Attending in person today in London here, and welcome to those tuning in remotely to the IPC Capital Markets Day presentation. I'm William Lundin, the CEO, and we have quite a wholesome agenda today. I'll be starting with the introduction, and as well as provide an overview of our strategy, and then I'll be passing you along to Mike and Chris, who will spend a little bit more time on the operational aspects of the business. Then Christophe will touch on the financial numbers, followed by Rebecca, who will expand on the reserves valuation, and then I will end with some concluding remarks. So jumping right into it, touching on the 2023 highlights here, the majority of the presentation will be forward-looking. But just to recap some of the achievements that IPC achieved through 2023, it was a record investment year from a capital expenditure standpoint. We spent $327 million, which was in line with our latest guidance of $330 million, and about $240 million of that was spent on the Blackrod project. We achieved record production, an all-time high for IPC in 2023, which is 51.1 thousand barrels of oil equivalent per day, and our operating expenditure was in line with guidance between $17.50-$18 per BOE. It settled in at $17.60. With healthy commodity prices as well as record production output, we had strong cash flow generation from the business. There's $353 million in operational cash flow generated, and we had $3 million in positive free cash flow. So what that meant is we were able to fully fund our capital expenditure program through the cash flow that was generated from the assets within the IPC portfolio. Notwithstanding, we executed the transaction to acquire Cor4 resources in March 2023 for $60 million. We also returned about $95 million worth of value to shareholders in the form of buybacks, and we exited 2023 in a net cash position of $58 million. And when you include the bonds available to us, we have greater than $500 million in cash resources available to the company. In 2023, we also canceled out 7% of our stock through the Normal Course Issuer Bid program. We've also renewed that and intend to fully exercise that through the course of 2024. Very pleased to share there are no material safety incidents through 2023, and we're well on track to achieve our net emissions intensity reduction goal of 12-20 kilograms per BOE by 2025, and I'll expand on that in the ESG section in the upcoming slide. So starting into the meat of the presentation here, a big milestone was achieved for IPC. We've produced in excess of 100 million barrels since the company was formed back in 2017. It's a great achievement, and when we started life, we only had 29 million 2P reserves, so it represents 3, more than 3 times that amount. As of year-end 2023, we have 468 million barrels in 2P reserves, and with that, based on our midpoint production guidance of 47,000 barrels of oil per day for 2024, that represents a 27-year reserve life index. So a very healthy inventory that exists within the IPC portfolio. And again, when we started life, we only had an 8-year reserve life index, so that's more than tripled to where we are now. So over the next 5 years, between 2024 through to the end of 2028, the average production over that timeframe is 55,000 barrels of oil equivalent per day. And the free cash flow that we expect to generate during that timeline is between $900 million-$1.8 billion in free cash flow. So that is less all the development costs associated with Blackrod. And when we look at capital allocation, there's three core strategic pillars that IPC has, starting with organic growth. This is a ten-year production profile based on our 2P reserves, and as you can see, at the second half of that first five-year period, we start getting a serious production uplift from the Blackrod Phase 1 development, which is gonna push the subsequent five-year period, an average production to 65,000 barrels of oil equivalent per day. And that resource is vast, and you'll see that in the upcoming slides here. There's a much more resources to be matured into reserves there, so it's likely there'll be future phase expansions. And Blackrod, it truly is a world-class asset, not only from a sheer resource and volume standpoint, but as well from the amount of delineation that exists within the reservoir prior to sanctioning the Phase 1 development. So within the Phase 1 initial development area, the average well control we have in terms of appraisal data, which means appraisal density, which is the number of wells per square kilometer, it's about 2.5. So what that means in relation to an offshore field when you're going into development, that stat of the number of appraisal wells you'll have relative to a square kilometer is about 0.2. So what that means in distilling it down to a simplest form is that, you know, the subsurface, which is the most important part of any asset, is very well understood through the delineation work that's taken place through the last 15+ years. We have greater than 1.2 billion barrels of recoverable resource here. That's assuming approximately a 51% recovery factor. Phase 1 targets 218 million barrels of 2P reserves. It's an $850 million capital expenditure investment to first oil. With that, we also have 80,000 barrels of oil per day in regulatory approvals. So we're just maturing the first phase, which is the right size and appropriate volume for economies of scale. If we look forward to the point forward value as of 1/1/2024, it's just under $1 billion, using a 10% discount rate and it now has a sub-$55 WTI breakeven price. And our contingent resources within excess of 1.1 billion barrels of contingent resources that exist within our portfolio, this is really the feedstock to our organic growth plans. Not a single dollar of value is applied to any of these volumes in the valuation or free cash flow numbers that are shown today. With significant amount of those resources contained within the Blackrod asset, it's an important focus within the company to continue honing in on our future phase expansion plans. However, the primary focus right now is getting the 30,000 barrel per day development up and going off the ground. There is also, outside of Blackrod, a lot of valuable contingent resource barrels that we're continuing to work and mature as we progress through the period of 2024. Moving on to our second core strategic pillar, which is stakeholder returns. Our share repurchase program since inception, we purchased nearly 63 million shares back since the company was formed back in 2017. The average share repurchase price was SEK 65 per share or about CAD 8.7 per share. Relative to our current share price, that represents greater than $275 million in value that's been created from these buybacks, and with only 11% dilution since the company was formed. And some of these stats that you can see on the far right-hand side of this slide, we've increased our production fivefold. The 2P reserves has grown greater than 16 times. We've added nearly 20 years to our reserve life index. There's still a ton of contingent resources that exist within the portfolio, as well as we've added greater than $2.5 billion in net asset value. So if we conclude this year's Normal Course Issuer Bid program, and then we renew the next one for the following year, by the time that is completed, we'll be back at our original share count when we were spun off in 2017. This is our shareholder distribution framework that we have proposed for this year. It's largely in line with what we had last time, which is last year, which is 40% of our free cash flow that we generate, provided our net debt to EBITDA stays less than 1x, we will return that value to shareholders. Now, provided 2024 is a significant capital investment year for the company, will be a new record. There's not a lot of free cash flow generation that's gonna be taking place. But what is important to note is between $70-$90 Brent on the base business, excluding the growth CapEx associated with Blackrod, we expect to generate between $140 million-$270 million in cash flow, which represents nearly a 10%-20% free cash flow yield. So what's the important message out of that? Is that the base business is generating robust cash flow generation. Over the next 10 years, this is the cumulative free cash flow we expect the business to generate. In just the first 5 years, at $85 Brent, we'll be able to liquidate the market cap. In the 10-year horizon, we expect to generate between $2.65 billion-$4.6 billion in free cash flow, assuming a $75-$95 Brent price. Moving on to our third key strategic pillar, which is M&A. So we've crystallized greater than $2.5 billion, through 5 accretive acquisitions that have been done since inception. So what this slide is showing is the total consideration price, less the free cash flow that had been generated as of the end of 2023, and then the point forward value remaining of those assets. So there's a significant amount of running room to go within the assets that we've acquired. Our current 2P NAV as of January 1, 2024, is in excess of $3 billion. That represents approximately a 55% discount or slightly in excess of that today, if we're looking at our share price. So as provided, this stays disconnected in terms of our fair intrinsic value, using our 2P value. For trading at this significant of a discount, we're gonna continue buying back our shares, provided the balance sheet stays in good form. So I've touched on the five-year free cash flow we expect to generate between 2024 to 2028. After that period, we'll have greater than 75% of our 2P reserves remaining, and we expect sustained production growth greater than 20% for the subsequent five-year period, which will be around 65,000 barrels of oil equivalent per day. Between that timeline, between $75-$95 Brent, we expect to generate between $1.75-$2.8 billion in free cash flow. So as we walk one year closer to first oil with Blackrod, what you're gonna see is the free cash flow start to enlarge in the front five years relative to the back end of the second half of the 10-year horizon.... The power of the buybacks. What this slide demonstrates, if all we were to do is just mature our 2P portfolio and not mature any contingent resources into reserves or continue to execute any acquisitions, and we were to look at our point forward value as of January 1st, 2029, the NAV 10 per share in a $75 pricing scenario would be in excess of 750 SEK per share, or under a $95 Brent scenario, slightly more bullish, the value would be in excess of 1,200 SEK per share. What you can see is the slight red on the second bar. What that is, is ultimately there are no more shareholders that exist besides insiders. So that amount of cash would be returned to insiders if we were to use 100% of our free cash flow over the 5 years to buy back our stock between 115 SEK per share and 215 SEK per share, is the assumption in the price that we'd be buying our stock back. Sustainability and ESG. Very pleased to share we had no material safety incidents through 2023, which we take a great deal of pride in, given that we're the operator of all of the assets that exist within the IPC portfolio. We're well on track to achieving our net emissions intensity reduction target, which is 20 kg per BOE come 2025. We're very pleased to share that we're extending that target through to the end of 2028. Our latest net emissions intensity number was 25 kg per BOE. Also, what's really important is the local communities that exist around the operations. So IPC prioritizes hiring local staff, and the vast majority of our operations have 100% local staff, which is very important when it comes to responsible operatorship. With that, I'll hand it over to Mike for the operations section. Thank you, Will, and it's my pleasure to take you through our 2024 outlook before getting into more of the asset detail with Chris Hogue. So just starting at reserves and contingent resources. As Will mentioned, it's been another excellent year for reserves replacement at IPC. We've replaced around 78% of our production and reserves in what was a lower than typical producing asset investment year. We maintain a very healthy reserve life index of 27 years, and if I just draw your eyes down to the bottom waterfall chart, we moved to 468 million barrels of oil equivalent reserves from 470 million barrels of oil equivalent in 2022. Within the year, we produced around 18 million barrels of oil equivalent, and that was largely offset by the Cor4 acquisition in Canada. There's been some minor ups and downs at our other producing assets. If I just take a look at our contingent resources, our contingent resource base that is largely dominated by the future phases of Blackrod development. As we bring online, as we start up Phase 1, these barrels will come under the development radar. Elsewhere, at Onion Lake Thermal in Canada and Bertam field in Malaysia, we've matured some contingent resources into our 2P reserve space. At our Mooney asset in Canada, our contingent resources now are matched to the latest field development plan. Just moving on to our 2024 investment strategy. It's no surprise that in 2024, the focus is on Blackrod Phase 1, where we have our peak investment year. Chris Hogue will share some more detail on that in the Canada section, along with some of our other base business investments in Canada. On the back of that peak investment year, we have a more balanced view on our base business investment plan. However, we do retain the ability to flex this up and down, depending on continued strong operational performance and market conditions. And of course, we retain our opportunistic approach to M&A. So just moving on to production operations, and I'm very happy to announce the 2024 production guidance range of 46,000 to 48,000 barrels of oil equivalent per day in what is a lower than typical investment year for IPC. Along with that, our operating costs are stable and also happy to announce the operating cost guidance range of $18-$19 per BOE. So just moving on to our capital expenditure, and I won't spend too much time on this one. As I mentioned, the investment is dominated by the peak spend year at Blackrod Phase 1, something Chris will share details on, along with the other activities you see in the Canadian bubble there. For our international assets, I'm very happy to report that the planned well workovers in Malaysia have been successfully completed. And both in Malaysia and France, now our focus aligns to maturing the next phase of development opportunities in the regions. Before we go into the asset detail, I just want to touch a little bit more on our longer-term outlook, our five plus five-year outlook. On the back of the progress at our Blackrod Phase 1 development, we're extremely strongly positioned for longer-term growth. If I look at the next five years' production, we are forecast to average 55,000 barrels of oil equivalent per day, growing to 65,000 barrels of oil equivalent per day in the second five years as we reach plateau rates and stability at our Blackrod Phase 1 development. In that time, it's no surprise that our capital costs in the first five years as we complete the execution work at Blackrod's Phase 1 are slightly higher, at $11 per BOE. Coming back down in the second year to a more normalized sustaining cost of $5 per BOE. And in that time, from an operating cost perspective, we expect to be stable around $18 per BOE. And with that, I'll hand over to Chris to take you through the Canadian detail. Thanks, Mike, and welcome this afternoon. We'll step through some details on Canada, specifically, a little extra detail. So in addition to our large Blackrod growth project, we have a strong base of assets that has really helped us through all types of market conditions. So that's worked out well. In addition to that, they are very diversified, having gas all the way through to in situ molecules, again, supporting different market conditions when required. Our large growth project that we've been talking about is Blackrod. So we launched that in early 2023, so we have a year under our belt of working on the project. To date, we have secured all our long lead equipment. We've procured most pieces that are considered long lead. We've started accepting these at site now. Engineering is progressing well, and we've also kicked off a lot of our drilling program. What you can see just from the pictures that you're looking at there on the far left is a fabrication facility that is fabricating all our free water knockouts and treater facilities. Big vessels. The middle picture is referring to... That's our evaporator, so these are some of the heavy hauls, the long-lead equipment, heavy hauls. That's an evaporator coming up our road into site. To the right is our camp. We have a construction camp that is at site. Workforce is gonna peak somewhere around 350 people at site. And there's the drilling rig on location, drilling all our service wells associated with the project. A few more interesting pictures. Top left is, these are on the central processing facility. We have started all the tank bases, so those are the piles that sit with the tank bases. Those are for 20,000 barrel a day sales tanks. So the tanks sit on top of those, those piles and angle iron. The bottom left is a better picture of the evaporators that are gonna be at site. You can see them being landed with the cranes on the picture to the right. So what are evaporators? We're using them for produced water recycle technology. So all the produced water goes to, we call it IGF. We clean some oil up out of it first, then it goes to the bottom of these evaporators. Essentially, we are evaporating water, and as it condenses, you get the pure water off the top, and the waste, call it the salts and the hardness, comes out the bottom, and we dispose of it in salt caverns. So disposal facility right on site. We're able to keep it all in pipe and dispose of it right there as part of the project. The subsurface portion of the big project. We kicked off drilling in mid to late November. It focused on all the service wells, that includes observation wells, to focus on the steam chamber, understanding steam chamber growth. The salt cavern wells that I mentioned, to dispose of our waste off the evaporators, water disposal wells, and also our source water well for any makeup water that we do run. We recycle approximately about 95% of the produced water, but there is a little bit of makeup that comes out of those source wells. What we're looking at here is, on the right-hand side, is our geologists had mapped what we would call a potential low with one of our, to the west, I guess, of our Phase 1 development, based on some seismic readings. We went in there, we added another control point, and it was better than prognosed, so we actually were able to add a couple meters of SAGD-able pay to that, which again helps our Phase 1 plan. Where does schedule sit for Blackrod today? So nothing has shifted. We're still expecting first oil in October 2026. All major equipment has been procured. All the long lead and critical path type things have all been identified and mitigated, if there was something that is at risk. So we've got mitigation plans for that to be able to achieve that October, 2026 first oil. Jumping into our base assets that, again, diversified portfolio from gas to an in situ molecule. So, minor declines, less than 10% type declines, really underpins the cash flow required for the growth that we're doing here at IPC. This is our Onion Lake thermal asset. To the top right is the development. You can see the drainage patterns that are currently producing today. There's five drainage patterns that are currently producing today. We have another pad, we call another drainage pattern, we call it our L drainage pattern. It's also drilled, and we started bringing those wells on. Half of them are remaining as sustaining, so no initial capital is going to be required there to hold this at nameplate design, around 14,000 barrels of oil per day for the course of the next couple of years. The facility is running very well. The wells are performing. Again, we're, we're at nameplate today, and we'll just continue to hold it there as we, as we push through the years. Pad L, the bottom right, one of the newest pads that I mentioned. You see where we are outperforming guidance there, so we're really happy with the results that we're seeing there, the conformance, the production that we're getting. So all, all thumbs up for the Onion Lake Thermal project. Suffield, again, another strong asset, great base production, minimal declines. There's oil and there's gas associated with this facility with this area. So you can see the bottom left, you see a jump in production, approximately 4,000 barrels a day. That's mostly due to our acquisition of the Cor4 company. We've taken that, we've continued to drill that asset as well as along with some assets that we have on the west side of the Suffield project. Also, we have reserve growth, looks over 40% of reserve growth through acquisitions and just good base optimization work. Bottom right's always a story we like to talk about. The gas production here, it's close to 15,000 BOE a day of gas. That is, you can see how it was declining prior to our acquisition. Again, through optimization work, it's really a lot of, you know, well-focused on swabbing, keeping the mud and water out of the wellbores. We're able to really keep this shallow gas flowing. You can see the very stable, minimal decline. I mentioned there's some organic growth to do on this Suffield asset. So the top right is a picture of where our assets are located. The green blobs on the right would be the existing fields that we've been operating for a number of years. Just to the west, you can see the new fields that were both part of the Cor4 acquisition and also land position that IPC had prior to the Cor4 acquisition. And we've been drilling what we call the Ellerslie play. So it's a horizontal, it's a multi-well horizontal type play, and we're seeing some really fantastic results from it. We have a deep inventory of wells to continue to work on that organic growth and really help that asset. It's kind of tucked in right next to Suffield, so we're able to use a lot. There's some efficiencies, a lot of efficiencies, all the manpower, some of the facilities. The focus that we're doing there allows us to tuck it in with lots of efficiencies. You can see the guidance on the Ellerslie wells. It's approximately 8 wells of production there, and you see we're outperforming the guidance. Last, there's a few other assets that are supporting our base business and that cash flow for growth. The first one is I'll jump to Onion Lake. So right around our Onion Lake Thermal, we have the opportunity to drill primary wells and produce primary. Again, utilize the efficiencies of being in the area. So that continues. We have a base production there. Going north into our Mooney asset, this is a polymer EOR. It has an additional phase that we haven't touched. It's all the capital has been there. It's been drilled on primary. The, the flow lines are there, the pipelines are there. The facility is set up to handle it, so no additional capital required other than the chemical that you need to put in or the polymer that you need to put in to repressurize and start to sweep the, sweep the zone. So we'll be moving to Phase 2 in 2024. As a fill-up, you'll start to see some response in 2025. To the south, Ferguson asset and light oil asset, no condensate required. I bring it up because it's really a nice thing to have. You don't have to blend to be able to sell your oil. It has a drilling inventory associated with it, so even in a year where we are spending a lot at Blackrod, we are working on our base business, and so we have a few wells planned at Ferguson as well for the 2024 spend. It really covers everything in Canada, I think, at the level of detail. Thank you. Thank you, Chris, and now just moving back over to our international assets. So be no surprise with the, the strong history of operational performance at these assets. We'll focus on maximizing the value through operational excellence in 2024. And as I mentioned earlier, with the, the successful development campaigns or the recent successful development campaigns in both regions, we're now integrating the results and, and maturing our next phase of development targets there. And as I mentioned, the, the well workovers are complete in Malaysia. And just moving on to Malaysia, you see the impact of these workovers with, with production, daily spot production back above 4,500 barrels of oil per day. And the wells in the northeast of the field, the high relief wells, they continue to perform strongly, and this is aligned to our modeling, which indicates there's more oil in the area. And with that, our next phase of field development studies is really focusing in this area. So we are working to mature the next round of targets, and we hope to come to an investment decision this year. Looking at France, and when I look at France, I just want to draw your eyes down to the production chart in the bottom left of the slide here, where we continue to offset historical declines through strong operational performance, base well optimization, and of course, infill well drilling. And when I'm talking about infill well drilling, we're now integrating the positive results from 2023, and we're finalizing the next set of targets. So for our international assets, it's very much a case of operational excellence and building up the next phase of development in both regions. So in summary, in 2024, our production guidance range is 46,000-48,000 barrels of oil equivalent per day. We're extremely well positioned for longer-term growth with the Blackrod Phase 1 development and the peak spend year in 2024. On the back of that peak spend year, we've set a more balanced base business budget, of course, with the flexibility to ramp up in the case of strong operational performance and strong market conditions. 2023 was another excellent year for reserves replacement. Seventy-eight per... 78% of our production and reserves were replaced. Year-end 2023, 2P reserves are 468 million barrels of oil equivalent. And with that, it takes us to the end of the operational section, and I'll hand over to Christophe for finance. Thank you, sir. Good afternoon to everyone. Thanks for being here. So we will see how those all the description of our activity, the production guidance and our CapEx, see how it's going to translate into operating cash flow and cash flow. So we've tried to set a base case, which is in line with the current conditions. We're just above, like, $1.5 above where Brent is trading today. But if you look over the last few quarters, it's fair to assume a $5 differential between Brent and WTI. And in terms of the WTI to WCS discount, we're using a minus $15 per barrel. It's a bit wider as we speak, with hopefully TMX coming on stream in the next few months. That should be a bit wider, maybe that, what the, the market would show. In any case, we have 70% of our exposure to WCS with a, with a hedge at -$15, so it's fair to use fifteen. That's, that's where most of, for exposure is, is hedged at. In terms of, in terms of gas, as, as you may have noticed, the, the, the gas market in North America as a whole is a bit, is a bit weak. There, there's a lot of production, including in, in Alberta and in, in Western Canada, as an anticipation of the LNG Canada project, which is due to come on stream in, 2025. So there's been a ramp-up in production, a relatively mild winter conditions with the El Niño weather impact. That's positive in terms of temperature, paradoxically negative. So long story short, we are setting our base case for the gas price this year, lower than the actuals in 2023. And then, in order to facilitate your work as much as possible, we're running two sensitivities, one on the WTI, WCS differential, and one on the gas price. So with the three different cases, the low case at $70 Brent, the base case and the high case at $90, plus those sensitivities, you should be able to pick exactly your own assumptions and translate that into operating and free cash flow going forward. So just as a reminder, those numbers are based on the exact guidance given by Will, Chris, and Mike previously. So we're guiding a production of between 46,000-48,000 barrels a day, $437 million of CapEx, the bulk of which obviously is dedicated to the Blackrod Phase 1. An operating cost per barrel of oil equivalent per day of 18.2, which is not dissimilar from where we are right now or where we were in the fourth quarter. So you can see some logic in that guidance. And so as a whole, we can see slightly less than $50 per BOE of revenues in terms of net back, including... That includes all of our gas production in Canada. The operating cash flow stands at $18.5, which is marginally lower than the $19 achieved in 2023, but it's based from a slightly lower Brent price and WCS as well. The interesting point, obviously, is the difference between the free cash flow before the Blackrod investment and after the Blackrod investment. I think it's important to keep that in mind because, of course, Blackrod is the most important development right now. But we have a very solid base business, which is funding most of Blackrod. It funded 100% of the Blackrod CapEx in 2023. It's going to fund again a good chunk of the CapEx in 2024, and that base business is very solid. Looking at the oil price and how it compares to the previous years, you can see that we have... We're using a $5 premium for Malaysian barrels, hopefully a bit on the conservative side, 'cause we achieved between $7 and $8. In 2023, we're assuming we're selling our French barrels on par with Brent. A tiny bit less, 'cause we tend to sell slightly below the Brent for our Southwestern assets in France. And the other important point, obviously, in Canada, where we sell virtually all of our barrels on parity with the WCS, slightly below, there's a small quality adjustment in Canada for both Suffield, the Suffield area, and the Onion Lake area, where we tend to sell at $0.50-$1.00 below the WCS. And the AECO, you can see our assumption is historically below the last three years for a reason, 'cause as discussed, the market is a bit weak right now. In terms of hedges, we've, as usual, tried to be a bit proactive. Maybe the main difference this year compared to the prior years is that given the size, the sheer size of the expected CapEx, we've hedged for the first time the benchmark. So 25% of our WTI exposure or WCS exposure has been hedged. With hindsight, we should have done a bit more, obviously. We did lock in 25% of our Canadian production at $81 per barrel. So unfortunately, I'd say this hedge is big time in the money and will run through the whole year. In terms of differential, I touched on it. So the WTI, WCS exposure we have in Canada, we've hedged 70% of it at -$15. It's in the money right now. As I was mentioning this morning, for those of you who listen, there tends to be some seasonality in Canada, where the differential tends to be wider in the winter months and tighter in the summer months. So hopefully with TMX, as I mentioned, coming on stream in the next few months and the summer coming, we should expect the differential to tighten. But right now, we're actually making money on this hedge. Condensate, that was a small hedge we put in place. Traditionally as well, there is some seasonality there, and so we've hedged at a discount to the WTI. 50% of the condensate we need to blend with our own production before we sell it on par with WCS. And then we've been quite active on the, on the FX front. We took the opportunity of having a reasonably weak Canadian dollar against our reporting currency, which is the US dollar, to hedge quite a bit of our OpEx, roughly two-thirds of our OpEx in 2024 at CAD 20 million per month, and half of our OpEx for 2025 at CAD 15 million per month at 1.36 Canadian or US dollar per Canadian. And we've hedged a significant portion of the future CapEx for Blackrod as well, between 1.32 and 1.35. If you look at the netback, how all of these assumptions translate, so starting from revenues at, in the base case, at $47.5 per BOE, less our operating cost, as we guided, at minus 18.2, and some cost of blending. So as you know, we need to blend, so we're using some diluent and blend that into our own production to sell the WCS quality. So we're blending roughly 37% of our own production at Onion Lake Thermal and 14% at Suffield, and Blackrod will be around 40% in the future. So that translates into an additional $10, which gives us a cash margin of nineteen dollar, which is the same almost as our operating cash flow netback or a bit that netback. On the operating cost per barrel, you can see the trajectory. It's going to remain at or below 18 dollar per BOE for most months. But with the anticipated projected turnaround at Onion Lake Thermal, which is our main producing asset in Canada, with the turnaround, we'll have a bit less production during that quarter, so mechanically, the operating cost per barrel will be higher in that quarter, averaging out 18.2. At least this is our current forecast. So the operating cash flow and EBITDA netback are around $18. That translates, that compares to roughly 19 achieved in 2023. And that's really a direct reflection of the fact that in 2023, the Brent averaged close to $83, and in our base case here, we're using $80. So it's all very coherent, consistent, and when you'll be, I'm sure, playing with your own model at different price decks, you'll realize that the base business is able to generate a similar free cash flow than last year. Looking at the net result on this slide, so it's assumed to be $6 per BOE as a whole, includes some depreciation, some minor G&A. Happy to report the G&A remained totally under control, at or below $1 per BOE, as it's been the case historically for IPC since 2018. And some reasonably low financial items. As you may have seen, in our 2023 numbers, we are sitting on more than $500 million of cash. All of this cash is deposited mostly with Canadian banks, which and those deposits yield 5%-6%. So the four hundred and fifty million dollars worth of bonds, where we're paying 7.25% of coupon, the cost of carry is really minimal with the good yield we get from the deposits. In terms of sensitivity, and if you'd compare that slide to the same slide last year, you'll realize that we are much less exposed to the differential volatility. And it's a direct reflection of the fact that 70% of our exposure on the WTI WCS differential is hedged at -15. So obviously, Oops, sorry. When we increase the differential from -15 to -20, the impact is less than $10 million in terms of operating cash flow. Looking at the same, when you move or increase gas prices from CAD 2.13 to CAD 3.13 per Mcf, that has an impact of $1 per barrel. One dollar per barrel in terms of operating cash flow or EBITDA, so a more significant one than the same on the oil price or that than our sensitivity on the oil price. Looking at the free cash flow, again, we do it obviously on purpose to break down the free cash flow before and after the Blackrod CapEx, and you can see that we have a very healthy cash flow of $12 per BOE before the Blackrod CapEx, and it turns negative after the Blackrod CapEx. But as we'll mention, and that's a tribute to how strong and robust our balance sheet is. We'll be able to still carry on share buyback despite that, based on the very strong cash position we're in. And that's a good transition, just to remind you of how solid our balance sheet is and really our work on that front is has not been very sophisticated. We're borrowing money when we don't need it, so that's been the case since 2022, with the first $300 million bonds issue in February 2022. And that was done also in anticipation that the base rates were probably going to increase, so that helped us locked in reasonably low, a reasonably low coupon at 7.25%. We tapped the bond market again in September last year, so the main question we had to answer at the time from investors was: Why do you do it? And it's not easy to explain. We don't need it, but we just do it in case, which still puts us in a very comfortable place today. And similarly, we've increased. We had a few banks knocking on our door, which we happily welcomed in our revolving credit facility. So we have a pre-committed and almost fully undrawn revolving credit facility of CAD 180 million in Canada. So that, that puts us in the comfortable position or enviable position where we have more than $600 million, close to $650 million between cash and access to cash to carry to, to deliver on our three strategic pillars, which are delivery of Blackrod, share, continuous share buyback, and, and to, to remain opportunistic, as we've been, last year with Cor4, if we can find some, some acquisitions which make sense. That's, that's the end of my, my presentation. Thank you very much. Rebecca? Thank you, Christophe. So I've got about an hour to talk about reserves valuation. I'm sure you're all very happy about that. Just kidding. I think we always present one net asset value or net, net present value to you, and that's the result of 6-9 months' work by our technical teams on-site and in our corporate headquarters and in our Canadian and Malaysian and French headquarters, going through, monitoring our assets, developing long-term forecasts, 30-year profiles, and then sending that to Geneva, where we look at it. All the finance teams bring us their balances, the economics team pulls all that together, and then we use our reserves audit to price forecast to give you that $3.1 billion worth of net asset value that we've produced today. And so why has that number gone down since last year? Well, it's very simple. Of course, we're influenced by macroeconomic assumptions, and between last year and this year, our price deck has gone down, in particular on the oil side. So you can see that the Brent price has got an average $5 a barrel decrease over the first five years in that profile there. You can see year-end 2023 is in blue, year-end 2022 is in red, and then there's a subsequent decrease as well in your Western Canadian Select profile, of course, which is directly related to your Brent, although there's a bit of an increase in your differential as well. So that first five years is down by around $6 a barrel, and that carries through to the long term. Gas, in particular, I think Will noted that it was a warm winter in, in Canada, so that automatically brings all of your forecasts down. But the reserves auditors have kept that long-term gas price, which means they do see that convergence between U.S. gas prices, European gas prices, LNG coming in in Canada, and keeping that sort of $4.50 level long term on the Canadian gas price... And so what do these numbers actually mean? So net NPV 10, 2P is $3 billion, and that's really our most likely scenario. So this is what we forecast on, where all of our targets are set, where our production profile long term comes. All of the data that Will and Christophe showed you is based on this 2P most likely profile. So that's our target, and that's what we operate to. But if you look at where our value is set, our enterprise value, it's at $1.3 billion. So obviously, undervalued on that basis. But I think one thing that gives some reassurance, particularly to some of our credit analysts that might be out here, we've got significant backing by our producing assets. So our PDP, which is our producing assets, doesn't include the development, is backed by almost $1 billion, US dollars worth of value here. Quite a large number, which is almost the enterprise value of the company altogether. And where is that divided? You can see that two-thirds of our assets are our producing assets. Two-thirds of the value sits in our producing assets, one-third in Blackrod, which is our development asset. So again, backed by our producing assets, the significant value that we get off our base profiles, which is funding Blackrod, completely funded it last year, and also funding some of our share buybacks and other shareholder-related activities. I can do it in three slides. So the third slide, I think what we wanted to show you is that, like any other oil company, we are exposed to oil price, right? So you will see the decrease from $3.5 billion to $3.1 billion this year. But really, that's just part of a long story where you can see the oil price in Brent underneath in the red line, that 5-year average oil price, and how our NAV reacts to that. A couple of points here. You can see our acquisitions that really pull us up. So year-end 2018, we've got Black Pearl coming in there. Year-end 2020, obviously, everyone suffered a bit there with COVID, but we still managed to maintain $1.1 billion worth of value there. A large debt number, but obviously, the sea change was between year-end 2021 and year-end 2022, where we brought in our Blackrod project. That's what's providing the future value for the company. That's where we turn to a net cash position from... You can see the debt turn to a net cash position, and that's really provided this very strong foundation for IPC to go forward into the future. Could do it in three slides, Will? Thank you. Sorry. No worries. Okay, so two more slides. Well done, everyone, and keeping things very efficient here. So wanted to share a history of value creation slide that touches on a few companies within the Lundin Group that have translated into significant shareholder value through time. So as you can see on the left-hand side of the chart, that's the original IPC symbol. So that's my grandfather, the founder of the Lundin Group over 50 years ago. He started that company in the 1980s, and the mandate at the time was to move quickly, rather than clunky majors, being able to make decisions, calculate, take calculated risks, and go into places where maybe people are scared to invest into. That company ended up merging with another company called Sands Petroleum to form Lundin Oil, and Lundin Oil was eventually sold for just under $500 million in 2001 to Talisman. So you can see that was about a 4.6x return. And then a new life was born, and Lundin Petroleum at the time was formed in 2001. They did one equity raise of $50 million, and then they went on to sell the company for cash and shares to Aker BP for an excess of $14 billion, and that represented greater than 175x return. Before that sale had taken place, IPC was reborn and spun out in 2017. We started the business, we were at 32 SEK per share. So you can see it's about a 3.5x return so far, and given the outlook of the business that's been shown by the team here today, there's plenty running room to go with material production growth coming in the not-too-distant horizon. So the concluding slide here to touch on, 2024 production guidance is 46,000-48,000 barrels of oil equivalent per day. The game-changing Blackrod Phase 1 development is gonna push our production up to 65,000 barrels of oil equivalent per day. That project adds 218 million barrels of 2P reserves, which has matured into our reserves last year. The point forward value, using a 10% discount, is just shy of $1 billion at $981 million. We've had the 2P value is greater than $3 billion, using a 10% discount, and the NAV per share is about 244 SEK per share. Our balance sheet is as strong as it's ever been. We have $517 million in cash resources available, and as Christophe pointed out, there's also CAD 180 million revolving credit facility in Canada that's completely undrawn. So when you include that into the total number, there's greater than $650 million in cash resources available to the company. We canceled out 7% of our shares last year. We're gonna try and do that again this year. We've done 5 accretive transactions over the last 7 years, and so don't count out the ability for IPC to find accretive acquisitions, given the health of the portfolio that exists at this point in time. And hand in hand with our growth ambitions, we have a strong sustainability framework on target to reduce our net emissions intensity come 2025, and we've extended that through to the end of 2028. So with that, that concludes the efficient CMD presentation, and happy to take questions from the audience. Yeah, we'll do audience first. So if someone wants to raise their hand? Yep. Great. Yeah. Thank you for the update. A few questions from me. First, on capital allocation. You have definitely been very clever to handle your balance sheet, and you've gone from a net debt position to now net cash, and you probably will use some of your balance sheet to invest in Blackrod. Just wonder, in the very long term, how should you think around the optimal capital structure for IPC? Should it be net cash, net debt, or zero net to net cash, net debt? And the second question on capital allocation is, will you ever pay cash dividends, or should we expect you to only buy back shares? Yeah, maybe you take the first one. I'll take the second. The second one. Second one, yeah. First. On the cash dividends, you know, you've seen the free cash flow that we expect to generate, you know, coming once Blackrod Phase 1 is online, is gonna be absolutely significant. And when you combine that with the shares outstanding being as low as it is today, and the ambition to keep canceling out those shares, you know, I think we're gonna have to see where we're standing in a few years' time to make that decision, whether, you know, we want to continue buying back shares if we're trading at such a discount, or, or click the dividend button. So, you know, no formal decisions made at this point in time. We're leaving ourselves flexible, but right now, the winning combination for shareholders that we believe in right now is investing for growth at the same time as reducing our share count. Yeah, on the, on, on the debt, I think, one of the pitfalls in our industry would be to hit the bottom of the cycle with too much debt on the balance sheet, so you... What you want to avoid, and you never know when the bottom of the market is gonna show up, but you don't want to get there with two or three times EBITDA kind of leverage. That's been the issue with some of our peers in the history. So we don't, we don't wanna, we don't wanna be there now. Some debt is pretty healthy, and what that can do, obviously, is accelerate once Blackrod is on stream, it can accelerate our ability to pay cash dividend, for instance. So I think debt, debt is healthy. The reason, obviously, I was a bit joking beforehand, the reason why we beefed up the capital structure in the way we did is because we wanted to be ready to be in a position to sanction and deliver Blackrod almost irrespectively of what oil price environment we would be in. So that that's why we're in a net cash position. I don't think the intention is to be in a net cash position forever. Okay, thank you. And two more from me while I have the microphone. I think we all can agree, and this has been a very positive story since the spin-off from Lundin Energy. So, where is the biggest risk associated with the business right now? And then finally, maybe a personal question to you, Will. You're a pretty young CEO. Where do you seek advice? Thank you, Teodor. I think for the biggest risk for the company, I mean, there's no denying it, we are gonna be spending a lot of money this year. It's a record investment year associated with the Blackrod project. We're gonna be deploying $362 million into that. By the end of 2024, we're gonna be, you know, roughly over 70% of the way there from a capital expenditure standpoint to first oil. So I think it all comes down to the execution. With Chris and the teams in Canada leading this project and having the experience in the past of doing big projects, not only from the teams in Black Pearl, but also the rising stars that came to join IPC and form IPC, and the big project experience that the teams have, it adds a level of comfort that we're gonna be able to get through this the right way and manage the project the right way. So I think that's largely de-risked, but I think, you know, that would be the main one to point out to as we're looking towards 2024 specifically. With respect to my age, in terms of mentors and who I look to talk to, of course, the board and family members. There's a lot of close individuals that I have within my life that I lean on for advice, and, you know, I try not to let my head get too big or have too big of an ego. You know, you gotta know what you know, and at the end of the day, it's, there's no I in team. It's a multi-person effort to lead a publicly traded oil and gas company, and it's been great being involved in this company for, you know, in excess of five years now, and being in the executive position for the last three-plus years. So with an organic succession, you know, nothing turns on the strategy, so we're quite excited for what the future has in store and super comfortable and excited in the new role. Just to add on it, this is not from me, it was from, from Lukas in his old days, and, he and Lundin would say the same thing. The biggest risk, he would, they would say, is not to own IPC stock. Thanks, Elliott. That's a good one. Hi there. Thanks. A couple of questions from my side, as you would probably expect, is if I remember correctly, we have or we have been shown that there's a contingency of roughly $100 million on the Blackrod project? Is that contingency still at $100 million or you used a bit of it up? We have used a little bit of the contingency up. We haven't spent it, but we have allocated it based on where we think as we've refined, defined, or matured some of the scopes of work. We have used up, but we're still sitting approximately $90 million in contingency. Okay. And then a couple of questions regarding the future strategy, and related to that, probably the portfolio. As Blackrod is becoming so big in Canada, obviously, is the name of the game, and Bertam acquisition, we welcomed. Very good. What about France? France is stable. We see the production there. We saw that you sold a couple of assets, non-producing and producing, tiny producing in Canada. Are you open for more divestments? We very much have an opportunistic approach to M&A. As you know, Lars, France has been a very stable producing asset within the portfolio for a long time. That was acquired by Lundin Energy. That was the first asset that they acquired, actually, in, I believe it was 2002. So with respect to growing the business, if we're able to do an acquisition in the operation in the jurisdictions where we have operations existing, it makes a ton of sense. At this time, you know, we're not looking to do acquisitions that are gonna really stress the balance sheet, so we're not looking to do anything too substantial in terms of anything $500 million, $400 million in excess of that. If we're able to get another acquisition done like we did in 2023 with Cor4 Oil Corp., we get immediate production, you know, oily weighted. That's what we're gonna be focused on. In Canada, of course, there's such a significant amount of resource in place there, so it's an attractive jurisdiction to be able to grow from, but we don't have a firm strategy that's set out that says we're only gonna be a pure play Canadian company going forward. We're very much opportunistic in that overall strategy and history of value creation. It's worked tremendously well for Lundin Group companies that we believe we can be able to create more value, and whether that's growing further in Canada or in the other jurisdictions of operations or elsewhere globally, we're gonna stay opportunistic. Thanks. Another one would be then on the gas side. Obviously, we see the market is pretty weak. The reserve auditors still have a dream. What about gas in general? Is because you're going to use up some gas as a natural hedge for obviously Onion Lake and then Blackrod. If you just can confirm how much of your production, of the current production would go into that, and so how much actually will be net long on gas? And the second question is, is it an opportunistic time? Because you have been pretty successful, opportunistic, doing acquisitions when others don't, and obviously, the prices are pretty low, I can imagine now for gas in Canada. So should we expect something on that side, or is it just referring to your prior sentence, you are going to be an oil company? It's a great question, and so from a gas consumption standpoint, we consume roughly in excess of 20 million scfs per day at our Onion Lake thermal asset, and Blackrod, when it's fully ramped up at peak production, we're talking about in excess of 40 million scfs per day in terms of overall, consumption. So the inflection point where we're actually consuming more gas than we're selling, it's gonna be around 2030. So we're vertically hedged up into that point. You know, later in 2023, last year, we were quite close to doing another acquisition that was similar to the size of Cor4, but it was 50/50 in terms of natural gas and, and liquids. So it is something from an opportunistic, countercyclical approach and a contrarian type of view. In a down market on the gas side, are there assets gonna be coming to sale that are gonna be at suppressed valuations? You know, it's something that we are intrigued in, but we're not. It's unlikely that we're gonna be a dominated gas company in terms of the production mix being in excess of 50% relative to the overall production mix where we're at today. Okay. If you don't mind, I have another one. Go for it. So, Mike, first of all, thanks for your presentation. First time I can see you in person. So I have a question on Malaysia. Obviously, the downtime was a bit more than I expected. What was mainly the reason for it, and what shall we see there in the future? Are you planning any serious downtimes this year? I don't... From what I just saw, I don't expect it. Can you a bit comment on that? Yeah. No, sure, and nice to meet you, Lars. No, it was two unique events we'd seen. So we've had two well pump failures. Historically, the Bertam field's been, you know, highly reliable, and we're still investigating the root cause, but they look like two distinctive events that we don't expect to be repeated. Okay, and what about this year, generally speaking? We saw in Christoph's presentation part that we see the third quarter is going up because of Onion Lake Thermal. Is there any more workovers which would have some downtime in the international business? So we always in our forecast, we hold provisions for workovers and downtime, but we don't expect a major workover is required, but we do hold costs, and we do hold some downtime provision in the production forecast also. Okay. Sorry, one last question, Chris, on Canada. How are things really going? You said we are on budget, obviously, we are on time. Can you give us a bit of, of probably a timetable point of view of what kind of announcement we should look throughout the year? What are the next critical steps throughout the year on Blackrod development? That's a great question. We're gonna continue to solidify some of our long-term contracts associated with egress of our dilbit coming out of the area. So you'll see some of those come out in 2024, and that kind of helps us lock in the whole marketing and sales price of it. They're progressing very well, and we have some solutions, but some of them aren't inked, and those are those long-term contracts. So I think that would be a key piece. An additional getting in some of our SAGD drilling behind us. So we've started drilling now on our first pad, Pad B North. We've started drilling. We're seeing great success. We're actually ahead of schedule there. So I think we'll see a progress update on where our SAGD drilling is, and the producing and injector wells are actually at. Those are probably two big things for 2024, Lars. Can I do one more? Sorry. Is it okay? So on the drilling in the Ellerslie play, can you evaluate a bit on... We saw the big jump up in production. What do you see as a type curve in Ellerslie? So it's also a great question. These do have steeper decline type wells, so our type curves are in about the, you know, 400 barrel a day well, kind of IP 30, IP 60, and then you do start to see some declines off. Thank you. Thanks. Hello. Thank you. Tom Erik Kristiansen. What would you need to see happening, your $650 million of liquidity now, to be comfortable enough to do and go with a special offer on the buyback side again as, as well? Kind of how far would you need to be in execution on Blackrod, or how high an oil price, or when, when could you think that that's an opportunity? It's a good question, Tom Erik. We don't have any firm particular target or timing or juncture or specific milestone in terms of when we're gonna do an SIB, and we, you know, haven't confirmed we're going to do an SIB. The beauty of doing Normal Course Issuer Bid s is that you can really dictate the pace and the amount of buybacks that you can do. You see, there is a limit to how many buybacks you can do on a daily basis. It's roughly 25% of the previous 20-day average. So, you know, I think we have to see how this year progresses with respect to the Blackrod spend and, you know, if we, if we ramp up the NCIB, we'll, we'll have to, you know, see where, see where we're at, but no firm commitments to doing an SIB at this time. Okay, thank you. And also just a follow-up on Blackrod. I think there has also been mention that there is a contingency in terms of the timeline there. Can you comment if, if any of that has been used yet? And any comments on the size of it, how early could this come on stream if it continues to progress on current schedule? So, yes, contingency does remain. Almost all of our contingency still does remain. Have not spent any of it, but again, we've allocated some of it where we've matured scopes of work that we expect to spend. There's still about $90 million left in our contingency bucket of the total $110 million, approximately, that we had. How quick could this production come on? Could things come on? There is some potential to outperform on the schedule, but at this time, we're for sure feel comfortable with our October 2026 first oil and getting steaming a few months before that. I think that should answer it. Okay, thank you. Last one for me. On M&A, you mentioned, of course, a bit on the company-specific side as well, that you would like to add more where you already have operations and capabilities, but is that also a reflection of... Do you still think Canada is the cheapest place to buy resources and reserves, or are other places now becoming more relevant as a lot of Canadian producers have better balance sheets and so on after a couple of good years for the industry? You know, we were able to take advantage of a relatively hot market in the middle of 2023 by selling some non-core core assets, mainly around the greater John Lake area, and I think believe that was shared alongside our Q3 results. We fetched a premium in excess of 220% relative to the NAV 2P for that particular asset that was sold. So that, what it demonstrates is that we're not particularly wedded to certain assets, and if an expression of interest comes in and that offer is in excess of what we believe we can create the value of an asset out of, then we will entertain that. With respect to growing through further acquisitions in Canada, we don't have anything live at this point in time that we can see. You know, I think what's a common, common theme with IPC is we're not the highest bidder that go into these processes, but we are a very legitimate funder for these processes. So having the cash resources available puts us in a strong position where we can try and close a deal quickly. Okay, thank you. Thank you. Pål Dahl, credit analyst at SpareBank 1 Markets. Are there any dynamics in Canada that we should keep in mind analyzing your company? You mentioned the Trans Mountain Pipeline, but then again, you have hedged a lot of the WCS, WTI differential. ... That's right. As Christophe noted, about 70% of our WTI to WCS discount is hedged at $15 a barrel. So the Trans Mountain Pipeline, I mean, there's, it seems like there's new headlines coming out every single week here. And typically, it's something about a little bit more delay, a little bit more delay, but there's been a ton of capital put into this pipeline by the federal government. So, you know, it is gonna be on stream, and I do think it's gonna come in before the first half of the year. But that is the single largest driver, I think, in terms of a catalyst for tightening differentials. It's gonna put the Western Canadian Sedimentary Basin in a position where there's ample export capacity relative to the production, which we haven't seen before, and that's what's really driving consensus to tighter differentials going forward. And I also think on the gas side, we can't forget about the LNG BC project that's taking place. It's expected to come online in 2025, I think, in the second half, and so that is expected to also drive gas prices up and, you know, its potential for a convergence between North American gas benchmark pricing and international gas prices. Great. Thanks. Børge Bakke from Fearnley. Thanks for taking my question. A question regarding hedges. You said that you were considering or had considered to up your hedges. How should we think your hedges going into 2028, 2025? Is this one of your only to the large CapEx in 2024, or how should we think about it? Thank you. Yeah, I think in terms of hedging the benchmarks or Brent or WTI versus the differential, what drives our decision-making is really how much money we need to spend, either on CapEx or whether we have major debt maturities. So clearly 2024 qualifies for a big CapEx year. So in that context, that's how we – that's why we started to unhedged 25% of WTI WCS exposure. If the market was to go back to that level, I think it's fair to assume we would consider... I'm not saying we'd do it for sure, but we would certainly consider adding some WTI hedges around $80 this year. And, depending on what the forward curve looks like next year, we might consider doing a bit as well. It all depends on how much CapEx we're actually going to spend this year and how much we will have to spend in 2025. But, if you look back, we hedged the differential in the past, so it's a fair assumption to assume that we might do it again. And the benchmark will depend on the shape of the forward. Thank you. Thank you. Yeah. It feels like there's a trade-off when you're evaluating assets between decline rates and cash operating costs. I'd be curious, when you're evaluating acquisitions, how you think about that? I think the main thing that we are looking at when we're looking at acquisitions is the free cash flow nature of the assets, and that's a big driver, especially right now, while we're so long-dated in terms of resource that we have in place. You know, we're gonna wanna see that if we're able to purchase an asset or do an acquisition or a company acquisition, that it's an accretive one from a five-year free cash flow perspective. That's one of the common metrics that we use as a tool to say, "If we buy this asset, are we gonna make more free cash flow for the next five years, or are we gonna make less?" And, you know, if it makes less, then typically unlikely for us to go any further. Yeah. But is it a consideration to try and get some oil with very, very low cash costs just in the eventuality of a very low oil price to have sort of cash coming in? You know, and that's... It's a good question, and the beauty about having a diversified portfolio and Brent-related mix as well is that, you know, that higher pricing that you can realize helps when oil prices crash, and we saw that through 2020. We really benefited from having a diversified portfolio. But in terms of in a perfect world, if we're able to get a 100% oily asset with super low operating costs, you know, that would be great to do that. But also, another key metric that we're looking at when we're doing acquisitions is: Is it cheaper to buy back our stock versus this acquisition? So it's really got to be accretive, which, you know, can be challenging with those type of assets that are, you know, 100% oily and very, very low operating costs that typically try and fetch a premium. Okay. Thank you. Yeah, me again. Just strategically, probably a bit early still, but so let's say Blackrod coming on in end of October and then full ramp up, 2026, and then full ramp up. There's so many, so much in contingent resources, and we see that you have the rights to do up to 80,000. Can you just give me a bit of feeling of another block would be another 30,000, or - and what kind of costs, because obviously a lot of costs are coming with the first phase, would be a next 30,000 barrel block of developing than with this huge free cash flow coming in? Would that be significantly cheaper, or how would it evolve? And what is strategically to realize the value of the massive contingent resources? Good question. So there definitely is some cost savings with an additional phase. All the, the engineering, all the design will be a mirrored approach. So it is a, a different location, but it is a mirrored approach, so we have some schedule advantage around that. And of course, any learnings that we're gonna get out of this one on the shop fabrication that we did. So there is an advantage on a CapEx per flowing barrel to get the second 30 on, and we do think it is a kind of a 30 is a great economy, a scale of going 30, 30, and probably another 30. We could expand with the, the reserve life index there to, to do further stages. 80 is our current regulatory approval, so we'd have to get that amended. But there, so there is a cost advantage to Phase 2, for sure, and also a schedule advantage. Exactly that amount of dollars, I, I don't know off the top, top of my head, but we definitely do see some efficiencies because we are using. The road, for example, is a quick one. You know, there's over $30 million into road infrastructure that never have to build again, and we've upgraded as such. So something like that is really quickly. All the egress pipelines are all set up and planned and done to be able to house the Phase 2. And we ship more, but, you know, we don't, we don't pay more on a per barrel basis. So yet, there's definitely some advantages. Hope that helps a bit. Further to that as well, if you were to invest in the Phase 2 expansion, you would reduce your post-royalty payout time. So, you know, you'd ultimately effectively fund 40% of that development by pushing your post-royalty payout from phase 1 because it's all ring-fenced within the same asset. So that's another benefit that you get from doing a Phase 2 expansion and some works that are definitely ongoing in the background as we look to mature that concept. But that does not, Christophe, taking what just Will said, but that does mean that acquisitions strategically getting more and more difficult because you're trading significantly below NAV, getting cheaper and cheaper, your stock, on a relative basis. And the contingent resources are relatively to develop, so cheap, so cheap, that it wouldn't make any serious sense to do any, any realistically, any more acquisitions, right? In a second phase, to call it in five years' time, notwithstanding a short-term acquisition like you did with Cor4. Yeah, you know what? We're of the firm belief that once we get closer to first oil coming online, I think the market's gonna wake up a little bit, and, you know, hopefully, we're gonna be trading at the premium that we deserve to be given the proven track record, the quality of asset acquisitions that we're able to do, and so we hope that we can get there. However, when we're looking at growing the business, whether it be organically or through M&A or even through shareholder returns, we're always measuring in terms of, you know, what is gonna give us the best bang for our buck. So I think that's quite an insightful comment on your behalf, that, you know, if we're looking to acquire something, it's got to be benchmarked against, well, what about Phase 2 at Blackrod, or what about doing a really big buyback or something to that extent? Especially, you know the subsurface very well, right? The risk of subsurface isn't there anymore. Correct. Versus an acquisition. Yeah. Yeah. Thanks. But I guess I would also add to that as well, that if we're looking at acquisitions, we're focused on producing assets, so subsurface should be de-risked, depending on what we're looking at, hopefully. Teodor Sveen-Nilsen from SpareBank 1 Markets again. Just more on Blackrod. You currently have a very high ownership. What do we need to see for you considering a farm down, and is that on the agenda at all before first oil? No, that's not on the agenda. I mean, I think we, we found our partner in 2022, and we made $430 million in free cash flow. And, you know, before that period in time, we were contemplating getting a partner in to help fund this project. As well as we were thinking about going 20,000 barrels of oil per day. And, you know, fortunately, through the big cash generation that we had had, we said, "You know, let's keep the pie for ourselves. We're gonna take this 100%. We're gonna upsize this to 30,000 barrels of oil per day." And, you know, my late father, before he had passed on, when he had told me about Blackrod, he was always mesmerized by the asset, and he always wanted us to, "Go for it, go for it." He said, "Don't, don't sell anything of that. Keep it 100%." Now, if an offer were to come in, that was in excess of the value that we believe the asset is worth, perhaps we would entertain that. But, you know, I think that's quite unlikely, given that it's not in production yet. So, it's very likely that we're gonna be retaining 100% ownership of this asset. Maybe one comment in. We obviously work for you, shareholders, and the S-curve in terms of value creation on Blackrod is very, very steep. Because with $850 million of CapEx and with the unwinding effect of the discount rate, when you look at the value of Blackrod between 2023 and 2026, it more than doubles, almost triple, right? So doing anything, losing some of the working interest in that asset, having to deal with a partner while you're creating all that value- ... As Will says, it really would need to come with a premium to the way we look at the value of this asset. Understood. That's clear. And then a totally separate question on the gas market. You talked about the potential of the regional gas price in North America will be closer to European gas prices. I view that at that, definitely share. But are you in a position to quantify or give some scenarios of how much you think that that gas price in Canada may improve just because of increased LNG export capacity from North America, and of course, obviously, strong gas demand in Europe? So the forward curve for AECO gas prices right now for just 2024 are relatively in line with our, what our budget states, which is about $2.13 per Mcf. So we're, we're assuming $2.25 through Q1 and Q4, and $2 in the summer. And I believe once you're starting to get into the back end of 2025, that almost doubles, maybe not quite fully there, but it gets quite a lot higher. So just looking on the forward strip is our main benchmark in terms of where we see the gas prices, and personally, don't have a view beyond that. Okay, thanks. Martin Mauseth from ABG. You have touched upon your share trading at a big discount to the net asset values. So I was wondering, as a management, what is the, like, important steps you can take to reduce that discount? Deliverability, predictability, and reliability. As we come in quarter after quarter, year after year, and delivering the results, you know, that should ideally compress the discount. I think the cash flow, the valuation, there's a wide array of attractive attributes within this company, and so I just believe in continued delivery of our plans, it should compress the discount. And I do believe, and we've seen it with an Edvard Grieg or a Johan Sverdrup, or even if we look in the mining world, the Fruta del Norte and the Lundin Gold asset. Once these big projects come on stream, you do typically get an exponential rise in your share price. And it's not just a one-day blip, it's a steady rise up until that point in time. If you're able to form a long-term view, this is the, this is the company you want to be looking into for multi returns. Yeah, I agree. And what is the biggest risk you see at Blackrod that could potentially delay the first oil date? Overall execution, of course, is the largest risk. But again, we've mitigated all those critical paths. So I guess some of the third-party pipelines that are coming in because they're out of our control to do, but we're well ahead in schedule, those would be something that we're not controlling. So I guess we consider it a risk and a critical path, but we've mitigated it by starting everything, a full build season, and leaving one full build season ahead of us if we had to, if things slipped. So it's some third-party pipelines, and then and just a clean execution of the project. Okay. Thank you. Thanks. One question. Onion Lake, I think you'd thought for some time about increasing the capacity from 14,000 to 16,000 in terms of processing. Seems like you're putting that on hold. Just, just interested in the thinking there. Great question. We do leave an expansion at Onion Lake as part of our portfolio of opportunities to work on. But right now, when we do look at free cash in that 3-5-year window, we are better off to delay it, push it, push it out, and just kinda look at it each year and decide when we should get at it and put it in the budget or not. So it's based on a free cash flow basis. Anybody want to add to that? No, it's maybe important, you and you mentioned it, the drilling on the Pad L h as been very successful. So we're in a situation where effectively the production capacity is slightly above the nameplate capacity of the facility. So, no, that's a very good question, Nick, and it's pushed to the right. It's not a 24 matter in any case. Okay. And then just the fields that you grouped together and report as Southern Canada, can you say what the remaining 2P reserves are for those fields? And what sort of decline rate, if you don't keep drilling there? Do you want me to...? Do you know what those numbers are exactly? No, no, not Suffield. I think I... He's referring to Ferguson, Mooney, and Primary. He's Ferguson, Mooney, and Primary. A and Suffield Oil. Suffield. Suffield oil. Okay. So you have that one lifesaver chart. I think those are in- Isn't that in the... Sorry. Here's. It's a bit of a different grouping, Nick. Can we get back to you on that? Yeah, sure. Thanks. Sure. Okay, so we've just got a couple of questions from the internet. We did actually have a large number of questions from the internet, but they've pretty much been asked by the audience. So just, perhaps, Christophe, could you, could you comment on this? Can you please elaborate why your scenarios on future cash generation are based on a Brent price range of $75-$95? What gives management the confidence that the lower bound is seventy-five, and why do we use those two bounds? As you know, last year our range was $70-$85-$100. We believed 85 was a bit too much. We didn't want to answer the question, "Why do you pick $85 when the market is slightly below?" Going below $70, it's always hard to read into the Saudi Arabia crystal ball, but it very much seems to us that there's a form of a floor from OPEC+ and from Saudi Arabia in particular. It's hard to say whether this floor is $60, $65, or $70. At least in the short term, for 2024, we believe it's reasonable to assume 70 is a form of a floor for the coming three and a half quarter. Yep. Thanks, Christophe. I think one other thing that giving you a range gives you is, you know, we're relatively linear when it comes to free cash flow generation at different price decks. So it gives you two bounds that you can use to then forecast whichever price you're interested in looking at. Just one more question, really, on carbon capture, Will. Can you talk about a view on, on additional subsidies that oil and gas needs or expects from government in order to go ahead with some of these carbon capture projects? And what would make sense for us as a company? Yeah, it's a good question and something that we definitely looked at upon the sanction case for Blackrod in terms of putting carbon capture and storage there, and it was deemed uneconomic, given the existing fiscal incentives that are in place in Canada. So ultimately, where we stand, it's not quite there. So we are doing a number of operational emission reduction projects across the portfolio and as well on Blackrod specifically. We have future-proofed area on the plot plan to be able to install that technology if the fiscal incentives improve. But we're not stopping there. What we've also put in the budget for 2024 is we're gonna spend about $1 million doing a comprehensive CCS study. This is mainly gonna be at our Onion Lake Thermal facility. So, you know, we are progressing our understanding of it and how we're gonna deploy that technology, but we do wanna see some fiscal incentives improve beyond what's currently structured. Okay. Thanks, Will. Chris, perhaps you could just answer, or Mike, perhaps, the investment in Blackrod by the end of 2024 will be around $600 million. Interested in understanding how the remaining capital expenditure is split between the future years. Sure. Yes, we're approximately $600 million into an $850 million spend by the end of 2024. The remaining work that is done in 2025 is a lot to do with our drilling scope of work, that has to do, and the final tying in of the electrical and instrumentation portion of the facility. It really spreads over the last $240 million. Thanks, Chris. Just one for you here, Mike. What can we expect in terms of Malaysia production now those two wells are on and producing well for 2024? We're seeing spot rates, as I mentioned, up at 4,500 barrels a day. We expect a low decline through 2024. Very good. And then one other question, Will: How do you like your job as CEO so far? It actually was a question that appeared here. Couldn't be happier. It's an amazing job, and it's a collection of a really, really strong team, and I'm, you know, fortunate to have made a really good relationship with a lot of these people in the company, given I've worked in it for, you know, almost six years, I believe now. So it's been a lot of fun. You know, we're all pulling and we're unified, pulling in the same direction. So I think the sky's the limit in terms of what we can achieve and, you know, excited for the years ahead. Couldn't be happier. Thank you very much. I think we'll, we'll close out there with all the questions. Thanks, everyone, for your participation in CMD, and we'll finish there. Thanks very much. Yeah, I appreciate the attendance, everyone, and listening in to the IPC CMD. So that concludes everything here, and look forward to having further engagements following this event here in London. So thank you.