International Petroleum Corporation (IPCO) Earnings Call Transcript & Summary

Okay. So a very good afternoon to everybody, and a warm welcome to all of our guests, our analysts and investors here in the room in Stockholm today. It's wonderful to be back actually physically doing our Capital Markets Day 2023 presentation. Certainly, 2 years since we've been able to do this together. And also a warm welcome to all of the people that are tuned in via the webcast. My name is Mike Nicholson, and I'm the CEO. And we've got quite a detailed agenda for you this afternoon. I'm going to begin by giving an introduction and an overview of the strategy of the company. And then I'll pass across to William Lundin, who is the Chief Operating Officer. And Will and Chris will walk through the asset overview in Canada, and in Malaysia and in France. And then we'll pass across to Christophe Nerguararian, who is the CFO, and he'll walk through the financial numbers and the forecast and the guidance for 2023. He'll pass then to Rebecca Gordon, who is our Vice President of Investor Relations and Corporate Planning. And Rebecca will talk about the latest reserves valuation that we've just finished off. And then we'll finish with some concluding remarks from myself. And then, of course, we'll open up and take questions from those here in the conference room today, and you can also send your questions in via the web. So to get started, and really the focus of this afternoon's presentation is going to be on the forward-looking guidance of the company, but I just wanted to take a couple of more minutes to reflect on the highlights from 2022. It was really the best-ever year for IPC in terms of across all the metrics, production and cash flow generation and balance sheet strength. And if we look at the investment year, we spent about $163 million of CapEx, grown production across all of our assets in Malaysia, in France and in Canada. That allowed us to lift our production to record highs. We actually touched 50,000 barrels of oil equivalent per day during the third quarter, and our full year production numbers were 48,600 barrels of oil equivalent per day, and that was 600 barrels a day in excess of our high-end guidance that we gave this time last year. On the cost side, good delivery. Our guidance was $16 to $17 per barrel. So the OpEx was bang in the middle of that guidance. And a combination of very strong commodity prices and record high production meant that we generated by a long margin and the best of our cash flow performance of the company in our 6 years. Operating cash flow in excess of $623 million and free cash flow of $430 million. And based upon the market cap of the company at the end of January, that's close to 30% free cash flow yield. So extremely favorable if you benchmark that against our other upstream oil and gas peers. That very strong operational performance and cash flow generation, of course, went into the balance sheet has been transformed. We've gone from a net debt position of just over $90 million, now it's a net cash position at the end of the year of $175 million. And then when we add in additional cash that we did from the bond issue at the beginning of last year, it means that we're sitting on a gross cash war chest of just under $0.5 billion. On the reserve side, it's been an incredible increase in reserves. I'm going to touch upon that on the next slide, 13x production replacement and an 80% increase in our reserves to just under 0.5 billion barrels of 2P reserves. And you're going to see we're going to continue our focus on our sustainability efforts. We're expanding our climate targets that I'll touch upon in a couple of slides. So to get started on the main part of the presentation. If we look at IPC's reserves growth has really been phenomenal since we started the company just under 6 years ago. And actually, if we cast our minds back to that period, we're producing only about 10,000 barrels a day, and we had 29 million barrels of 2P reserves. And based upon that reserves, we had an 8-year reserve life. So we could have produced all of those reserves in 8 years. And if you look at the light blue bar at the bottom of this chart, 83 million barrels produced in 6 years and we've produced almost 3x that original reserve base. So it gives you a sense of how quickly we have grown. The big news, obviously, the massive increase in reserves these last years has been largely driven by acquisition and M&A. But what you can see in this -- just this year-end, we've significantly increased our reserves up by 80% to now 487 million barrels of oil equivalent, and that's been on the back of the sanction of our Phase 1 Blackrod project as well as adding 60 million barrels from our Cor4 acquisition. I think the feature about IPC's reserve base is a very low decline reserve base, and you're going to see that when we show the long-term production forecasts. And we've massively extended the longevity of our reserve life, and it's gone from 8 years when we started 6 years ago to now 27 years at current production levels, with the inclusion of our Blackrod project. And if all we do is develop that 2P reserve base. So we don't do any additional M&A. We don't mature another single barrel of contingent resources into our reserves. Over the next 5 years, from 2023 to 2027, we can actually keep our production very stable just in excess of 50,000 barrels of oil equivalent per day. And post the funding of our Blackrod Phase I development, we're able to generate at $75 per barrel Brent in excess of USD 700 million. And at $95 per barrel Brent, we're able to generate in excess of $1.4 billion. And that's an average annual free cash flow yield of between 10% and 19% per annum. So quite extraordinary when you take into account the funding of our Phase 1 Blackrod development. So what do we plan to do with all of that cash flow? In IPC, we have 3 main strategic pillars. And the first is stakeholder returns, and we're in a net cash position. So there's no opportunity to pay back any debt. And what we've been focused on so far is share buybacks, and I'll come back to the reason as to why we prefer share buybacks. If you look at this next slide, you can see that there is a long history of shareholder return since we started the company. The only dilutive event that we've had was when we combined with BlackPearl Resources back in late 2018, and we issued just under 76 million shares. But since then, we've had -- we're now in our fifth shareholder return with the NCIB that we approved in December of last year. We've bought back in aggregate a total of 53.3 million shares. The average price of that share buyback program over the last 5 years has been $0.58 per share. And if we take the share price from the end of January of SEK 112.5 a share, that's added in excess of $280 million in value to our shareholders. So a total of just 20% dilution. And if you look at what we've been able to deliver with just that net 20% dilution, we've seen a fivefold increase in production. We've seen a 16-fold increase in 2P reserves. We've added 19 years to our reserves life, added in excess of 1 billion barrels of contingent resources, quadrupled our cash flow generation. And you'll see that we've added between $3 billion to $3.7 billion to our net asset value with just that 20% dilution. So what do we plan to do this year? Our capital allocation framework that we announced 12 months ago was that as long as the company's balance sheet is in good shape, and we define that as our net debt to EBITDA is below 1x, then we're returning 40% of all free cash flow to shareholders. And if we look at the cash flow guidance that we've given, and assets are still generating significant free cash flow. If you look at the $70 per barrel forecast, we're generating in excess of $140 million of free cash flow. At $85, the assets will generate in excess of $270 million of free cash flow. And at a $100 per barrel close to last year's price, we're just under $400 million of free cash flow. Big decision, obviously, to move forward with our Blackrod project, which we're very excited about. $287 million of CapEx is forecast this year to commence the development. And when we look at the free cash flow after Blackrod development, we're looking at approximately breakeven at $85 per barrel. And we have in excess of $100 million of free cash flow at last year's oil prices around $100 per barrel. So if we took our capital allocation framework strictly, we would be looking at really only distributing above $85 per barrel. But as I mentioned in the summary, the financial position of IPC is as good as it's ever been. And post the acquisition of Cor4 that we announced, we're sitting on gross cash resources of $425 million. So we intend to use that balance sheet and that financial strength to return at least the 7% buyback under our NCIB through 2023. If we look at the market cap of IPC relative to the 5-year and the 10-year cash flow that we're going to go through in more detail in this presentation, IPC's market cap is just under $1.5 billion. And if we look at setting the free cash flow generation over the next 5 years into context, we can essentially buy back between 50% and 100% of our shares outstanding over the next 5 years and fully fund our Blackrod project and repay the $300 million bond. So quite significant in terms of the financial strength. If we look at the step change in cash flow generation, once we've got Blackrod on production and on plateau production, over the next 10 years, you can see it's between $2.6 billion and $4.4 billion of free cash flow. So we can effectively liquidate the enterprise value 2 to 3x over the 10-year period, and we're still going to have material reserves and production and beyond that time frame. The second pillar of our capital allocation is M&A. We've concluded now with the announcement yesterday, 5 transactions since the company has started. If we look at this next slide, we show the 4 most recent transactions. The first was our Suffield oil acquisition. What we're showing on the left-hand side of this chart is the acquisition price, The light blue bar in the middle is the free cash flow that we've generated from those assets. And then the dark blue bar on the right-hand side is the current value on the 1st of January of this year as assigned by our independent reserves auditor. And you can see that across the 4 acquisitions in total $2.8 billion in value has been added from those 4 acquisitions. And with a total consideration of $875 million and free cash flow generation of $635 million, we're not very far away from paying back all of those 4 transactions in aggregate. And we look forward to updating this chart in 12 months from now to show the impact of the Cor4 acquisition, which I don't think you're going to be disappointed with. Let me turn now to the third pillar of our strategic capital allocation, it's organic growth and investing in our massive contingent resource base. Even moving the Blackrod 2C resources into 2P reserves, we still have in excess of 1.2 billion barrels of contingent resources. If we look at the development over time, I think it's been one of the most impressive stories within IPC when we started life just 6 years ago. We didn't have a single barrel of contingent resources. We had a big jump in 2018 when we concluded the acquisition of BlackPearl Resources. Blackrod back then had 744 million barrels of contingent resources. A year later, after we integrated the company, we did a deal with MEG Energy and we acquired an adjacent land position to our Blackrod lands for $3 million. It added 244 million barrels of discovered contingent resources. So that lifted the Blackrod numbers to close to 1 billion barrels. And then 12 months ago, we went through third-party certification. We integrated all of our latest technical data and our latest pilot data from wellpair 3 and we saw a big jump in our contingent resources on our Blackrod project to 1.3 billion barrels. And having taken the decision now to sanction the Phase I development of Blackrod, we see our 1.4 billion barrels reduce to now 1.2 billion barrels as 200 million barrels has matured into 2P reserves. And I think the last bullet on the slide should not be underestimated. Certain of this last 1 to 2 years, I think energy security and access to resource has come into the free, and that's certainly something that differentiates IPC. Our undeveloped resources sit in Canada, which is the second largest resource holder behind Saudi Arabia and behind Venezuela, and we're certainly not welcome in those locations. And it's a very stable fiscal regime. It's a very stable political regime. It's a very favorable fiscal regime for oil and gas investment. And I think the value of this resource base is materially underestimated, and very happy to start to mature that now with the announcement this morning of our Phase I development. And how is this project sanction going to change the company as we look forward over the next 5 to 10 years? And I think on this slide, what we're showing is the impact on our production. As I mentioned, we -- our 5-year average production guidance is around just over 50,000 barrels of oil equivalent per day. And we expect Blackrod to come into production late in 2026. And once we ramp up, Blackrod is 30,000 barrels a day of capacity much more quickly than we originally anticipated, and Chris will talk about that in his presentation. We're pushing up towards 70,000 barrels a day in the early years. And then with a steady decline, we can still sustain average production in excess of 65,000 barrels a day over the next 5 years. And of course, this just includes the Phase I development of Blackrod, and we still got 1 billion barrels of undeveloped contingent resources. So clearly, there's scope for further phases and to extend that production much higher than these levels that we're currently showing here today. So some highlights on the valuation of our Blackrod Phase 1. As I mentioned, the full field total resources were 1.3 billion barrels. We've matured 218 million barrels into our Phase 1 development. The capital expenditure in nominal terms to first oil is now $850 million. That is an increase from last year's estimate of $540 million. We have seen some inflationary increases, but the biggest single component attached to the increases is some scope changes and some acceleration to ramp to 30,000 barrels a day much more quickly. And Chris will give a lot more details of that in his presentation. And we've also prudently added a large chunk of contingency to make sure that we're able to deliver the project within budget. And again, Chris will go through that in more detail in his presentation. We've been piloting Blackrod now for in excess of 10 years. So we've got a huge amount of subsurface data. And we've got the team on the ground, and Chris will talk about his experience. But with Onion Lake Thermal, we've got the experience of having developed these types of facilities in the past. We've got the regulatory approval for a full 80,000 barrels a day project. And through FEED studies and looking at the optimization and how we can maximize value, we've decided to move forward with a much faster ramp to 30,000 barrels a day as part of our Phase 1 development as opposed to the previous concept, 12 months ago, that initially saw us ramping to 20,000 barrels per day. And in a number of years later, ramping to 30,000 barrels per day, and that adds much more value to the project. In terms of the profitability and the value proposition for shareholders, and when we look at the overall net present value using our third-party reserve auditors price deck and Rebecca will talk about that later in her presentation. It's essentially an $80 per barrel long-term real oil price forecast. On an NPV10 basis, we're in excess of $800 million of value added. And if we're using a net present Value 8, that's in excess of USD 1.1 billion. And when we look at the breakeven of the project for Phase 1, it sits between USD 57 and USD 59 per barrel WTI. So still a very robust project. And I think we feel very comfortable now with the extra additions that we've put into our cost estimate that Chris will talk about later to be able to deliver these numbers. So when we put that all together now, and we take the base 2P business and the value additions from our Blackrod Phase 1 project, you can see the transformation and huge value creation since the company started 6 years ago. Back then, our net present value or net asset value using an 8% discount rate was just in excess of $540 million. With the addition of Blackrod and the net cash position, $130 million of net cash that we have following the acquisition of Cor4 means the company 2P net asset value, not a single dollar value to our $1.2 billion of contingent resources is USD 4.2 billion or SEK 320 per share. If we've obviously seen interest rates increasing, if we move the discount rate to 10%, we see a $3.5 billion NAV or SEK 270 a share valuation. Again, with no future value associated with the 1.2 billion barrels of contingent resources that we have. And again, to put that into context with our current company's market value of around USD 1.4 billion, that's a 60% to 65% discount to our 2P net asset value. So that's the company through the value lens. And if we turn now and look at the cash flow lens, I think you can see what a material transformation the base business plus Blackrod Phase 1 can deliver for IPC. The first 5 years, as I mentioned, in excess of 50,000 barrels a day will generate between $700 million and $1.4 billion of free cash flow or a yield of between 10% to 19%. By the end of that 5-year period, at the current market cap, as I mentioned, we could buy back either 50% to 100% of all of our stock. We will still have 80% of our 2P reserves remaining, and we're able to lift that long-term production forecast by 30% to in excess of 65,000 barrels per day for the next 5 years. And the true transformation in terms of cash flow generation that you can see in the next 5 years shows that we can generate close to $2 billion at a $75 per barrel Brent price or in excess of USD 3 billion at a $95 per barrel oil price, and that translates into an average annual free cash flow yield of between 26% to 41% per annum. So quite phenomenal numbers. And at the end of that 5-year period, you'll see from Rebecca's presentation that we'll still have 50% of our 490 million barrels of reserves remaining after that period. And we'll still have 1.2 billion barrels of contingent resources. So quite phenomenal cash flow numbers. And I think this next slide really kind of taps into, if you like, the lending history of how you can create value by acquiring resources, by finding resources and developing contingent resources and then moving them into reserves and into production and into cash flow and monetizing value. And what this slide shows is if all we do is, as a management team over the next 5 years, as we develop Blackrod, we don't do any more M&A. We don't mature a single barrel of contingent resources into reserves. And we take the surplus free cash flow over the next 5 years between $700 million and $1.4 billion and just fund share buybacks. And under the $75 per barrel case on the left-hand side, we assume a share repurchase price of SEK 115 a share. And under the $95 per barrel price, we assume the stock price is more than double today's levels is SEK 215 a share. If you just walk that valuation forward and you have the CapEx behind you and you reduced the share count, our SEK 270 per share net asset value will grow double in the $75 per barrel level. And we'll grow more than 3x in the $95 per barrel level. And it's a very similar situation that we had in Lundin Petroleum when we were developing and sanctioning Edvard grieg and then Johan Sverdrup. Once you get through those projects and get them into production, you see transformational increases in the value of those assets and in the company and in the share price. And I think even if we trade at a discount to those types of values in the years ahead, I think we're set for some very significant increases in the IPC share price in the years ahead. My final slide on sustainability. In ESG, it's been a very important test of a very clear ESG strategy that goes hand in hand with the company's growth plans. I'm very pleased that last year, through 2022, and we didn't have any material safety incidents or environmental incidents. Back in 2019, we set in place the commitment on our climate strategy to reduce the company's net emissions intensity by 50% over 5 years through the end of 2025. And just yesterday, during our Board meeting, we sanctioned the extension of that commitment now to 2027. So we expect to remain at 20 kilograms per BOE of CO2 now through the end of 2027. So I think that concludes the introductory part of the presentation. I'll pass across now to William Lundin to go through the asset overview in more detail. So Will, over to you.

Thank you, Mike. It's absolute pleasure to be here today presenting our short- and long-term business plans. As per the traditional format, I'm going to spend some time on our resource maturation strategy and talk about our corporate guidance. Then Chris and I will go into more detail on the work programs that we've set out in each of the countries of operations. So before I get into the meat of the presentation here, I'd like to personally commend all the IPC internal teams with a tremendous work done throughout the course of 2022. It's an absolutely incredible result, and it allowed us to shape our business the way that we have done so today. So drawing your eyes to the waterfall chart. You can see we had very strong reserve replacement achieved approximately 220 million barrels of oil equivalent. We're matured out of our year-end 2021 contingent resource position into reserves. That was further supplemented by 16 million barrels of 2P reserve additions from the acquisition of Cor4 Resources, which settles out at a 2P year-end 2022 reserve position just shy of 0.5 billion barrels of oil equivalent. That represents a reserve's replacement ratio of greater than 1,300%, a remarkable achievement and consistent with our core strategy of maximizing our resource base through organic growth and through M&A. And it's important to note that not a single dollar, as Mike had mentioned, aside to any of the contingent resource volumes that we have left over. And no reserve replacement is assumed in any of the free cash flow projections, or the valuation materials that are shown today, which will be further explained by Rebecca in her upcoming section. So as Mike stated, our 2P Reserves Life Index stands at 27 years. That's based on our midpoint guidance of 49,000 barrels of oil equivalent per day. So that means that we can maintain that production level for 27 years, and that is approximately 70% higher than our ROI number last year and greater than 3x the reserve life index back in 2017 when the company was formed. So drawing your eyes to the reconciliation table. At year-end 2021, our 2P reserves stood at 270 million barrels of oil equivalent. We produced 17 million barrels throughout the course of 2022. And with the inclusion of the Blackrod Phase 1 volumes coming into our 2P reserve book, that adds 218 million barrels. And you'll notice that's a slight difference from the 2C applied volumes to our Blackrod Phase 1 volumes, which was 217. So there's a slight increase, which is the result of technical improvements. There were some other minor adjustments across the other portfolio, which was offset by additional reserves being matured at our Malaysian assets as a result of the PSC extension. So when you include Cor4 into the final year-end 2P number, the exact quantity is 487 million barrels of oil equivalent, with an 86% weighting to crude and 14% weighting to natural gas. So contingent resources, this is the feedstock to our organic growth. And in the other Canada section, you'll see there is a bit of an adjustment there, and that's largely due to some land package expiries near the Onion Lake property. And then internationally, as I said in the prior slide, we matured our Malaysian PSC extension volumes into reserves, and that was slightly offset by an additional infill well identified within the Bertam field. So that gives us a year-end best estimate of contingent resources of 1.162 billion barrels of oil equivalent, and that's greater than 2x our large current reserve position. And if we take a step back, and we put into perspective, just 20% of the recoverable resource at Blackrod was matured into reserves, and that brought with it greater than $800 million worth of value. So if we're able to extrapolate that across the remaining contingent resources that we have, you can begin to appreciate the quantum of value that lies within the continent resource base and why it's a major focus in the company in maturing these volumes going forward. So 2023 investment strategy with an established platform of high-quality producing assets, delivering strong cash flow to the business, coupled with a healthy balance sheet, the stage is set for IPC to advance commercial development at our Blackrod property, and that's exactly what we set out to do to start this year. But it doesn't stop there. Growth through M&A has enabled us to be in the position that we are in today. And case in point, we've decided to enter into an agreement with a private company called Cor4 to acquire their business, which brings with it greater than 4,000 barrels of oil equivalent per day of immediate production just adjacent to the Suffield property. This is executed with no shareholder dilution as well as at a very attractive dollar per flowing barrel metric. So a key focus this year is going to be on integrating this asset into the IPC portfolio and unlocking the synergy potential within the Suffield operations and asset management teams. So management has made a conscious decision to dial back some of the base business expenditure and push some of the organic investments to the right because we were able to buy production for today cheaper than what it would have cost to develop within our own portfolio. And that really puts us in the position to have the flexibility of having a deep inventory of mature projects, whereby if commodity prices strengthen, we'll be able to add more projects into the budget and really maximize the value going forward. In addition to that, with having nearly $0.5 billion of cash at hand, the multiyear Blackrod investment does not crowd out our ability to stay acquisitive as well as maintain shareholder distributions. So 2023 production guidance is 48,000 to 50,000 barrels of oil equivalent per day. And you can see on the slide here, it's been an absolutely beautiful trend of increasing production year-on-year. And that has happened in tandem with a rising commodity price environment. 2022, as Mike stated, was a record production year for the company, settling at 48,600 barrels of oil equivalent per day. This guidance range does include the Cor4 volumes. And additionally to that, that offset substantially our natural decline, but the investments that we do have planned throughout the course of the year are high impact, where we expect a production benefit at the front end of the year from our France development campaign as well as from the wider Suffield area drilling program. In addition, we expect Onion Lake Thermal sustaining pad L to come in at the back end of the year and uplift some of the production at the back end of the year. Our diversified production mix this year is about 1/3 weighted towards natural gas and 2/3 weighted towards crude of varying grades with about 14% of our volumes coming from France and Malaysia. So our operating costs, we are guiding a range this year between $17.50 and $18 per barrel of oil equivalent. It's a slight increase relative to last year's operating costs, which settled at $16.60. This is largely attributed to the reclassification of Blackrod from E&A to PP&E, and that's for the pilot operation specifically. So that had a slight effect. And these cost estimates also do include the operating costs associated with our Cor4 assets. And within the operating cost structure, it does include provisions for maintenance and workovers, of which we do have a turnaround scheduled in Bertam in Q3, which is routine in nature. That happens every 2 years at that property. And Christophe will show the evolution of our operating costs per barrel of oil equivalent on a quarterly basis on in his section. So strong cost discipline is a key ingredient to our operational philosophy. We also ensure that we carry out critical maintenance scopes to ensure that we maintain high uptime, and this also ensures very safe and reliable operations. We minimize any discretionary spend, and we make sure that everything is activity-based across all the regions. So it's a very robust budgeting process that is undertaken and it ensures maximum profitability potential. So very exciting capital expenditure year. The majority of the capital is going to be directed towards Blackrod. And Chris has a great section of that within his Canada presentation. The rest of the base business expenditure is going to be allocated towards Onion Lake Thermal where there's some carryover for the project -- the bottlenecking project as well as to complete and tie in the sustaining pad L. There's also some activity to take place within the wider Suffield area on the very exciting Ellerslie play. In France, we have some investments going towards finishing our development program, which comprises of a 3-well infill program -- pardon me, Suffield program at the Villeperdue West field. And we also have a Merisier sidetrack plan to take place within the Paris Basin. In Malaysia, we're spending money on maturing the next development plan there. So as I had mentioned on the investment strategy side. We've deliberately scaled back some of the base business expenditure because we were able to purchase production today. But it's a very mature set of projects that can add immediate production that we have ready to go on the sidelines. And if commodity prices are to strengthen, we do have the ability to add that in if it meets the corporate objectives. So we take a look at the business in the more medium to long-term lens. We're expecting to average approximately 50,000 barrels of oil equivalent per day for the next 5 years. At the end of that period of time, we'll still have 80% of our 2P reserves remaining. And for the ensuing 5-year period, we expect to average 65,000 barrels of oil equivalent per day, and we'll have 50% of our 2P reserves remaining past that point in time. So the long-term investment strategy, you can see what Blackrod does for shaping the business. We have a deep, deep inventory and a long life assets contained within the portfolio. Once we get through the Blackrod growth CapEx, you can see that our sustaining capital beyond that is expected to be to the tune of around $5 per barrel of oil equivalent. And the remaining expenditure that we have planned for the next 5 to 10 years is really at Onion Lake Thermal, where we look to increase the nameplate production capacity from 14,000 barrels of oil per day to 16,000 barrels of oil per day. There's also some drilling to take place within Suffield as well as at Ferguson some gas optimization activity as well. And it assumes no further investments within the international assets that we have once the program is in complete in France. So quite an exciting and achievable business plan that, again, does not assume any reserve replacement. So now I'll transition to Chris to walk through Canada.

Thank you, Will. I'll walk you through Canada's 40,000 barrels a day of equivalent Canadian assets. And then we'll do a focus on our Blackrod development, and then also a little bit on the Cor4 acquisition that we had. So Blackrod getting lots of attention. First of all, just bring your attention to the map on the right-hand side. So Blackrod is located in the Southern Athabasca region of the oil sands area in Alberta. It's close to lots of infrastructure, roads, pipelines, both diluent, Dilbit and fuel gas. So it's strategically located from that perspective. It's a large resource. We have over 1 billion barrels that you've heard today, with 200 million of it now matured into what we call our Phase 1 development, or our initial development area. And it still leaves quite a bit of resource left to continue to mature. How did it all get started? A bit of a time line on Blackrod. So land was amassed in the late 2000s, and it has been well defined with stratigraphic holes and seismic to really understand the play and understand the delineated and take a look at the resource. We started drilling pilot holes. We've drilled 3 pilot holes there now. So there's 3 wellpairs, wellpair 1, 2 and 3. And each time, we've able to kind of progress the learnings associated with that development, whether it's the length of wells. We now drill 1,400-meter wells. You can see to the bottom right of the slide. The first pair was to the west. It was about a 700-meter well. The second pair was to the north is a 900-meter well. And then our third pair has been 1,400 meters well. And what we're doing there is looking at how far can we drill a wellbore from heel to toe to really minimize the total number of wells that need to be drilled in the project, which, again, reduces the number of pads, roads and aboveground pipelines that have to go with it. A little bit about the pilot. So the plot on the bottom left is showing wellpair 2 and wellpair 3. Wellpair 3 being the one in excess of 800 barrels of oil per day. That's a 1,400-meter well. And it has -- it's going along at a great SOR of less than 3 today. And you'll see we're designing our commercial facility to about an SOR of 3, that's been operating less than a 3. We're really happy with the results today. A couple of things you could see there on wellpair 2 and wellpair 3. So wellpair 2 is approximately just about 600 barrels a day. It was -- we shut it in. The facility can only really handle one well at a time. So when you do shut that in to drill the third pair. But when you look at wellpair 2 and you look at wellpair 3, on a per meter drilled basis, production per meter drilled, they really overlie each other perfectly. So we knew we were on to something in terms of the completion that we were dealing with there. So if I take a look at a 900-meter well, like 600 barrels a day and I look at a 1,400-meter well at 850 barrels a day, it's very close in the production per meter. So we feel really good about the commercial design that we're going to bring forward for the first phase of development. The overall commercial development plan at this time is -- it's an 80,000 barrel a day approved project. The original phase is going to be a 30,000 barrel phase. We'll talk a little more about that. It originally was going to be a 20,000, with an acceleration to 30,000. 20,000, with some growth to 30,000. Through some economy of scale, we're able to start off at 30,000 barrels right out of the chute, and there's definitely some economics associated with that. You can see over on the right-hand side, that's our first pad. So some of the learnings that we've done with the pilot is we figured out well spacing. We figured out the lengths of the wells. And so that first pad has 32 wellpairs on it. So 16 wellpairs are going to the north and 16 wellpairs going to the south on that first path. So 32 total wellpairs. 40 wellpairs will be drilled in total for our 30,000-barrel project. That's included in the cost estimates that we're going to talk today. And you can see where it's located in terms of the wellpair 1, 2 and 3, just off to the West. We have a schematic just making sure we're very clear on the type of technology that we're dealing with SAGDs. We've got 2 horizontal wells. There are about 5 meters of space apart between the injector and the producer. We warm up by circulating both those wells, then [indiscernible] and producer gets a steam circulation. And after enough of a steam slug, we're able to convert to true SAGD mode, where we are injecting into the injector and producing in the producer with gravity drainage. A little bit about the facility is we're starting off with 90,000 barrels of steam and 30,000 barrels of oil. So approximately 12 months ago, when we looked at the project, we're talking 20,000 barrels of oil and 80,000 barrels of steam. So as we'll talk through the CapEx movements, just keep that in mind. It's a plot plan of our first phase of commercial development what we see here. And what this is, is it's a modular design facility. So everything is built in a shop and has brought out in sequence as per construction plan. Everything is landed and put together and again, a very organized construction plan. It removes a lot of risk and seasonal problems of building in the field. And we've done this before. So at Onion Lake, and we'll talk about that project next. At Onion Lake, it was a 12,000 barrel they build in 2 phases. So it wasn't quite this large, but very similar concept on how we did build that. And the project management and the execution plan for that has been brought forward on this project as well. So we built Onion Lake on budget and on time, both phases. So we believe we kind of have the right learnings that we brought forward to this central processing facility as well. So we feel pretty good about engaging in it. It's an island power. So what I mean by that is we're not connected to the grid here. It is close to -- it is -- could be close to power. Again, we have lots of infrastructure in the area. But the most cost effective for power at this facility is going to be turbines with heat recovery units, and there's some efficiency around capturing steam with using those heat recovery units. So it's a co-gen turbine-powered facility. Capital, movements in capital. So approximately a year ago, we were talking around USD 540 million to put on a 20,000 barrel a day facility. Since then, we've accelerated some scope. We've dealt with some cost inflation. We've developed the project through FEED and into some detailed engineering. We're able to refine different work scopes to understand where our costs lie. And then we do got some contingency that you see as a major part of the increases because there is some known/unknowns that we're going to have to deal with, and there is some further definition of work scope that has to happen. So that's where that 15% contingency at 110 million sits. But if we talk about this scope acceleration, which is key to the cost increase and why. So on the facility side, we went from like we mentioned, from 20,000 to 30,000 barrels a day. So an incremental 10,000 of oil out of the chute versus expanding the facility [ 30 years ] after the first phase. And what we've done there is we've been able to do that without adding equipment or adding vessels. So we're able to just upsize some of the equipment and the vessel size. So you get that economy of scale. We don't have extra vessels. We don't have extra pumps. We just have -- everything is a little larger. So we were able to capture some economies of scale. So on a dollar per -- on a CapEx metric in terms of flowing barrel from a capital build, we are more efficient with this particular design. Additionally, there were some new but surplus equipment that was on the shelf that we were able to capture, which gave us some further cost savings to help us with that CapEx metric and it really did help on schedule and long leads as well. There's a fair few long leads associated with this facility. So we've captured -- again, now we've had -- a lot of our long leads are in place. We've procured them. We understand the costs. So we feel really good about the incremental acceleration in the facilities. On the drilling side of things, We went from 20,000 to 30,000 barrels of oil, so we require more wells. So we've had to build another pad and we drill 8 additional wells -- or sorry, a total of 16 additional wells have been added to the total scope from the 20,000 barrel to the 30,000 barrel. In addition to that, we have a bunch of utility wells that we've added in here. So an additional disposal, additional source water and also, we're dealing with a salt cavern for disposal of waste that comes out of the produced water recycle system. So we've added some drilling scope. We have our cost inflation. And again, it's just been a stressed supply chain. I think the world has seen it, a stressed supply chain. So it's come with some increased costs, longer lead time when it comes to equipment, and we've captured it there in our inflation number. And then again, contingency, a large portion there. It's about 15% of the project, and we hope not to have to use all that, but there is some known/unknowns that do go on. We've done some things with our contracting strategies to manage that very well. But having that in place will ensure success, and we've ran our economics as such. Schedule. So we started spending money, when do we get some oil back? When do we start getting cash flow? So this year, 2023 we'll be doing detailed engineering, finish the procurement of our long lead equipment and line up when we expect to be able to get those delivered. And start fabricating in the fab shop, starting -- get putting some of the fabrication modules together. It gets going in about quarter 3 of 2023. In 2024, we hit the field. We start doing some civil activities. So we have a good road going in there now, but that road is going to be expanded. It's going to be built up. It's going to be widened. And that will happen in early '24. We'll also start building the leases. We'll start building wellpad 1 and the CPF. So clearing the site, start moving the organics in the top soil and then bringing in [ clay ]. In late '24 and into '25 is when we'll really start to build the facilities out there. So we'll start to bring in all the equipment and stand it and start putting the modules together for the 30,000 barrel oil trading, 90,000 barrels of steam central processing facility. In parallel with that, we'll be drilling. So we'll have 2 type of drilling rigs out there. We do it in back style. So we'll be drilling surface hole so you move on to a pad and you go through that pad with one rig to do surface holes. Then you come back with another rig and you go through that same pad, you do intermediate and set intermediate casing. And then you -- and then with that same rig, you go through the batch of wells, again, doing your horizontal laterals. And that allows us just to bring in the expensive tools in a smaller period of time versus how thing was sitting around on standby throughout the time to drill. In parallel with that as well in '24, '25, we have some commercial requirements. Again, we need to bring in fuel gas. We need to bring in a diluent and we need to take away our Dilbit and tie it into a line that takes us into an Edmonton market. So those are progressing now. We've identified right of ways and consultation is happening with the third-party commercial requirements that we have. So those are advancing in parallel as well. First steam late 2025, so Q4 2025. And then first oil approximately a year after that, which is late 2026. We have some -- believe that we hopefully will be able to be quicker than that on first oil, but we -- based on the ramp-up procedures that we've had at the wellpair, we've factored that in. And so this is our best guess at this point. Onion Lake Thermal. You can see on the production chart, it's running now close to 13,500, 14,000 barrels a day. So this facility was built in 2 phases. It was built in the 6,000 and then another 6,000 and then a bit of an expansion. It was built on time and it was built on budget using some of the same plans that we're going to use on Blackrod. So we've got a lot of learnings from that. We're very happy with what we have here. We have a big resource. It has a sustaining level to keep us in that 13,000, 14,000 barrels a day for a long time, lots of inventory, lots of resource. So it's a nice sustaining cash at this point. The plots on the right-hand side are showing drainage patterns. So we've drilled everything there. You see L is the most recent one that we've drilled that has not came online yet, have not required it. We plan to start to warm up some wells and put some production on later this year off pad L, drainage pattern. Suffield. So the large, yellow blob is really the -- our land base where we are on the Suffield base. You can see the different deposits that we are developing there. What we're showing here is there's some, what we call, our expansion to Suffield, take into account our comparative advantage of what we've been doing at Suffield. We were able to chase a play that was just west of us that IPC had some land on. We were chasing this particular fairway. This is Ellerslie fairway. Cor4, which you've heard a recent acquisition, we'll talk about it in a bit. was well developed into that fairway. So it was a very natural transaction to acquire Cor4. The production that's coming from Cor4 is predominantly oil, it's 80-plus percent oil and 18% or 20% gas on a production split perspective. You can see the production growth that we do expect on there. So our Suffield asset on the oil side will be greater than 10,000 barrels for a period -- quite a period of time. A little bit about Suffield, going back to the history of the Suffield. So the -- through just good oil optimization, the drilling of our end-to-end field that was in the existing Suffield, we're able to get reserve replacement in that 31 million barrels of organic reserve replacement throughout the years. And again, just from good oil optimization of the existing asset and looking where there was places to drill. In addition to that, with adding the Cor4 barrels, another 16 million barrels of 2P were associated with that. We are about 47 million barrels of reserve addition. The plots are showing a couple of significance on the plots or the bottom left being the oil. You can see since the acquisition of IPC that the decline of those assets has really changed. And that, again, is through optimization projects, working the well stock that we have out there, ensuring that those facilities are running with the highest uptime possible. In addition to that, drilling some of the plays that we're in there. And we call that, one is our end-to-end, which is a [ polymer type pad ]. On the gas side, very similar story. You see the decline that was happening, and then the work that went into giving the assets some love. So really, these are shallow gas wells. They fill up with water. They fill up with mud. You need to take quite a bit of time to swap these wells and keep them flowing. And it keeps our production rate quite up. You can see each winter, you can see there's always a blip down around November through February. There's always a blip in gas. A shallow gas doesn't come up with a lot of pressure. When we get the very cold minus 20 plus weather, we do get freeze-offs but everything does come back afterwards. So back onto the Suffield extension and the Cor4 acquisition, which there's a bit of a blow up there. The Ellerslie fairway was a play that we were chasing at Blackrod -- at Suffield. And we were planning to drill a well ourselves this August. And coming into that land sale, we did pick up some land that IPC was interested in to be able to grow that play. At the same time that we're watching that play developed Cor4 was moving along that fairway quite well. So the acquisition was very natural to want to bring them into the fold. So we had about 10 development locations associated with the land that we had picked up. The Cor4 land has an additional 25 plus drilling locations. These wells are IP30s in greater than 200 barrels a day, and they recover around 200,000 barrels each. They're great cash flow wells. They -- good production right out of the gate. And so this year, we'll be drilling approximately 6 wells on that acreage in the 2023 year. Ferguson. So Ferguson came through an acquisition of a company called Granite, as you've seen in earlier in the presentation, it's done what we expected it to do. It has an inventory of drilling locations. We tackled 16 of them. These are long horizontal wells. We tackled 16 of them in 2022, and we've brought them on production. You can see production has approximately doubled, peaked a little higher than that. We've had a little issues over the winter here with the cold weather, and we had some cold weather downtime issues. So the production had dropped off a little bit, but it is coming back now. And so again, we have an Inventory of wells that are ready to go, and we'll drill them as cash flow permits. Conventional assets. On the conventional side of assets, these are kind of primary producing type wells. And really what they do is they provide free cash flow for our growth projects. So we go in there, we drill these wells. They typically pay out very quickly at the right price environment, and we use the free cash flow to focus on our growth projects. That's the base business and a focus on Blackrod and Cor4. Thank you.

Thank you, Chris. Now I'll spend some time on the Malaysian and French business and the assets that we have. For those who aren't familiar with the IPC story, these are the 2 main assets that IPC inherited upon spin-off from Lundin Energy back in 2017. So as announced at the end of last year, we managed to extend our PSC in the Bertam field for an incremental 10 years. That goes all the way up until 2035 now. It's a great achievement, not only for IPC Malaysia, but also for the host country as a whole. Our plan this year is quite straightforward, which is to deliver on our safety targets, our cost budget as well as meet our production volumes. We'll also be looking to evaluate the next field development plan. So hats off to the Malaysia team again here. They're continuing to fire on all cylinders, the operational team. They managed to deliver greater than 99% uptime excluding planned outages, which is a phenomenal achievement to continue to do year after year. We also had a very successful development campaign last year. where we did the A15 sidetrack as well as 3 ESP upgrades. You can see on the production plot, the production benefit that we got from that program where we had multiple months with excess of 6,000 barrels of oil per day. And this program was executed in an environment where updated Brent prices averaged around $100 a barrel. And the high-quality nature of the crude from the Bertam field commanded a premium of greater than $10 a barrel throughout the course of last year that resulted in an absolutely rapid payback of the program of approximately 4 months. And you can see what the infill campaigns have delivered in terms of the ultimate recovery. It's really gone above and beyond what our predrill expectations were. And another point of significance with our Malaysian asset was in last year, we managed to achieve 100% reserve replacement. And this year, we had an excess of 100% reserve replacement again as a result of the PSC extension. So France, very exciting time in France right now with development activity underway. We recently spud the third and final well within the Villeperdue field. And following completion of that well, we will move the rig to the Merisier field to execute a side track, which is also within the Paris Basin. We're looking to continue to maintain a high level of operational efficiency and continue to mature our organic growth opportunities. So the picture to the top right that you can see, this is actually an older picture was taken in 2019 when we were doing the Vert La Gravelle development campaign there. And you can see in the production plot, the benefits what we got from a production perspective from doing this program. So the goal and hope here is to replicate the success that we've had with our current program in Villeperdue and Merisier. And as a reminder, what we're targeting is the Dogger carbonates wells formation part of me in France, in the Paris Basin within the Villeperdue field and within Merisier. These wells are single legged horizontal wells with approximately 500-to-600 meter long drain length, open hole completions, and we equip these wells with bean pumps or pump jacks, and we have a lot of ESPs in inventory. So once production rates stabilize, we'll look to install the ESPs to increase the output. So our current 2P reserves, the vast majority of them at this point in time are within the developed producing category. And if the program is successful, that is underway at this moment in time, there is the opportunity to increase undeveloped reserves with the locations that are currently held within our contingent resources. In summary, the production guidance this year, 48,000 to 50,000 barrels of oil equivalent per day. We have a robust plan that underpins flat production rate of 50,000 barrels of oil equivalent per day for the next 5 years, which grows to an average of 65,000 barrels of oil equivalent per day for the ensuing 5-year term. So the Blackrod Phase 1 investment is an absolute game changer and is a key component to the growth that we expect see, but we will continue investing in the base business to ensure that we maximize the value creation here. And we're all extremely bullish when it comes to the pricing outlook. What this does is it sets us up for continuous reserve replacement and overall being in a very, very strong position to continue shareholder distributions as well. So with that, I will invite Christophe Nerguararian to come to the podium and go through the financial numbers. Thank you.

Thank you, Will. Good to see all of you again. Let's move on to some numbers. I think this slide is really important, almost respectively of what is your view on oil prices or gas prices, this is a matrix that you can use to really plug in your own price deck lower, higher in between. It's essentially proportional and mine amongst those 3 cases. We've picked up Brent prices of $70, $85 and $100 but we will also show you what is the impact in terms of sensitivities on cash flows in case you would want to change the WTI/WCS differential. So we will show you the impact on cash flows, if that was to increase or decrease by $5 and as well even if our AECO base case is using CAD 3.5 per Mcf, you can see the impact of that gas prices being increased or decreased by CAD 1. So with all this in mind, we will show you what the netbacks in terms of U.S. dollar per BOE are in terms of revenues, OpEx, CapEx, free cash flow or EBITDA. And using those different cases, you can really play with those numbers, adjust to the scenarios you would like to run and translate that in free cash flow going forward. So we're using as a base case, $85 Brent with a $5 discount to the WTI and another $20 discount to the WCS. And you can see that in our high case, at $100 with $95 WTI and $75 per barrel WCS, it's pretty much in line that high case with what happened in 2022. AECO gas price is lower. I'll come back to that. And I've talked about the sensitivities. So in terms of guidance, I reiterate what's been said by Will with a production in between 48,000 to 50,000 BOE per day. We have a significant CapEx program, which is really comprised of USD 78 million for our base business and USD 287 million for the -- for Blackrod. We are guiding operating cost in between $17.5 and $18 per BOE. It's really in line with 2022, I'll show you why. And so the output I can mention already is just shy of $50 per BOE netback in terms of revenues, $21 of operating cash flow and $15 of free cash flow in the base case before the Blackrod CapEx for this year. In terms of realized prices, you can see here that we're assuming -- so it was a Brent at $85 . We're assuming that we're selling our Malaysian barrels with a premium of $5 that we're selling our French barrels on par with Brent and that we're selling of Suffield and Onion Lake heavy barrels almost in line with the WCS's tiny discount on the Suffield and we're assuming for 2023 that all of the Onion Lake production is blended and sold on priority with WCS. The AECO price, you can see how it compares the [ 3.50 ] to the previous year. So obviously, in 2022 was much stronger, but the [ 3.50 ] is essentially in line with 2021. We're using a modest premium for Empress of $0.10 on average for the year. We are selling, as you know, our gas on the Alberta-Saskatchewan border. So we tend to benefit from a premium there because we're closer to the end market, which are Toronto, Chicago and New York. In times where there are some logistical challenges or challenges to inject gas in storage in Alberta, we tend to benefit from a higher premium at our selling point. So in terms of hedging, I mentioned this morning at -- in Q4 because we hedged a good chunk of our WTI/WCS differential exposure. We had some hedging gains. In 2023, we initially wanted to protect ourselves against potentially issues in the transportation of oil from Western Canada to the U.S. Gulf Coast. And so that WCS quality in Hardisty is referenced as the WCS and the WCS quality in the Gulf Coast is referenced as the ARV. And so by hedging 60% approximately of our Canadian oil production between this WCS and ARV we're essentially hedging ourselves against any issues we may face in terms of transportation costs for that part. There was a small leak on the Keystone pipeline in December, immediately the transportation cost widened quite a bit in January. So with that hedge in place for the whole of 2023, we already benefited from hedging gains in January 2023. Otherwise, for the rest of the year, it's relatively in line with that $10 differential we hedge that. On the gas side, we want it in the context of what we believe were reasonably high prices. In any case, decent gas prices in Q4, we didn't really anticipate that the winter would be so mild and gas prices would come up so fast. But in any case, we hedged more than 33 million square a day, during Q1 in excess of CAD 6 per Mcf and for the so-called summer strip from April to October this year, we've hedged the same volume in excess of $4 per Mcf -- CAD 4 per Mcf for that period of time. So those are really the 2 hedges we have in place, no Brent or WTI hedges. We don't have any covenants in our bank facilities to do that. In terms of other hedges, that was on the FX side. The U.S. dollar was extremely strong in the fourth quarter and because we need to pay a good chunk, if not all of our OpEx in Canada or France in Canadian dollar or euro, respectively. We've bought forward some of those euros and Canadian dollars, and the they're really in the money right now because the dollar strengths have come off a bit against those 2 currencies. So if you look at the margin netbacks, I talked about in our base case for around $50 per BOE revenues and with the operating costs right in between our guidance at between $17.5 and $18 per barrel of oil equivalent, gives us a cash margin of $22. Just want to explain a bit on the operating cost fronts, so you can see, quarter-over-quarter, we have a small spike in the third quarter, which is just a function of a slightly lower expected production when we're going to have to shut down Bertam for the FPSO for a few days for regular maintenance. Otherwise, it looks to increase and it marginally increase against $16.60 that we realized on average for 2022. But the reality is that because we've sanctioned Blackrod, it's an accounting technicality we're now reporting Blackrod, even the well pair 3 is going to add to the revenues and to the OpEx on the P&L. Until last year, it was just reported on the balance sheet. Those costs were capitalized on the CapEx line. So by adding a bit of operating cost here, you bump up the dollar per barrel. But in terms of net free cash flow, it doesn't change. So what it means in terms of operating cash flows and EBITDA in terms of netback you're around $21, between $27 and $29 in our high case and you can see that it's -- there is still some upside compared to 2022, which was a very, very strong year, but there's still a bit of upside in our high case compared to 2022. In terms of net profit, so in our base case, we're looking at [ $8.5 ] per barrel. And I'll let you play with the numbers again, if you want to -- if you have a different -- a different set of oil and gas prices. I think this one is important and again, we'll help you play with numbers and realize what is the impact of the sensitivity on the WTI/WCS differential with a $5 increase or decrease, the impact on cash flows would be $2.3 per BOE or roughly $40 million or $41 million. Same with a decrease or increase in gas prices with an increase the impact on revenues is $1 per BOE. Of course, the operating cash flow impact is a bit less because we're using gas as an input to our Onion Lake operations to steam the water we inject in the ground. So it's in case this gas price would increase, it increases revenues, but it also increases some of the OpEx. And you can see we told you that on average, we are producing 3 times more gas than we're consuming hence, the ratio between the revenue impact and the OpEx impact. So net-net dollar -- Canadian dollar per Mcf increase on gas prices would improve our free cash flow by $11 million, whether it's operating cash flow, EBITDA or free cash flow, that's the same impact, obviously, $11 million. This slide is important, and I will let you spend some time if you wanted to. But I think the one important number here on this slide is the base case and the free cash flow before Blackrod CapEx, so we would be generating in '23 in that base case, $15 per BOE. And that -- and after CapEx from -- for Blackrod, we roughly breakeven at $85. Of course, cash is fungible. As we speak, we're sitting on USD 500 million of cash. And so the funding of the Blackrod project for this year comes irrespectively, from our free cash flow or from the cash at hand. In terms of capital structure, our balance sheet remains extremely strong and is unchanged for the last few quarters since we issued bonds. We're still fairly unlevered. We're sitting on 300 -- we issued $300 million of bonds at a 7.25% coupon almost a year ago to the day. Our bonds are trading less yesterday. There was a trade at around 97.5%. And not so far from the power, which is important because the base rates have increased and what that means is our credit spreads for IPC have improved quite significantly. There is -- we still have this very small EUR 13 million French loan, which we amortize on a quarterly basis and a fully unutilized CAD 75 million revolving credit facility in Canada. Maybe just to draw your attention on a few people in the past asked us whether the -- why we raised the bonds and why we were sitting on cash. It's interesting, if you do the math, believe it or not for -- with capital guarantee, just overnight deposits, we can generate 4.5% on our deposits, whether it's Canadian dollar or U.S. dollar. So effectively, with $400 if we place on deposit $480 million of our cash that generates 4.5% that fully covers the 7.25% coupon we're paying on our $300 million bonds, right? So everything being equal, it's -- we don't have a cost of carry as we speak for the bonds. But obviously, we're in a comfortable position with all this cash on our balance sheet. Thank you very much. Very happy to take some more questions later on and I'll let you -- let Rebecca explain what's going to happen in the next few years.

Okay. I have to bring my own presentation because 6 years at IPC, and I can't see the screen. So let's talk about reserves valuation. So we've shown you a lot of numbers today, the short-term numbers that Christophe's has outlined. We've shown you our short-term budget production profiles. Will and Chris have taken you through a lot of detail there but we've also shown you our medium-term forecast through 5 to 10 years' worth of cash flows and our reserves valuation. So a little bit of information on what our major assumptions are behind these numbers. And we'll start with price deck. So for our reserves valuation, we take a bottom-up approach. All of the assets we bring in all of our technical profiles, we apply, of course, the macroeconomic and the fiscal environment and this is the major part, our reserves order to price deck behind our NAV10 and NAV8 numbers that we gave you previously. As you can see, 2022 was a bumper year at $100. And then there's some backwardation in the price deck there, it starts from $90 but then goes to an $80 long-term forecast. And when we convert that to WCS, Christophe has indicated in his short-term forecast, that he's got a $20 WCS differential. Our reserves auditor also is using that short-term $20. And we expect that, as you can see by their forecast as well, that it will come back to a pipeline differential there is Trans Mountain coming in the third to fourth quarter of 2023, and we expect that the barrels will move back into the U.S. strategic storage as well over the next couple of years. In terms of the Empress gas price, we've given you the hedging information there. So the [ $6 ] that sits there in 2023, which is the reserves auditor forecast. We have actually got 30% of our Q1 hedged at that particular level. And then long term, we're coming into a 450 CAD long-term forecast there. But to the more interesting slides and Mike has taken you through this as well on the 5- to 10-year forecast our enterprise value of close to [ $1.3 ] billion. You can see that our NPV10 of 2P, so this is excluding the cash component, 2.7x our enterprise value today. We've got a 1P that is 2x our enterprise value today. And actually, our enterprise value is pretty close to our PDP value for our reserves. So really important to see just how undervalued we are on these metrics. And if I can draw your attention to the slide on the -- sorry, the pie chart on the right as well because this is really important. You know that we've given you our Blackrod value, yes, it's about SEK 94 a share. Of our SEK 270, which includes cash, so SEK 262 without the cash. Blackrod is 25% of that value. So 75% of our 2P value is backed by our current producing assets. Most importantly, Onion Link in Canada, but also our Suffield including our new Cor4 valuation. And we've got Canadian tax balances. So we will publish our tax balances, but I can tell you that, that includes about CAD 900 million worth of future depreciation there. And of course, Malaysia and France, which are still producing nicely as Will outlined in his presentation. And then from this value here, Mike has taken you through how then we convert from this SEK 270 over the next 5 years, -- we use our cash flows of [ 700 million ] to [ 1.4 billion ]. We can then convert that SEK 270 into between SEK 500 and SEK 900 per share by buying back our shares, using this cash generation, which is phenomenal from our underlying producing assets. And also, of course, fund Blackrod at the same time. So very quick, we put this slide up because it is important to note that end of last year, we had a NAV of USD 2.2 billion, if we run at last year's price deck, our reserves of this year, not only did we generate $430 million of cash in 2022 but we've also managed to replace all of that value through organic and -- organic growth acquisitions and also value replacement at our base assets. So you can see that actually, we've got a small increase that goes to $2.4 billion worth of NAV there. And then, of course, a slightly higher price deck this year comes up to the $3.5 billion level that Mike has talked about previously. So it was relatively quick, but we can then turn to conclusions from Mike.

Okay. So thank you very much, Rebecca, into the IPC team for the very detailed presentations. So just one final slide from my side and some concluding remarks before we can open up for some questions. I think you've heard, obviously, last year was a record year for the company. We reached new heights in terms of production. And we generated record cash flows. And as Christophe took you through in his presentation, I think the financial position and the balance sheet of the company has never been better. But I think as we look forward, the company has never been in a better position and has such a bright future to continue our long track record of generating huge amounts of value for our shareholders. So if we just recap our production guidance for this year is 48,000 to 50,000 barrels of oil equivalent per day. So that's a bump from where we were at this time last year. We expect to be able to stay on average at 50,000 barrels of oil equivalent per day over the next 5 years. And once we've developed and put Blackrod into production, we're going to see that long-term production grow by another 30% to in excess of 65,000 barrels of oil equivalent per day. So extremely positive long-term production growth coming from the business over the next 5 to 10 years. We've talked about, Will has walk through the reserves growth, the phenomenal increase from the decision to sanction our Blackrod Phase 1 development and Chris went through in great detail. We're adding close to 220 million barrels of additional 2P reserves. And as Rebecca has shown on the value presentation in excess of $800 million of 2P value from that project. And as I showed earlier, as we continue to fund that project and the capital gets behind us, and the increase in our NAV per share as we continue to buy our stock back increases exponentially. Value perspective, the 2P reserves value that Rebecca just walked through, is USD 3.5 billion. She showed that on a like-for-like price deck. We've still managed to materially increase the value. But of course, at the same time, we reduced and canceled the share count, 12% of our shares were retired last year. So of course, if you took that into account, you're going to see an additional 12% uplift in value. When we run our numbers and divide our 2P reserves value with a much lower share count and we're seeing today a SEK 270 per share -- net asset value. When you compare that against IPC's current share price of around SEK 100 per share, that's a huge discount to just the 2P net asset value assumes that we don't convert any more contingent resources into reserves and assumes that we don't do any more M&A. The balance sheet is in great shape. It's never been in better shape. The net or the gross cash, if you like, post the funding of the Cor4 acquisition has a sitting on a war chest and $425 million. And of course, that means that we've got the financial strength to really attack all 3 of our capital allocation and pillars. We can fully fund our Blackrod development project, but we can still continue an aggressive shareholder return framework. And this year, we've made the commitment to at least conclude the NCIB and buyback and cancel 7% of our shares outstanding. And of course, we're also in the position of that in excess of $400 million war chest that doesn't crowd out our ability to do further M&A. We've generated huge value from M&A over the last 5 acquisitions that we've done. We were very pleased to announce another acquisition adjacent as Chris showed to our Suffield property, very strategic, nice little tuck-in adds 50% to our Suffield oil production. And I certainly believe that we've got the capacity to do further M&A in the years ahead. And last but not least, on our sustainability focus. We're very pleased that we've been able to extend the longevity of our net emissions intensity reduction targets through the end of 2027 as opposed to previously, which was by 2025. So that concludes the presentation part, if I can maybe ask the IPC team to come up and we can take some questions from the audience here. And then Rebecca, you can moderate some questions from the Internet. So.

All right, we start with the audience. That's where we can run to, [indiscernible] Lars there.

First of all, thank you very much for what you delivered in the last -- when did you spin off -- was it shareholder day 1.

Just under 6 years ago.

I remember, I remember with you and Christophe sitting there, having a long discussion, if you should keep this very small firm in the portfolio or not. Luckily, you convinced us, which -- thank you very much again for that. So having a couple of questions, and I'll leave it to the audience and the further questions is what's about, as you said, we are bullish on oil prices. And if throughout the year, we are seeing high oil prices, is it more about production growth, what we heard from Chris? Or is it more about shareholder return opportunities, additional shareholder return opportunities, number one.

Okay. That's a very good question, Lars, and maybe I'd just pull up the shareholder return framework as a reminder. I mean I think if you look at -- if we're in a $100 per barrel price environment, then you can see that even with the funding of Blackrod, we've got around in excess of $100 million of surplus free cash flow out. I'm not going to say we made a commitment right now to say that an SIB will take priority over organic growth. And I think what we'll do is at the time when we've got the confidence that we're going to be generating, hopefully, a significant surplus free cash flow. We'll look at where is the stock trading and we look at the returns from incremental investments and we'll allocate the capital to the activity that's going to give us the best possible returns. But the one thing I would say is when you look at now our 2P value inclusive of Blackrod, I think the maths that I showed you, when you walk through and you look at the multiplication effect that you get as you retire your shares, we certainly wouldn't rule out further shareholder distributions in the $100 environment.

So SEK 250 of share price, you would consider some organic growth as well.

Potentially, yes. [indiscernible] of that problem.

And another question, sorry, one follow-up directly on Blackrod. Was 30,000 really the ideal point because you obviously said there are some efficiencies. Was there a consideration to go directly to 40,000 or 50,000? Or how did you actually come really up with the 30,000? Is it the ideal point of cost versus benefit? Or how did you actually come up with 30,000?

I mean it's so through feed, of course, there's multiple different development scenarios were analyzed, and we were looking at -- and of course, it's a trade-off between maximizing value and also looking at the capital exposure. But I think when you get to that 30,000, as Chris talked about in his presentation, this is very kind of modular. So by upsize in the vessels, as Chris talked about, we found that, that was really the sweet spot to get to in terms of returns and breakeven. So of course, we could have gone straight to 80,000. But of course, you look at the capital requirement, and that would have produced for us, it would have been just too much for us to swallow in one go. So really the 30,000 ramping quickly when into an environment, obviously, we're quite bullish on oil prices in physical markets. We can get there in 3 years' time. So I think that combination delivered for us anyway, the biggest value proposition for shareholders.

It's James Hosie from Barclays. I guess, on Blackrod, I appreciate your oil price builds clearly. But how do you respond to challenge the $59 breakeven at 10% NPV is too high, particularly for a project of that kind of long-term duration.

It's a good question, James. I mean, I think sub-$60 per barrel breakeven and still a full 10% rate of return is pretty good. I think as Chris showed in his presentation, it does also allow a certain amount of contingency in there. And of course, we hope to be able to do better than that. But I think when you look at and invest in a project with the balance sheet that we have, even if oil prices drop back for a number of years to $60 per barrel. We're still in a position to be able to fully fund that project. I don't think it's not too big a bite, if you like, for IPC. And I think when you put it in context of the value creation that I showed as you get through the investment and the experience we all had in Lundin Petroleum, when we did Edvard Grieg, and that's how you build companies, that's how you deliver exceptional returns. And I think when you look at the value creation over just 3 to 4 years, once you've done the heavy lifting and you've put these projects into production that exponential impact, I think, is difficult to replicate through just organic growth or share buybacks. So yes, it's that kind of transformational growth that's really driven us to move forward with a sub-$60 per barrel breakeven project.

Okay. And just I could follow up then. You sort of mentioned the contingency. Could some of that almost come out this year as you identify some of the known unknowns. And also how fixed is that kind of budget now? Are you effectively locking in contracts for the whole project at this point? Or is there a point over the next couple of years, you can adapt the project subject to the market conditions.

Do you want to take that one, Chris?

Yes. Sure. Sure. So yes, as work scopes do get completed, we should be able to take some contingency off the table. So as each year progresses, we'll be able to lower that contingency amount. We are working on contracts this year to be able to kind of lock in the scope of the contracting strategy does deal with some lump sums does deal with some target prices, different ways to incentivize the vendors and contractors to kind of work with us as one team. So we will have the majority of our contracts put together by the end of '23.

[ Kim ] with Pareto Securities. So thank you, first of all, for the presentation. Second, I was wondering with Blackrod. Chris, you mentioned that it might go a little bit quicker than what you showed on the board. I was just wondering what sort of milestones do we need to look for? And what needs to go according to plan for that to go quicker than the end of '26.

Yes. Good question. So Mike jump to the schedule. So it's really field activities that need to get done. So everything that we're planning to do in the shop in the fabrication yard, that schedule will -- should be very close to what we've planned out just because it's in a controlled environment. So when we do hit the field, there is some -- a little bit of time in there that if we have good weather goes with us, that will help. We'll gain some weeks, a month or so in that type of thing. So -- we -- it's really field seasonal-type activity while we construct out there. And we're playing with our workforce to man up at the right times and not to overman up. So just make sure we as efficient as possible through that. So it's really field execution that could bring the schedule in a few months early.

Great. And also, I think William mentioned that it's actually now cheaper to buy production in some places than actually develop it. And we've seen a lot of activity from you in Canada lately. Are you seeing the same trends elsewhere? And are you looking elsewhere? Or how are you looking for future M&A activity and that sort of thing.

Yes. I think, [ Kim ] we always -- we cast a wide net, so we're not wedded to one particular jurisdiction. Obviously, we've got a huge business in Canada. We've got a lot of capability, cost conventional across EOR and across the thermal business and we've got a big team in Canada and [indiscernible], who's here was kind of dragging the team that just delivered the Cor4 acquisition. So I think we're always just given the size and scale and the number of deals that we see in Canada that there's going to be a focus. But still, internationally, there's no question, the majors are still looking to the energy transition. They're still looking at disposing of some of the assets that they have within their portfolios. We've been involved in multiple processes still looking at assets internationally. Thus far, we haven't been able to do anything about -- apart from 25% our Bertam project that we picked up for 0. That was a nice one. But yes, we still continue to cast a wide net. And I think the success of any of the lending group companies that starts with asset quality. And it starts with the subsurface rather than jurisdiction. And if we can find the right asset for the right value proposition, and we're happy to bring that into the company.

It's fair to say, as you mentioned, quarter ago or 2 quarters ago that when we look at M&A, we focus exclusively on production and cash flows. We have enough development on our plate. That's a way to increase cash flows and also give us the opportunity to deploy more capital to buybacks and shareholders' return.

Great. One final question for me. You have been quite successful with hedges lately. Do you have a strategy? Or is it more looking at what's going on in the market at the time?

Well, if you take the gas hedge, for instance, we felt that if gas prices were to stay at [ CAD 6 ] and we hedged only at [ CAD 4 ] during the summer, given that it's only a portion, nobody would be extremely upset that we underperformed a bit, but that -- it's always a matter of maybe we want to protect the downside, more than fully benefit from the upside. We believe like when you look at some transportation risk for the Western Canadian barrels, there is more risk, there's more downside than upside. So we're happy to forego forgive a bit of forgo, a bit of upside, protect the downside. That's been what -- that's been our strategy so far, it worked very well in 2022. If you look, we hedged WTI/WCS at $13. We lost a bit of money in the first 2 quarters, but it was generally happy days to see a differential at $11 or minus $12. Again, it's a matter of the -- we believe there is some -- when there is some screaming in balance in our view between the downside and the upside. That's usually when we act.

And I think that's a fair comment because we certainly haven't hedged the FX in the last 6 years, but when we saw the real strength in the U.S. dollar late last year and of course, our euro exposure and our Canadian dollar exposure, we just felt that there was -- it was a bit asymmetric. So we decided it was a little bit opportunistic in that respect. But I think -- I think the big question in terms of the benchmark that Christophe showed in his presentation, we've obviously got a very, very strong balance sheet and still fully fund all of our projects and our growth plans down to the very, very low oil prices. So for the time being, being constructive on oil prices in the medium term, we want to kind of allow our shareholders to participate in that upside. That's why we have decided not to hedge the benchmark at this stage.