrastructure. Could you give an estimate of maximum production capacity?

It's a very interesting question. I mean if you go back pre-COVID, back to 2019, our long-term business plan, we were looking at actually been able to sustain production up towards 50,000 barrels per day. So if we decided that we really wanted to ramp up our capital program and deploy more rigs into the field, we can with the flexibility that we have in the discretion as we operate all of our assets 100%. We could ramp production up faster. But what we've seen as we've looked to stress test the portfolio, a more measured approach where you're spreading your investments over a longer period of time actually allows you to do 2 positive things. One is you generate just as much free cash flow within the 5-year window. And the second thing is you lower your free cash flow breakeven. And I think if there's been any lesson learned through the last down cycle, the kind of unchecked growth in spend in every single dollar of free cash flow I just don't think flies any longer for investors, and we've taken a lot of time to listen to our shareholders. So it's really a much more measured approach that allows us to still achieve and maximize the free cash flow generation while still adding value for our shareholders.

Okay. Thanks, Mike. And then perhaps just a follow-on question for you here, Mike. Could you please explain the higher CO2 emissions cost burden starting in 2025? And how much will this account for in a full year?

On CO2 emissions. Yes, so if we look at the average CO2 cost, which is underpinned in all of our 2P NAV valuations, in Canada, the CO2 tax starts at a baseline of $50 per ton and increases to $170 per ton through 2030. And what that translates through into in terms of a weighted average dollar per BOE at $50 per ton, it's around CAD 0.30 per barrel, rising to around $1.30 per barrel by 2030 or in U.S. dollar terms at its maximum around $1 per BOE across our entire Canadian business.

Okay. Thank you, Mike. Christophe, perhaps you can take this one. We're starting to see inflationary pressures all over natural gas basic materials and possibly wages. Do you have any estimate on how higher natural gas prices would impact overall OpEx?

Yes. Well, I cannot give you an exact dollar amount of increase in the gas price and how much that would translate into an increased OpEx per barrel. Now what I can say is that if you look back when you -- over the period 2018, 2020, our OpEx per barrel were closer to between $12 and $13. And now we are guiding that we're going to be between $15 and $16. And so that takes into account already this revised guidance for the next 5 years on OpEx per BOE, takes into account higher gas prices and the higher cost of energy altogether. Now this being said, what may look like a negative is actually a positive for IPC because we're producing more gas than we're consuming gas for operations or even consuming energy. So net-net, increased gas prices are positive to our business and will increase netbacks. We're roughly producing 100 million squares a day and consuming 30 million, so still 70 million squares a day net.

Okay. Thank you very much, Christophe. Mike, perhaps you could take this one, got a question on what the IRR is for Phase 1 on Blackrod. And also, are we looking for a partner in the asset? And is the bond issuance intended to fund Phase 1 development?

Yes. So the short -- bond issue is not intended to fund Phase 1 development of Blackrod. I think there's still a lot more work to do, and we're using the FEED studies to pin down the cost estimates through 2022. We haven't disclosed the IRR for the project at this stage. And the last part of the question, sorry, around was?

Are we intending to take a partner?

A partner. Yes, I mean I think it's always -- we operate all of our assets 100%, but those are assets that are in production. So I think we're in the fortunate position that should the market conditions prevail, we can still go to the market and test if there's appetite to farm the project down. And if we like the valuation that we see, we can always bring a partner in, but we're not obliged to do so. So I think we certainly wouldn't rule out bringing a partner in. We're seeing the positive development on the egress position and tight differentials. We've seen the breakeven for the project come down on the back of the successful results of well pair 3, as Chris has alluded to, and we're seeing much stronger benchmark prices. So I think all the market conditions are starting to turn in our favor, and I think it would make sense to test the market, but we don't necessarily have to take a partner.

Okay. Thanks, Mike. Christophe, perhaps this is one for you as well. There's still an enormous gap between the current share price and NAV per share expressed in a free cash flow yield. Statistically, this is more attractive from the valuation standpoint than IPC's peers. If this gap persists, would management consider a tender offer to cancel bigger blocks of shares on top of the normal course issuer bid program?

I can't agree more with the statement at the beginning, and we're trying to explain all the reasons why we justify this gap. And so hopefully, the market will naturally comment and help us bridge that gap. I think it's a matter of delivering quarter-after-quarter what we are showing today. I think this morning, we posted very good quarterly results, which are the proof that our ability to generate that free cash flow is there. We've announced this afternoon our capital allocation plan to frame the distribution we want to put in place from this year back to shareholders. Now we already have this NCIB program in place. We've executed roughly 20% of it. So still quite a long way to go. Now I can't say in the longer term. At this stage, we have no intention to do such a drastic move, but we need to wait and see how the market reacts from where we are. We are very well progressed in terms of production, in terms of investments. The costs are under control. So we're in good place to deliver the cash flows that we've shown, especially in our high case, we're on $85. Let's see how the share price bridge that gap before we take a drastic measure.

And maybe just one follow-up. From Christophe's point, we have done both in our history. So we did do a tender offer back in 2017 and 2019. And as Christophe says, last year's program have been under the normal course issuer bid rule. So I think all of those tools remain in place.

Okay. Thanks, Christophe, Mike. Chris, do you have any estimate on how higher basic materials that we have today, the cost of higher basic materials, could impact Blackrod CapEx and OpEx, and so the overall economics of the project?

Great question. As the industry heats up, that is always a concern and something we need to monitor and watch. At this point, we factored in just some normal escalation that we need to deal with, but it is not a -- it will not be an addition to where we land at the end of a FEED study. So we'll take into account how markets are doing for those basic type of materials or supply. So always watching that, and it comes into the front-end engineering study.

Okay. Thank you very much, Chris. Will, should we consider it proactive in the Malaysia offshore market? Are we looking to grow inorganically in Southeast Asia?

Yes. Absolutely. We're looking to grow everywhere, whether it be in Malaysia or in Canada or any opportunity globally, even in France, we have an opportunistic approach to looking at growing the business inorganically. And if we're able to do that, where we have expertise and team in place and good relationships with the regulators and everything already established, that's something really that we can anchor off. However, any acquisition that we're going to be -- going to execute really has to be accretive to the portfolio, and that's the #1 factor that comes into account when looking at opportunities within M&A.

Thanks very much, Will. Mike, just a more general question on M&A in terms of geographic location. Do you have anything to add on geographic location given the bonds on the book?

Yes. I mean I think if you look at what we've done in the first 5 years, we've always preferred the jurisdictions that are low risk that the commercial banks will follow, and we'll be prepared to lend and provide acquisition financing. But I think if you look at the, as Will kind of alluded to in his previous answer, the success of the Lundin family and any of the group companies that are listed is it more starts with the quality of the asset. So we always tend to cast a wide geographical net. It makes sense for us, obviously, to focus on further acquisitions in the area where we have the expertise and the teams on the ground. But if we can find the right opportunity and we can do so without too much dilution, then we do obviously consider new potential jurisdictions.

Thanks, Mike. And we have a couple of questions in -- with this theme. So what kind of deal is it possible to make in a world with Brent over $90 and Western Canadian Select close to $70 -- close to $80 with companies generating a lot of cash and deleveraging? Where can you find a better deal than buying back your shares?

Yes. That's the $100 Brent question. So I think, obviously, people are not assuming $70, $80, $90 a barrel in their long-term economics. And there is still some quite steep backwardation. And I think our experience of dealing with the majors is people are prepared to look at lower long-term oil price assumptions, which I think is different in previous cycles. There's no question that there's -- the banks are being more conservative in their lending practices. So I think if you like, that wall of capital that's available to fund acquisitions is actually a good thing because it's going to at least keep a lid on the amount of capital that's available for upfront considerations. I think people are just going to have to be more creative and look at certainly in the early part of the life of an asset is to share some of the upside through continuing oil price payments so that if you're above that longer-term price, then there's a share of mechanism between the seller and the buyer to allow the -- to reduce the spread between the bid and the ask.

Okay. Thanks very much, Mike. Will, perhaps you could take this one. Apart from Bertam, where are the sort of next couple of assets where you have to invest more to maintain current production rates? So the lease remaining inventory of new potential wells.

That's a good question. And I would say it's pretty even distribution across all our assets base with respect to having to invest some dollars to get the production to increase. Decline rates are really low across all the assets that we have. So I think it's something that it's hard to comment on exactly because it's pretty unequal distribution across the assets that we have in terms of maintaining those production levels where they're at.

Thanks, Will. Christophe, how does gas-related cash flow fit into your framework to return 40% of cash flow above $55 Brent? I think that's a proportion of gas-related cash flow.

Yes. Well, I guess we're producing roughly -- 1/3 of our production is roughly coming from the gas, and the 1/6 of our revenues are coming from gas. So yes, the cash flow is anywhere between those -- that third and the sixth. We don't give too many details on cash flows. But I must confess, in the first place, we didn't go after Suffield acquisition for the gas part, and it's proven extremely lucrative. And while we were using a $2.5, $3 gas price when we were considering that acquisition, it's obviously, much more -- much higher the gas prices today, and so will considerably help into the cash flow mix. Now in terms of the -- still the bulk of the cash flow is coming from the oil production. So we've set that condition at above $55. I think the comparable $55 is probably around CAD 3 per Mcf now. So above that, that will contribute to returning cash to shareholders.

Okay. Thanks very much, Christophe. Mike, just another short question. There's been a lot of rumors lately about a merger with Africa Oil. How do you see their assets. Can you comment ?

Yes. I can comment. There are no discussions ongoing with Africa Oil at this point in time.

Okay. Short question. And then I think the last question here. Another question on how much production realistically would make sense in terms of acquisitions, Mike? And what kind of free cash flow in comparison to your current assets would be enough to get you to pull to trigger?

I think it's too tricky to put a production target because all barrels, of course, aren't created equally. I mean, if you -- obviously, if you look in scenario, we have a higher marginal tax rate around 78% relative to some of the jurisdictions that we're in, in Canada, where we're in the mid-20s, around 30% in France. We focus more on the value proposition and the cash flow generation potential of the targets. So it's always dangerous to give yourself specific production targets. I think as both Will and I have alluded to, it always starts with what's the quality of the asset in the subsurface, the expertise that our team can bring, how can we unlock the value, and is that going to be material and accretive to our shareholders. That's the grounding principle, and that's the one that served not only IPC, but all the other companies within the lending group in creating huge amounts of value for all our shareholders.

Okay. Thanks very much, Mike. I think most of the other questions have been answered through the discussions that we've just had. So that will finish up with the web questions, and I don't believe there's any more from the telephone, so...

Okay. Well, thank you first to my colleagues to Rebecca, to Chris, Christophe and to Will for their presentations. Thank you much. Thank you very much to all of you for tuning in this afternoon. I hope you agree that the company has delivered some phenomenal results last year. I think this year is going to be even better, and the 5 years and further beyond is an incredible platform to generate a lot more value in the next 5 years. So thank you for your support, and we look forward to presenting the Q1 results. Thank you.

Thanks, everyone.