Okay, so welcome everybody to International Petroleum Corporation's Capital Markets Day presentation. I'm William Lundin, the President and CEO, and I'm accompanied today by all officers within IPC. And so on the agenda today, we have a wholesome package set out in front of us. I'll begin with the overall introduction and big picture overview for the company. Followed by that, our COO, Nicki Duncan, will expand on the operational detail at the group level, as well as at the asset level. Then Christophe will touch on the financial details as it relates to our 2025 budget outlook, followed by Rebecca Gordon, who will go into more detail on our year-end 2024 reserves valuation. Following that, I'll have some concluding remarks, and then we'll open up the floor to Q&A, where I'll ask some of my Canadian colleagues to join us to assist in those questions. Without further ado, to touch on the 2024 highlights for the company, it was a great year, a milestone year, record investment, capital and decommissioning expenditure settled in at $442 million. $351 million of that was spent on our transformational growth project, the Blackrod Phase 1 development, and very pleased to share that that project is very much on schedule and on budget as things stand. Production for the year was 47,400 barrels of oil equivalent per day. It was right in line with our Capital Markets Day guidance that we had set out at the beginning of last year, between 46,000 to 48,000 barrels of oil equivalent per day. Q4 production was the same number at 47.4. Good cost control still exists within IPC, of course. We had operating expenditure per unit production average for the year at $17 per BOE, which was in line with our latest guidance, and Q4 OpEx costs were $18.20 per BOE. Strong cash flow for the company was generated in 2024. We delivered $342 million in operating cash flow, and when we take into account the growth CapEx and all CapEx that was spent by the company in 2024, our free cash flow number was minus $135 million for the year, so right in line within our expectation, and if we are to remove the growth CapEx that the company spent on the Blackrod Phase 1 development, our free cash flow was $216 million, highlighting the strong cash flow generative ability of our producing assets. Our balance sheet stands in healthy shape still. We're at $209 million in net debt. We have gross cash resources available of $247 million, and we also have an undrawn RCF in Canada to the tune of around CAD 180 million, so ample liquidity access for the company to continue pursuing its strategic objectives. Strong sustainability focus within the company. Very pleased to share there were no material HSE incidents that took place in 2024, and we're well on track to achieve our net emissions intensity reduction target. Share repurchases, so we returned around $102 million in value to our shareholders in 2024 in the form of share buybacks. And so we completed our 2023, 2024 NCIB program, where we could buy 8.3 million shares, and we have renewed the next program, which is the 2024, 2025 NCIB program, and we're making great progress on that buyback program as things stand. So I think it's important to highlight the growth that the company's achieved over the last eight years since we launched IPC at the beginning of 2017. At that point in time, there was 113.5 million shares outstanding, and at our current point in time in 2025, as at the end of January, we have 117.7 million shares, so really a marginal difference overall staff. So inclusive of employees and contractors, we had 220 people in the company when we started life, and we've seen a 2x in excess of that increase. Now we have over 500 people, employees and contractors within the company, and that growth is largely coming from Canada, of course. Production, we have a 4.5 times increase on our overall production. We were 10,000 barrels per day when we started in 2017, and our guidance for 2025 is 43,000 to 45,000 BOEs per day. 2P reserves started life with less than 30 million 2P Reserves, a 17 times increase as at year-end 2024, so we now have 493 million barrels of 2P Reserves, which is a record amount for the company. Reserves Life Index, when we were producing 10,000 barrels per day, we had 29 million 2P Reserves. That meant that within eight years, we would deplete that reserve base. We've increased that amount four times now, where we have a Reserve Life Index of 31 years. Big increase in value, starting life around $500 million and a 6x increase to this point in time, where now our Net Asset Value is around $3.1 billion overall. Major increase in Contingent Resources, of course, too, where we had none when we started the company, and we've added in excess of a billion barrels to the company. This slide here, the 2P reserves growth, is one that we'd love to show, of course, because it's been a significant amount of growth in a relatively short period of time. But what I'd like to draw everyone's eyes to is the red shaded elements within this waterfall or reserves chart, which is the reserve replacement ratio. So notwithstanding 2020 and the Black Swan events that took place with COVID and the oil price war between Saudi Arabia and Russia, we've had material reserves replacement every year within the company, and that's really been achieved through accretive acquisitions that we've done, but that's been further supplemented as well as a result of the base business investment that has been undertaken by the company. So 500 million barrels nearly of 2P reserves now. We only had 29 million 2P reserves when we started, and if you look at the light blue wedge on the graph there, we've produced more than four times our original 2P reserves position, so an impressive amount of growth in a short period of time. Growth per share, this is really our core focus here, is maximizing the value of the company for all our stakeholders, and we see that by maximizing the value per share, and so when we're reducing our share in combination with growing our reserves, production, and cash flow, we feel that this is a key differentiator within the company, and so again, when we started in 2017, we had 113.5 million shares outstanding. Looking at the reserves per share represented just shy of 0.3 reserves per share. It's been a 14x increase to just in excess of 3.7 reserves per share as things stood at 2024. Looking at the production per share growth, that's in excess of 4x over that period, and operating cash flow per share as well has increased more than two times. So we're confident and excited as these metrics continue to appreciate through time that that should also translate in share price appreciation. So the 2025 through 2029 business plan that the company sees is average production of 57,000 barrels of oil equivalent per day, and in between $75 to $95 Brent, we expect to generate in excess of $1.2 billion to in excess of $2 billion in free cash flow generation, which of course, less all the costs associated with our growth projects in the company. And so that doesn't have any assumptions contained within it regarding contingent resource maturation or future M&A capability. And so when we look at that free cash flow generation that the company's going to achieve in the future years, we have three key strategic pillars as it relates to capital allocation, starting with organic growth. And so of course, we have material production growth coming from our Blackrod Phase 1 development, which is expected to come on stream in the back end of 2026. What I really wanted to emphasize here and continue emphasizing is the production per share metrics. So the company made a deliberate decision here to sanction the Blackrod Phase 1 project. We've also been persistent in buying back our shares. So as a result of that, there's been a marginal modest base production decline, but through our Blackrod buildout period, despite less capital being deployed towards our producing assets, the actual production per share metric has remained flat through the development. And so if all's we do is finish this program that we're on track to complete, as things stand right now, we're going to have material production per share increase and of course, natural production increase, where we expect to increase our overall production in aggregate by 50% come 2028 relative to 2025. So the Blackrod asset, there's been a lot of good work has been delivered throughout the year, and Nicki's going to expand on that in his section, as well as what I'm about to say here, which is, of course, is 1.3 billion barrels of recoverable resource at this asset. We've had an increase in our 2P reserves at the Blackrod Phase 1 development. It's moved from 218 to 259 million barrels of 2P reserves for the Phase 1 development. This field, it's a big one. Our capital expenditure is $850 million from when we sanctioned this project in the beginning of 2023 to when we expect first oil in late 2026. We're well on track to deliver within that overall guidance on our costs as well as the timeline. We have one of the best world-class, I would say, SAGD teams in-house within the company, not only from an operational perspective, but also from a development perspective. With that, it gives us a lot of confidence in being able to deliver this project as we've set out with a lot of historical data and knowledge on the Blackrod asset specifically. There's been over 10 years of production data gathered through our pilot operations, and we have regulatory approval here for an 80,000 barrels per day development. Phase 1, of course, targets 30,000 barrels per day, so it's a phased approach overall here. The Phase 1 project net present value using a 10% discount rate now stands at $1.4 billion based on the reserve auditor price deck, which Rebecca will get into detail how that looks in her section of the presentation. The break-even point forward from 1/1/2025 is around $50 WTI now. Big fields get bigger. This is a new slide that we've inserted here, and I think it's a really important thing to demonstrate through the Lundin Group track record in terms of major discoveries of fields when they go into sanctioning to a commercial development and what happens through time typically when you have good assets and great people managing those assets. In Lundin Energy, as you can see, Alvheim and Edvard Grieg, these are multi-hundred barrel reserve fields when they were sanctioned at their time of PDO. If you fast forward to year-end 2021, which was of course right before we sold Lundin Energy to Aker BP for cash and shares, there was a massive increase in the ultimate recovery when you take into account the cumulative production from both of those fields and their point forward reserves at year-end 2021. The same thing can be said for Johan Sverdrup, of course, which has seen a material increase in its initial sanctioned 2P reserves relative to its EUR at year-end 2021. Or, to take a look at an asset that we have within the IPC portfolio from Black Pearl Resources, of course, Onion Lake Thermal, this field when it was originally sanctioned to go for commercial development had a 2P reserves volume of 90 million barrels in 2P reserves at year-end 2013. Where we're at today at year-end 2024, we see a 70% increase relative to its EUR versus where it was when it started and where it was sanctioned. So a major increase overall there. Blackrod, we have yet to even produce a single barrel from this asset. It was of course 218 million barrels for the Phase 1 development when we sanctioned this project at year-end 2022. Now at year-end 2024, 2P reserves is 259 million barrels, so represents nearly a 20% increase. So we very much believe big fields get bigger through time. Here are the results to speak to that as well, and we believe that Blackrod is going to have future growth in the years ahead as well. Where's the growth going to be coming for that? It's going to be coming from our continued contingent resource maturation. So this is one of the plots that it's actually okay to see a declining number from one bar to the next here. As at year-end 2023, we matured some contingent resources, as I had touched on, into 2P reserves, mainly from the Blackrod asset. There was also some reserve replacement achieved at the France and Malaysian assets, which Nicki will expand on in his section of the presentation. So as things stand, as at year-end 2024, we have 1.107 billion barrels of contingent resources, which not a single dollar of value is assigned to in any of the corporate cash flow numbers or the net asset value numbers that we share. And over a billion barrels of recoverable resource still lies at the Blackrod asset. We move on to our second key capital allocation pillar, which is stakeholder returns. So just under 72 million shares has been repurchased since inception from the company at an average price of 74 SEK per share or just under 10 CAD per share. And if you look at our current share price as of the close of play yesterday, that represents around $490 million in value that's been created in terms of buying back our shares in aggregate at a much cheaper price relative to where we stand today. And so we completed the NCIB program last year, as I had touched on, and we've also renewed the next NCIB, the 2024-2025 normal course issuer bid program. And as you can see, we've made great progress there. And our intention is to complete that program given that we traded a significant discount relative to our underlying intrinsic value. And that's really provided our balance sheet stays in good shape. So we have increased our net debt to an EBITDA leverage ratio to accommodate this to 1.75 times, which is in line with our distribution covenant that we have within our bonds. To draw your eyes to the shares outstanding at the end of January, 4% dilution, that's all that's happened. You look at the metrics in terms of the enhancements to the business to where things stand today, four and a half times on production, 17X on 2P reserves. We've added more than 23 years into our reserve life index. Of course, major contingent resource growth and net asset value growth. Our EV stands at $1.765 billion when you add in the net debt on top of our market cap. Over the next five years, we expect to generate between $1.2 to 2 billion in free cash flow between $75 and $95 Brent. In the 10-year horizon, the cumulative free cash flow that we anticipate the business to throw off based on our 2P reserves is between $2.8 to 4.6 billion in free cash flow, which represents 1.6 to 2.6 times our current enterprise value. So moving on to our third key strategic pillar, this really highlights these acquisitions or the five accretive acquisitions that the company has executed since being formed in 2017. The first major acquisition that the company executed was the Suffield asset acquisition from Cenovus. Following that, in the same year, at the end of December, we did the all-stock transaction with Black Pearl Resources. All of the deals that were done that are shown on the slide, these were funded by cash on hand as well as through debt, with the exception of the Black Pearl transaction where we issued shares. The Granite, [Cherry Valley], as well as Cor4 were three subsequent acquisitions that we did after the Black Pearl acquisition. So a lot of accretive deals, and we definitely remain opportunistic to growing the business through M&A. And when we look at the total consideration of what we paid and we essentially add all of the consideration costs from that prior slide, it represents around $940 million of money spent to acquire these high-quality assets and companies. And as at the end of 2024, excluding the growth CapEx associated with the Phase 1 development at Blackrod, they've generated $1.06 billion in free cash flow. And the point forward value of these acquisitions is in excess of $2.7 billion. So very timely acquisitions and a lot of value has been created through the accretive M&A. 2P NAV, again, we were $500 million at the beginning of 2017. Our 2P net asset value using a 10% discount rate now is $3 billion in excess of that $3.083 billion. That equates to a fair share price of around 37 CAD per share or 287 SEK per share. I'd like to keep it simple. This is why our shareholder returns are geared towards doing buybacks as we trade at a material discount at around 50% relative to our underlying 2P net asset value. Creating stakeholder value, I touched on the five-year cumulative free cash flow where we expect to generate in excess of $1.2 to an excess of $2 billion over the next five years. That represents a cumulative free cash flow yield of 77% or 128% during that period. If we look forward to our production from 2030 to 2034, we foresee average production rates of 63,000 barrels of oil equivalent per day. We'll still have an excess of 75% of our 2P reserves before getting into that five-year window. That's where we expect to generate between $1.6 and $2.6 billion in free cash flow between $75 to $95 Brent, representing a 21% to 33% free cash flow yield per annum from 2030 to 2034. Power of the growth of the buybacks, so this is really a theoretical mathematical exercise here. And if we were to look at the point forward value per share as at 1/1/2030, which is after the five-year period, and we use that free cash flow, the five-year free cash flow of $1.2 to 2 billion to buy back our shares, assuming 145 SEK per share buyback price at the $75 level and 215 SEK per share price for buying back our shares, the point forward value of the company will be in excess of 760 SEK per share at the $75 case. And there will actually be 15 SEK per share worth of cash being returned. This assumes no insiders sell their shares during this period. So we'll effectively go private through this exercise. And similarly, at $95, the fair value would grow to 1,240 SEK per share. And there would be 110 SEK per share of cash to be returned to the shareholders. Final slide within my section. This is sustainability highlights, so super pleased to share again, no material safety incidents happened in 2024, and we actually achieved a 35% reduction in our total recordable incident rate, which is something that's definitely worth noting given that we had increased man hours and work carried out through 2024, largely due to the development activities that took place at the Blackrod asset, and the climate action, we're well on track to progressively achieve our net emissions intensity reduction. We're targeting 20 kilograms per BOE, which represents a 50% reduction relative to our 2019 Scope 1 net emissions intensity, and so we expect to get to that target by the end of 2025, and we intend to maintain that level through to the end of 2028. Of course, in the community engagement front, we're really pleased that where our operations are situated across the world, largely all local staff members are running our region's regional businesses, not only in the field, but also at the local office level. I think it's definitely key to note here with this Blackrod Phase 1 development project that's underway, that is creating a huge amount of jobs growth in Alberta and elsewhere where we have vendors providing different kits and equipment from other places in the world. Really a major net positive impact to society by going through with this transformational growth project. With that, I'll hand it over to Nicki to go through the operational section of the presentation. Thank you. Thank you. Well, and good afternoon. It's my pleasure to take you through our 2025 outlook and on through some of the asset operational details. So just kicking off with our track record of reserves growth. And as Will mentioned earlier in the presentation, year-end 2024 has been another excellent year for reserves replacement at IPC. At Blackrod, we've matured three additional well pads into our reserves. And in Malaysia, where we've completed our next phase of field development studies, we've matured the infill well A21 into reserves. And also, it's going to be part of the 2025 work plan and budget. That's something I'll touch on a little later in the presentation. In France, beyond the acquisition of the Fontaine-au-Bron field, Fontaine-au-Bron sits north of Villeperdue in France, a highly underdeveloped part of the field. We believe we've matured three sidetrack wells into reserves in preparation for the development there. It's not currently included in the 2025 budget. We're still finalizing the plan. And I'll touch a little bit more on that in the section for France. Really, the message here, though, is organic growth. Reserves growth is in our DNA. Notwithstanding the significant resource we've matured into 2P reserves at Blackrod, since inception at IPC, we've seen 33 million barrels of oil equivalent organic reserves growth. So just moving on to our 2025 investment strategy. And it's no surprise, again, our investment is dominated by the final major spend year at the Blackrod Phase 1 development. Elsewhere, we plan infill well drilling at Onion Lake Thermal in Canada. And also, like I mentioned, we're drilling the next infill well target at Bertam in Malaysia. Beyond that, we continue to mature all of the potential opportunities with our portfolio. If the opportunity arises, we'll be ready then to lift our activity levels, and as always, we retain an opportunistic approach to M&A. Production operations, so I don't want to be too repetitive here. Happy to announce our 2025 production guidance of 43,000 to 45,000 barrels of oil equivalent per day, particularly on the back of the fact that our development investment is dominated by the greenfield Blackrod Phase 1. As always, our production guidance includes provisions for unplanned and planned downtime. We do have a major shutdown at Bertam in Malaysia in the second half of 2025. The only other thing I'd like to mention here is our operating costs remain stable, and our 2025 operating guidance is $18 to $19 per barrel of oil equivalent. I could get a little bit repetitive with this one. Our spend is obviously dominated by the final major spend year at Blackrod Phase 1. Infill well drilling at Onion Lake Thermal, I'll touch on in the Onion Lake Thermal asset slide. And as I mentioned, there's an infill well to be drilled in Malaysia. We also have a well workover in the field to complete at the time we're doing the infill well drilling there. And in France, as I mentioned, on the back of the acquisition of the Fontaine-au-Bron field at the north of Villeperdue, we continue to mature up the three sidetrack well targets there. And beyond that, on the back of the successful Villeperdue Phase 1 development, we're working on our targets for Villeperdue West Phase 2. Okay, before I move on to the asset level detail, I'll just quickly run through our five-year plus five-year outlook. As Will mentioned, we're very strongly positioned for long-term growth. Our average production in the next five years is 57,000 barrels of oil equivalent per day, growing to 63,000 barrels of oil equivalent per day in the following five years, and that's on the back of the ramp-up of our Blackrod Phase 1 development and expansion activity at our Onion Lake Thermal asset in Canada. At that time, over the full period, our sustaining capital is stable at $5 per barrel of oil equivalent, with an incremental $3 per barrel of oil equivalent in the first five years as we complete that Blackrod Phase 1 development and we complete the expansion work in Onion Lake Thermal, like I mentioned earlier. Okay, so just moving on to our asset overview, and kicking off with the Blackrod Phase 1 development. the headline is very happy to report the project's progression in line with schedule and budget. Critical engineering and road access upgrades have progressed to the point that it's allowed us to progress the facility fabrication and major equipment site delivery on track, which then allows you to progress the field construction. And on the next slide, I'll really show you what that looks like at the site itself. Drilling's going well. It remains ahead of schedule. And we've seen some positive results. It's something that I'll touch on a little bit further in the presentation. And just to mention, our third-party pipeline installation's ongoing and it's on track. So they say a picture paints a thousand words. This is a very recent picture from our Blackrod site. Unfortunately, I don't have a point or I would point out some of the major equipment, but I'll try and describe to you the equipment that has been installed so far or we're continuing to install just now. So if you look around the perimeter of the central processing facility site, you see the pipe racks. All of our pipe racks have been installed. At the far end of the picture there, you've got our sales tanks and the oil conditioning for sales pretty much completely installed. You've got our four steam boilers and two cogeneration units in the middle of the plant. And down nearer to me, the two large towers that are pointing up the way. That's our evaporation towers and some of our steam water regeneration equipment, which is ongoing installation. So I mentioned the drilling results. And we've seen consistent positive drilling results at Blackrod. It's no major surprise to us given the extensive appraisal data we have, but it's always good when those results come in and they're at least in line with expectations. Just a very quick reminder here. Blackrod's homogeneous sand, very little barriers. It's a very clean play. And the last two bullets here are just to say that our well targets or locations have been landed on target. So moving on to the Blackrod Phase 1 schedule. And very exciting that we're transitioning now from engineering and fabrication into really heavy construction and commissioning in the field. And the only other key point on here for me is we remain on track for first steam in Q1 2026 and first oil later that year. And the resource and value at Blackrod goes way beyond Phase 1. I think the best way for us to demonstrate this to you is actually this map on the side here. Well, thank you, Rebecca. And very happy to report that at year-end 2024, as Will mentioned earlier, we matured four additional well pads into our 2P reserves at a very low appraisal cost. Now, this reserves maturation process is very, very important as it provides the foundations for future growth or value growth and the next phases at Blackrod. Okay, so moving on to our producing assets in Canada and starting off with Onion Lake Thermal. Stable production from Onion Lake Thermal in 2024 as we continue to ramp up production sustaining pad L. Seven out of eight drilled wells are now online. As part of the 2025 budget, we do actually plan to drill the final and ninth well pair on pad L alongside four infill wells. And you'll see those infill wells marked up on the map up here in light blue. And moving on to our Suffield area assets. And the success story of Suffield continues. There's been a focus on offsetting historical declines through oil well drilling and low-cost optimization activity. And 2024 was no different. We drilled eight wells in the [LS] or the Basal Quartz play. And production is in line with expectations from those wells. In 2025, we have no major development planned in the Suffield area, but we do continue to work up the potential opportunities we hold. And if the opportunity arises to increase activity levels, we'll be ready. And moving on to the other assets in Canada. And it's been a good year at the other assets in Canada. In Ferguson, we drilled five new production wells that are performing ahead of expectations. If you recall back to last year, we sanctioned the Phase 2 Mooney EOR flood with production response there ahead of expectations. We expect that to ramp up further through 2025. Again, like Suffield, we have no firm development at the other assets in Canada, but we continue to work up the potential opportunities there. Okay, so moving on to our international assets. Starting off with Malaysia, Bertam in Malaysia, where it has been another year for operational excellence with greater than 99% facility uptime. Unfortunately, in December, the A15 sidetrack well went down with an ESP failure, which requires workover. The good news is our field development studies have progressed far enough down the line that when we have the rig mobilized to do that workover, we plan to drill the next infill well A21 at that time. If I just draw your eyes down to the light blue chart at the bottom right of this slide, those infill well programs continue to add significant value at Bertam in Malaysia. Okay, so last in the asset section is the operational overview for France. Similar to some of our other assets, we've historically offset declines through developments in France. Even though we don't hold any firm development in the budget for 2025 in France, we do continue to mature the next phase of development opportunities. I mentioned Fontaine-au-Bron already. If you look up on the map in the top corner, you can see what we mean by it's highly undeveloped in comparison to our currently operated Villeperdue asset. I've highlighted where our current three sidetrack well targets are there. Beyond that, in Villeperdue, on the back of the successful Villeperdue West One campaign, we continue to work up what Villeperdue Phase 2 will look like. In summary, production guidance range of 43,000 to 45,000 barrels of oil equivalent per day in 2025, with an average production growing to 57,000 barrels of oil equivalent per day in the first or the next five years as we ramp up the Blackrod Phase 1 development. Investments, as I mentioned a number of times, 2025 focuses on that Blackrod Phase 1 development. We are drilling at Onion Lake Thermal and Bertam in Malaysia, and we continue to mature all of the opportunities within our global portfolio. With regards to reserves, so yeah, as I mentioned, a really good year for reserves replacement, 251% reserve replacement year-end 2024, and we exit year-end 2024 with 2P reserves of 493 million barrels of oil equivalent, a record for IPC. And with that, it is the end of the operational section, and I will hand you over to Christophe to take us through the finances. I like this picture with some of my very professional and good-looking colleagues working on some of the numbers you are looking at today. So this section is, I believe, quite hopefully interesting, but as well very useful for you because the intention is when we give you those numbers, we do not tell you what to believe in terms of oil price or gas prices or what kind of differential between the WTI and the WCS you would like to use for your own model, your own review. And so we're giving you a range and some sensitivity so that you can exactly pick what you think is fair for 2025 forecast. And that will give you on the back of the net backs in the following slides exactly the operating cash flows and the free cash flow in different scenarios which match with your own internal assumptions. So our base case is actually very close to where we are today with a Brent price of $75 per barrel, a WTI differential of minus five and a further differential of minus 15 between WTI and WCS. So it's reasonably close to where we are. It's interesting to see last year that when we used our base case was 80, 75, and 60 for the Brent, the WTI and the WCS. Fortunately or unfortunately, that was very close to the realized prices for 2024. Let's see if we forecast well again. Hopefully, the oil prices will be a bit higher. I think the Brent is around $77 as we speak. But that's a good range, and again, which should help you design exactly the case that matches your internal view. In terms of gas prices, I mean, we've touched upon it this morning when we released our 2024 numbers. The situation in Alberta, AECO is the reference gas price for Alberta in Canada. The market is relatively oversupplied in the sense that the storage levels are still quite high. So we've used a relatively conservative assumption of CAD 1.75 per MCF for our projection, but we're giving you what a CAD 1 increase or decrease would do. So it's a useful sensitivity, I believe, as well. The good thing on AECO is that the LNG Canada project has been repeatedly mentioned as coming on stream in this summer, in the summer of this year. So that should help alleviate some of the almost saturation in the storage facility. So we don't want to be over-optimistic, but we believe there is a decent trend and some support coming to the market from the AECO gas price perspective. Just reiterating what our main assumptions are for the guidance this year. So 43,000 to 44,000, sorry, 43,000 to 45,000 barrels of oil equivalent per day is our guidance. If you take the midpoint price of that range, 44,000, you compare it to the achievement in 2024, that's a 7% natural production decline. So $320 million of CapEx, $230 million of those are dedicated to Blackrod. So 70% of our CapEx, as you'd expect and assume, dedicated to the project. The operating costs are just below $19 per barrel. They're a bit higher compared to 2024. That's the result of a bit more activity, a few workovers, which are reported under OpEx. So a bit more activity in Malaysia, for instance, but as well, slightly higher gas prices in 2025, which, as you know, is an input to our Onion Lake Thermal operations to create the steam and facilitate the production there. So you see here in terms of net backs, so US dollar per BOE, what our base case would look like with the realized oil and gas prices for the revenues of $42, $15, between $14 and $15 for EBITDA and operating cash flow on a $ per BOE basis again, and $7 to minus $7 of free cash flow before or after Blackrod CapEx. So if you look at what our oil prices, how do they compare? Historically, they're reasonably lower, a bit lower, like $5 lower than the last couple of years. So our assumption is that our Malaysian crude will sell at a $5 premium to Brent. So $80 in our case. Happy to report that we have a lifting this month, which is selling at a slightly higher premium than $5. So it's a bit of support there. In France, we're assuming that the oil is sold on par with Brent, with just a tiny discount for our Southwest Aquitaine production. In Canada, assuming that Suffield and Onion Lake are two largest oil producers, are selling oil on par with WCS. You can see the AECO here. We're assuming a conservative three cents premium. We're selling on a Suffield. Suffield is both the name of the asset and the name of the sales point for our gas, which is literally on the Alberta-Saskatchewan border. You see that historically we've enjoyed a slightly higher premium. We're taking conservative three cents. Hopefully, there's a bit of upside there. I think it's important to reflect on hedging here. As we've discussed in the past, it's our view and strategy to leave our investors decide how they want to manage the oil price risk or the gas price risk, with the exception of two situations. One is when we have very significant CapEx compared to our base business cash flow, or if we would face some significant debt maturities. Clearly, in 2025, again, a very significant CapEx and investment program. We're starting to see the light at the end of the Blackrod investment Phase 1. So we felt it was appropriate to lock in some decent oil prices to support our base cash flow for this year, which is what we did. We used the opportunity of slightly stronger oil prices at the beginning of this year to complement our hedging, and so we have roughly 40% of our Brent and WTI exposure hedged. 2,000 barrels a day for Brent hedged at $76, just right about where we are, but for the whole year, we're in backwardation. So actually, it's better than it's actually in the money, this hedge as we speak. Same thing for the WTI. We've hedged roughly 40% of our exposure at $71 per barrel, and close to 50% of our differential, WTI-WCS differential, is hedged at minus 14. All of those hedges are taken into account in the net back we're talking in those numbers. All of that is included. So it reduces the volatility. So when we look at sensitivities, what would happen if the differential would be lower, if the oil price is higher? All of those numbers include those hedges. And so the sensitivity, which I'm going to talk in a minute, are relatively limited. We've hedged a bit of gas. I think it's fair to say we wished we had hedged a bit more with Curtis, but that was a good move. I think it's fair to say that if there was any blip or if the whole forward curve for this year was to go up a bit, we would consider hedging a bit more gas. Certainly not at the current price, though. In terms of FX, again, that's another significant exposure for us. All our activities from Canada to France or Malaysia, our expenses are in local currencies. So we've locked in around 75% of our Canadian spending this year between OpEx and CapEx at 136. It was a very positive level for us. But since we entered that hedge, the Canadian dollar has further weakened against the dollar. So the current rate is 143, so slightly negative for us, but still compared to what we had originally in our budget and in our forecast for the Blackrod project, for instance. It was a positive to be able to lock in the spend at 136 CAD for a dollar. And in euro and Malaysian ringgit, we've hedged as well around 75% of our OpEx for this year. So that's the result. And really, these tables are meant for you to play with, pick a number in terms of somewhere within that production range between 43,000-45,000 barrels a day, pick an oil price, and as well play with the potential differential sensitivity. So in that case, and I think it's interesting to focus on the cash margin, so really the revenues less OpEx, we're at $15 per BOE in our base case with a Brent of 75. You can see here the shape of what we're projecting our OpEx per barrel to be during this year on a quarter-per-quarter basis. The workover and the new well to be drilled in the northeastern side of the Bertam field in Malaysia are meant to really come on stream in the second half of this year, which is where you see operating costs slightly reducing in the second half. And we have some activity with limited shutdown in Malaysia in the second quarter, meaning that the OpEx per barrel will be slightly higher. But so we're happy to guide from between 18 and 19 at this stage. We're a bit higher, around 18.7. But depending on gas prices, there are also some potential upside there. I think this one is important. And you can see that the operating cash flow net back in our base case is $15 per barrel. As you can see, there's not a massive sensitivity between the low and the high case. This is really that has really something to do with the hedging we have in place. Actually, if you would pick between our base and high case, if you would use the average of those numbers, you'd realize that the net backs are lower than what we enjoyed in 2024. That's really a factor of those hedges. We've hedged Brent at $75 this year, $76, WTI at $71, when in 2024, we had some Brent hedges at $85 and WTI hedges at $80. Really, the difference is like the business is still as good. The base operations are still working, going as strong as in 2024. The reduced net back has to do with oil prices and our hedge position. You have all the net backs going all the way down to the net profit here. I think this one is more interesting. And so you see that if the in case the differential would widen or reduce by $5. So in that case, if the differential was to increase from $15-$20, so if the WTI was $70 and the WCS $50 per barrel, in that case, we "only lose" $1 per BOE in revenues, operating cash flows, and EBITDA. So the sensitivity is significant. The five bucks is quite significant, but the impact on our cash flows is limited again because of the hedges, roughly 50% of our exposure to the diff that we entered into at minus 14. It's an interesting question you've not asked. Maybe that question will come and we can elaborate further, but when Trump mentioned or threatened Canada with tariffs, immediately the differential widened between the WTI and the WCS. Typically, our hedges will play a nice role in that and will limit our exposure to that risk. That's better to be lucky than good. Our intention when we hedged the diff was really just to be protected in case anything happened on the Trans Mountain Pipeline or on the Keystone Pipeline taking our Canadian production to the U.S. It also works in case of U.S. import taxes. The gas sensitivity is interesting and is an interesting way to remind you that we are consuming some of our production. If gas prices would go from CAD 1.75 per MCF to CAD 2.75, the impact on our total revenues would be $1.2 per BOE. The net impact on operating cash flow is only two-thirds of that because we consume one-third of the gas we are producing. This is probably the most important one in terms of looking at the net back in all those different cases. If you look at the base case here and you look at the free cash flow of $7 per BOE in the base case before the Blackrod CapEx, if you use the 44,000 BOE per day, so the midpoint production guidance applied to $7, you roughly would see that the free cash flow generated by our base business before the Blackrod CapEx is $115 million minus $230 million of Blackrod CapEx. That would give you a negative $115 million of free cash flow, including all of the business CapEx, including Blackrod. In terms of the capital structure, the business has not moved much. We still have our $450 million of bonds outstanding at 7.25% coupon. The interests are payable twice a year in February and August. We are at the end of the non-call period, so we can call the bonds from a few days ago. We have no immediate intention, but we're obviously monitoring very closely what's happening on the bond market. The bond market is very supportive right now, so we keep an open dialogue with our banks and investors to find the right opportunity there. The bonds are maturing in February 2027, so we have quite a bit of time before refinancing this bond or repaying it. Very happy to report that we still have CAD 180 million of revolving credit facility from our Canadian banks. It's fully committed, fully available, and fully enjoyed. So the business is in good shape from that perspective. We still have a very significant amount of liquidity. And as Will mentioned, we ended the year at the end of 2024. We still had $247 million of cash on the balance sheet. And that's it for my part. That was really just the 12 months look ahead, and now we have the five and 25-year look ahead. Yeah, Ryan said that we weren't going to get through all the slides in an hour. Challenge accepted. So starting with the reserves evaluation, I've just got a couple of slides that I wanted to show you. But I think key here is just to remind you a bit of the process that goes on behind the numbers that you see. And something that's really important for us is that everything is bottom-up. So we look at assets, we look at production, we look at capital expenditure, we look at operating costs, and then we build that into a picture at a country level and then also at an IPC level. And that's what sits behind that. It's a 10-month process. It starts in March, it finishes in January, and there is a lot of work behind these profiles. And that goes really to our confidence in the numbers that we present to you. Long-term pricing forecast, actually, it's quite similar. We did see a bit of a decrease in the upfront Brent for 2025, which went through to the Western Canadian Select there. About a dollar difference in the profiles. For every dollar, you lose about 100 million of NPV, and vice versa. For each dollar plus, you gain about 100 million NPV. So not significant numbers, about 3% in the total there, our total NPV. The gas price, I'll grant you, looks a little bit ambitious. But what's happened with the gas in Canada, and Curtis can expand on this a little bit more, is that Canada LNG was meant to come on, producers produced up in anticipation of that. It's been late. There was a warm winter, and these things sort of combined, which meant that the storage in Canada, gas storage in Canada, became very full. So that situation is now working its way out. You can see that the reserves auditors, at least, are confident that the gas price will return to a normalized level in 2025 of about $4. So that's what runs through our profiles. But I think it's also important to mention that we've hit the point now where we're quite balanced on gas price. So in about 2029, we'll hit the point where we become more of a consumer than a producer. And even if you change your gas price by $2, you barely see a movement in the NPV because that's how balanced we are between producer and consumer at these different points in time. NPV per share, there's a couple of interesting points on this slide. I think first drawing your attention to where Blackrod is sitting, 132 SEK a share. So that was 79 SEK a share last year. Obviously, this big increase in value, even despite a little bit off on price. It's SEK 306 a share in terms of value. It was sitting at SEK 240 last year. And if we look at our share price today and we add up all of the assets, we don't even include Blackrod, we have SEK 174 a share. So even at today's share price, without including Blackrod, we have SEK 174 more value than our current share price, which just gives you an indication of why we believe we're so undervalued in our share price. SEK 20 a share of this 306 is value that we give to the buybacks in the reduced number of shares that we've had over the past year. You can see that that's increased year on year. So that gives you a really positive indication of what happens in these buybacks. You just get an increase in your per share value, which is really important for a company that is coming up to increasing value year on year, and I think the one other thing to point out here is you see it's a very narrow range on SEK per share, it's SEK 223 to SEK 369 between your 1P, 2P, and 3P, and that really shows the tight range that you get with oil sands projects in particular. We have very homogeneous reservoirs. It's very predictable, and that compresses your value between your different reserves categories, and my final slide, I really like this slide because it shows you a few different things here, and I think the biggest thing that it shows you is in order to make big value in oil and gas, you need to make bold moves. And Will has shown you through our acquisitions that we've made bold moves, 2018, 2019, 2022 with Blackrod. And we've got more bold moves to come. We've got a billion barrels that sit in our contingent resources, for example. And then I think what 2020 shows you is that you shouldn't make bold moves unless you have a very strong balance sheet. And Christophe has shown that we've got the strong balance sheet. We are always paying attention to what's happening with our CapEx program, whether we need to hedge at any particular point, making sure that we know oil and gas, it's cyclical, making sure that we can ride a cycle if it comes the other way on us. And so that's been really important for us as well. But what I want you to take away, really, is look at the big chunks of upside value that come through the M&A 2018 and then through Blackrod 2021 to 2022. And really, it's just imagining what we'll look like going forward when we put our contingent resources into our 2P profile. When we continue with M&A in our DNA, we will continue to do it. This company will go up and up. And I think that's where I wanted to leave you with Will to close off. Excellent. Thanks for that, Rebecca. Bold moves, that's what it's all about in contrarian decision-making. And that's really what's put the company in the position where we are today, where our share price has appreciated over four times since we were formed. We very much believe that we're still in the early stages of material value creation to be created in the years ahead here. Closing remarks, the production that we expect to achieve is between 43,000 to 45,000 barrels of oil equivalent per day in 2025. We expect to grow our production in excess of 50% by 2028. We have growth through our Blackrod asset, which now has 259 million barrels of 2P reserves assigned to the Phase 1 development and much more resource potential beyond that. That alone represents $1.4 billion out of our $3.1 billion in net asset value. The 3.1 NAV using a 10% discount rate represents a fair share price of 287 SEK per share. A ways to go to compress that discount that we're trading at. And the balance sheets, Christophe also touched on, and I had mentioned at the beginning of the presentation, we have $250 million just below that of cash resources on the balance sheets. And our shareholder returns have been extraordinary, much differentiated by a lot of our peers out there. You hear a lot of share buybacks that happen within this industry, but it's all about your absolute share reduction because we're not issuing shares. We've had a 24% absolute share reduction since January 1, 2022, which is hugely impressive. There's been five accretive acquisitions that have been done in the last eight years since the company was formed. And we've had really good safety results on our Blackrod project and within the company overall in terms of no material safety incidents. And this is such a big focus for the company while we get through this build. As it was mentioned before, you can kind of see the light at the end of the tunnel, but it's absolutely critical that we do all of our activity in the safest way possible and ensure that none of our staff or contractors that we're working with are getting injured in any which way. So that concludes the overall presentation for the team here. And we very much look forward to opening up the floor to more questions. And with that, I think I'll also ask a few of the Canada guys as well to take a seat up here at the front if we can somehow rejig the seats at the table here. But thank you. We'll take questions from the audience first, I think. Yeah, thanks for clarifying that. So we'll start with from the audience, and then it'll come in from the web. Try and come in a little bit to the side. You're good, Nicki. Slide over a little bit. Okay, any questions? Everyone's good? We'll go home? Ruben up there with you. Yeah, we go. Sorry, Ruben first. Yeah, we'll come to you next. Hi, thank you for taking my questions. Ruben from Jefferies. Just one on Blackrod to start off with. Given that it's a pivotal point in the conversion of Blackrod into 2P reserves, as you said, from the contingent resources, and we're coming up to First Oil, I wanted to just ask, what do you see as the most significant risk factor between now and First Oil? And just kind of elaborating on that, how many years do you give for Blackrod Plateau? Thank you. Will? Yeah, great. Yeah, I can take that one in terms of the biggest risk factor. I think it's going to be things that are really outside of our control at this stage. So it's going to be weather impacts that can have a knock-on effect in terms of the critical facility modules that are still to be delivered to site. If there's a knock-on effect where we want to get a certain piece of kit towards the site and it's very harsh conditions and we can't get that piece of kit out there, then that can have a delayed knock-on impact, which can also relate to higher costs, as well as being impaired. And so the level loading at the field is very critical in terms of the construction task force that's out there. And so with the peak activity still underway here, we want to make sure that everything continues to happen in an orderly manner. Of course, something like weather is not something that we can control. And then I would also say that the electrical side is a very critical part of this scope to complete. It's like the nervous system that exists within a human body in terms of making sure that all of the instrumentation connections and electrical-related connections are wired into all of the key aspects of the facility. And so as things stand at this point in time, we have all our critical E-houses at site at this point, and there's no major concerns there. But that is a key part of the scope that still presents some risk, but we feel comfortable where things stand at this time. And I'm not sure, Chris, if you'd add anything to that in terms of notable risks maybe at the Blackrod for the project where things stand beyond what I've mentioned already. I don't think so. I think you covered it for sure. It's the field construction component of it that there is some risk there, but very manageable. Okay, thank you. And just maybe one more. When you have Blackrod online late 2026, wondering with all the significant free cash flow that you're about to make, will focus be on the contingent resources phase two side of things, or will you be going back to M&A? Or how do you look at capital returns and capital allocation from that point on? Yeah, and also on your past question as well in terms of plateau production rates, given that it's oil sands, it's a SAGD asset we're developing. This is a very flat production profile. Once we hit 30,000 barrels per day around late 2027, at that point in time we expect to maintain around 30,000 barrels per day in that Phase 1 development for around a decade or so. It's a pretty flat production profile for the beginning years of Blackrod. Then in terms of once we have a lot of free cash flow being generated and the major CapEx is behind us, I mean, we're going to stick to, of course, our three key strategic pillars, which is slightly open-ended, but in terms of maximizing value organically within our asset base. We're doing a lot of work behind the scenes, all these guys to my left and to my right here, and Nicki, of course, and Rebecca working on the future phase expansion potential at the Blackrod asset. And so what we can do here as a management team, which is important, is to mature every single project that we have within our portfolio. So when we're benchmarking against looking at creating value through M&A, we're always able to internally look at what we have in our portfolio in terms of projects to sanction. And that's really what happened as well in late 2022 there where we were close to having some material acquisitions take place. We were unsuccessful being a slightly lower end of the bids. And these were transactions that would have delivered in excess of 20,000 barrels per day of immediate production growth of the company, but break-even prices for those potential acquisitions were around $65 Brent. And we looked internally. We had the Blackrod Phase 1 development, which had a sub-$60 WTI break-even. So in terms of the best way to create value, we decided to go organically and sanction the Phase 1 development. So of course, we'll also be looking at enhanced shareholder returns as well, provided we're going to be continuing to trade at a material discount like we are today. Then buybacks will definitely continue to be a theme. But if we compress that discount, we'll look to do dividends. So a lot of optionality, but of course, the core focus and the owner-operator mentality is to maximize value for all our stakeholders. Thank you very much. I'll pass it on. Thanks for the presentation. Very transparent to follow, I think. So thank you for that. I'll be the one to ask the question that might have bored you in the latest couple of days. But how do you expect the differential on the WCS to develop now around the communication on tariffs? And do you think that oil producers will have to take the majority hit if it were to happen? Or do you think it could be offset to the en d customers? Christophe, maybe that one? Yeah, I'll start and hand over to you, Curtis. But yeah, it's a very good question. And it's never entirely certain who bears the cost at the end. What's very clear is that if and when tariffs would be put in place, the maximum would be so it was 10% recently. And when you look at all the analysts and our own understanding, I think it's fair to assume that the cost of such a measure would be split between Canadian oil producers and US refiners and US end users. It's also probably fair to assume that the bulk of that cost would be borne by the Canadian oil producers. The impact on tariffs is clearly the WCS price, which simply goes down to compensate for the extra cost that US refiners have to pay to buy those Canadian heavy barrels. The good thing, as I mentioned, is that we were 50% hedged against that risk. It was never intention to hedge ourselves against that. But the end result is exactly that. Yeah, maybe, Curtis, you can touch upon what was the immediate impact on the differential when Trump threatened to impose that new tariff. Yeah, so I guess we were at the end. Curtis, can you use the mic? Okay. Thanks. Does that work? Yep. All right. The immediate impacts, worst-case scenario, were kind of $4 a barrel. If you were to run the math on what full impact to producers would be, it's probably $5 a barrel. If you look at today's market, I think you're really only for the rest of the year kind of $0.50 to $1 wide. So, I mean, the market's telling you that they don't believe either the tariffs will come through or that the Canadian producers will have a full impact. I do think we'll take a piece of it if it comes through just because there's only so much we can do. There's about 200,000 barrels of spot capacity that could be moved west, which does help take some of the impact out. But yeah, I would say the trading in the market was kind of at the worst case $4 a barrel wider for that day. I think that was last Monday. And now we're seeing $0.50 to $1.00. So that's kind of your range. It doesn't really impact what anyone's production plans will be. And it'll have a muted impact on our cash flow just because after royalties, after taxes, that entire impact doesn't roll through the business. Yeah, I think it's interesting for you to look at slide 52 in the context of your question, where you see what the impact of a widening of the diff by $5 per barrel would mean for 2025. The impact on our cash flows is less than $1.00 per BOE. So that's really what we're talking about in terms of potential impact of a 10% US tariff. Not very significant for 2025. No, I guess it's really within the natural volatility of oil prices. And we're modeling $15 to $20 there. So really what we saw was $13 to $17, so still tighter than that modeling case. Thanks a lot. Anyone else from the audience? Yep, right up the back, Amir. Thanks. Thanks. Amir Arif with ATB Capital. Just a couple of quick questions on Blackrod. With Blackrod, some of your capital seems to be pushed out into early 2026 in terms of hitting the $850 million number that you're still holding out to. Can you just give us some color on what that capital is or what it involves? Thank you. Do you want to take it? Yeah. So the 2025 spend or the 2026 spend? By the end of 2025, I don't think you're fully out the 850, so are you? No. And that's correct, so as we exit 2025, we're still commissioning and finalizing the plant. We've got our final drilling completions to complete as well. Okay. It's mostly drilling and. Primarily drilling and a little bit of commissioning to roll over. Okay. Then just in terms of the steaming, if that starts at the end of Q1 2026, can you give us a sense of how long you plan to steam it for? Is it six months, nine months? Currently we're around nine to 10 months in the plan. Chris, maybe you can have a talk about that nine to 10 months, yeah? Sure. Amir, we do start a kind of a progressive handover, a progressive commissioning. You don't bring on all the wells on day one. You don't have all the equipment steaming on day one. So you see a first steam on that schedule, and then you see a first oil that is a number of months out there. But that's getting all the equipment and all wells online. That explains that better. Okay. No, that helps. And then just finally, in terms of the ramp up to the 30,000, would that take nine months, 12 months? Well, maybe? Oh, sorry. You got it. 18 months. Oh, Chris, yeah. We have a profile approximately closer to the 12 to 18 months kind of range, but you'll see that peak in 28, that plateau in 28. Thank you. Hi. Tariq from BMO Capital Markets. Looking at those pad additions that you identified in 2024, are those part of the initial ramp up, or is it identified to offset declines from the initial well pairs further down the road? Then my second question is, looking at your well pairs that will come along with the commercial project, is it safe to assume they'll be similar to the third well pair at the pilot, or are you seeing the ability to increase well rates beyond t hat? Ryan, if you could take that one. Sure. Okay, thanks. I'll take the second one first. I think very much you can expect the rates to resemble well pair three. The geology in the initial development area is very similar, and so we would expect rates to fall in line. The well length is 1,400 meters in line with that pilot. So that is a good template for understanding the rate potential. Then in terms of your first question, so we booked 14 development pads as part of the project sanction. What Nicki showed earlier is pads number 15, 16, and 17 in the sequence. So those would be to offset declines at the tail end of the project. Awesome. Thank you. Anyone else from the audience? Yep. Hi. Thank you for taking my question. It's Jakov from SpareBank 1 Markets. First, maybe a bit long-shot question, but how do you see 2026 CapEx in relation to 2025 and kind of, yeah? Yep. Take that one, maybe, Nicki. Yeah. So the major spend at Blackrod will have been completed. So we still will have a little bit of carryover, as we mentioned to the gentleman earlier, but it should be a lower capital expenditure year. Of course, we've still to build that budget, and we've still to get through 2025. So it's a bit too early to confirm what it would look like, but certainly the spend at Blackrod will be less. Okay. And regarding buybacks, at what discount to NAV, in your opinion, you're going to slow down buybacks? Will, maybe that's you, I think. Yeah. Great question. So sorry, what discount to NAV in terms of where we'd be trading at? Would we be looking to slow down the. Regarding your valuation to NAV? Yeah. Yes. We've never put out a specific number. I mean, we would like to get close to that. We truly feel, given the track record of what the company's achieved, that we should be trading at a premium. And if we were at or at a premium relative to our net asset value in that situation, would we be a dividend-paying company? So we'd like to really compress down that discount quite a lot materially further than where it is today before we would start to do that. Yeah, because you have to remember the NAV we're talking about doesn't include any of the resources, obviously, so. Exactly. It only takes into account our 2P reserves. Hi. Sorry, in light of that question, can you talk about, so you have M&A buybacks, and then you're coming off major CapEx. M&A, you never know when it arrives, but I'm just wondering if something arrives that is interesting enough or sizable enough, how do you think about that relative to the balance sheet and buybacks? I mean, to which, I don't know how far you're going to stretch if a number of things sort of collide in time, the balance sheet, if you see that happening. And then in M&A, can you, I don't know, give us some color in terms of geographies, assets, what sort of things are you looking at? Thank you. Yeah. My father would always say that with good assets, you can find the money and make it happen. And so whilst I wish I could believe, I think there is a certain threshold or ceiling in terms of what we could do, I think it's a little bit unlikely that we're going to do a transaction or at least a fully cash-funded transaction at $500 million-$1 billion right now while we're rounding out the major spend year at Blackrod. But nevertheless, I mean, options exist in terms of refinancing bonds. Or if there's a company that's trading at a more significant discount than we are from a 2P net asset value perspective, then we are open to using paper in such a case. But we'd have to have a very high degree of confidence that that truly is the situation because we've been on an aggressive path of reducing our share count. So when using our paper to do something like that, we would have to be very, very compelling and convinced that by doing a deal and issuing shares, more value would be created, sort of like the transaction that took place with Black Pearl Resources where we used our stock. So, I mean, we have $250 million of cash resources available, CAD 180 million in drawn credit facility. There's a decent amount of firepower that we could deploy towards an asset or a company acquisition naturally, but I think it would be sub $500 million below that at this stage if we were to do such an activity. In terms of geographical locations where we've been looking at and continuing to screen different opportunities, of course, in Canada, we've been doing that. Curtis has been working with Ryan and Chris leading that initiative, of course, while fully looped into the whole process there. If we can grow where we have existing areas of operations, that makes a ton of sense given the teams that we have in place and the connections and relationships that were already established. However, in saying that, we're opportunistic at our core. So we are open to growing in other jurisdictions, whether that be Africa, Latin America. But again, there has to be a major strategic edge in terms of if we were to do a new country jurisdiction entry. And so we'd want it to be significant to really turn the needle if we're to go into a new jurisdiction for the company. And one of our big edges here in IPC is the operational proficiency and the understanding of our assets being the operator of our assets. And that's a huge benefit to have that and be able to really dictate the pace of your development activity and what you do to maximize value of those assets. So in saying that, preferably, we'd be able to secure something that we could be the operator of those assets. But again, we're opportunistic at our core. So if there's something non-op that looks interesting and we can get it for a very good price that's cheaper than buying back our stock or developing phase two of Blackrod, we'll take a look at it. I think it's fair to say as well in the context of what the impact could be of M&A on the balance sheet is that we have development assets with Blackrod Phase 1. We have further development opportunities with a phase two or even a phase three. So it's fair to say that if we were to consider M&A, that would most likely be with the target of increasing production. So we're thinking about production bringing immediate free cash flow. So also, if you think of M&A in that context, that means that the target would likely bring some debt capacity with it. So it doesn't mean necessarily that the leverage would go through the roof because we're doing M&A. The target would bring cash flow and free cash flow. That would be the mindset of M&A. That's a great point. Thank you. Oliver Dunvold from ABG Sundal Collier. You have a bond maturing in 2027. Can you please provide any more color about your plans for financing and also just in terms of the balance sheet if you want to continue using the strong, tight bond market? Yeah. No, I think we're very happy with the concept of having bonds. It's not cheap, but it's long-term money. So it provides long-term capital to a company like us, which has very long-lived assets, right? So I think it's important to have some form of balance between the maturity of our project or for investment cycle and of the source of capital. So from that perspective, it's working very well for us. We like the idea of having some revolving credit facility to complement that if we have some short-term needs. But generally, we see the source of funding from the bond market is clearly a good one. Again, next week, I have a few calls with banks around bonds. Everyone explaining to us that the market is very supportive these days. It's arguably a bit early because we've just come out of the non-call period for these bonds. But we are following that very closely. Our bonds are trading around 99%, so very close to par. So we also need to maybe better understand what the issuance price could be in the context of new bonds. And as we speak, the refinancing of those bonds would be at a small premium of 2.9%. So we'd have to repay 102.9% of the face value of those bonds. So it's a continuous discussion internally. And we're following that, of course. We believe that if we can make some progress around Blackrod, which we are definitely doing, it should benefit both from the bond investors' perspective or from our perspective when we're to market new potential bonds. So we want to give ourselves probably a bit more time, but following very closely how strong and liquid the market is. Thank you. Okay. No more questions from the audience, I don't think. Oh, Tore, sorry. You mentioned briefly Blackrod Phase 2. Can you elaborate a little bit more about your thinking and timing on kind of sanctioning potentially or not sanctioning, but kind of how are you thinking about timing for Blackrod Phase 2? Also a little bit on potential synergies and your key learnings and how would that kind of, is there, I would assume that especially on timing and process, there are some key learnings to be done from the first part of the project. Thank you. Will? Yeah. No, it's a great question for sure in terms of future phase expansion potential at the Blackrod asset. So where we're at today, of course, all hands on deck and focus is on getting Phase 1 on stream and oil flowing through that facility. But what we are also doing behind the scenes here is maturing up the phase two concept through our value process policy, which involves multiple decision gates to go through. So with respect to that, Nicki's highlighted within his part of the presentation, part of the resource maturation that is taking place right now. With some of those future barrels that are being matured into the Phase 1 area, and when we look at the Phase 2, there's options in terms of what exists and what we can do, which is either you could expand that existing central processing facility or do something that's a completely standalone plant. The latter one is where we're thinking about during our concept selection phase right now to just put a brand new standalone 30,000-barrel-per-day facility. With that, if we were to put a brand new CPF, you need all the well pads associated with that as well. So while there will be some synergies that you would achieve with respect to the Blackrod, with respect to the Blackrod pipelines that are already installed, also with respect to the detailed engineering and some of the fabrication learnings that have taken place and the successful partnership and relationships that's been formed with our key vendors and EPCMs, using those aspects, there would be some synergies and cost savings, perhaps around 10% or so. But it's not huge given that if you're to do a phase two, again, we're under the concept selection phase at this stage right now. And if you're to do a standalone facility, there's still going to be a pretty significant amount of CapEx to put that in place. In terms of timing, looking at that, again, we want to mature that opportunity as far as we can while spending the minimum amount of dollars in order to do that as well. And so once we're in a position, Blackrod's on stream, we're hitting plateau production rates. What happens is it actually pays out quite quickly, at least based on the reserve auditor price deck. And when that takes place, the pre to post royalty regime changes, which is expected to happen around sometime in 2030. So it would make logical sense for us to be able to pursue a phase two development sometime before the end of this decade, let's put it there. And I don't know if there's any other additional comments, Nicki or Chris, the guys that would like to add to that in terms of Phase 2. The only other synergy I could think of is we've sized all these lateral pipelines for at least Phase 2. So that's also a benefit from an operating cost perspective is all these lines will be in the ground for gas, oil, condensate. Export pipelines, for example, are they kind of sized through a Phase 2 development? Yes, largely. Yeah, that's exactly what you just noted there as well. The lateral pipelines that have been installed, they have been sized to future phase expansions. Is that what you meant, the lateral or the connecting? Yeah. There's room in both. I would say the laterals, it's not only that they're sized for that, it's that you don't pay a material different cost, so your dollar per barrel will go down. We need new contracts where we'll sign for space on the ones that were built before we were there. So that's just the delta. But you have on the laterals, you'll get an opex per barrel savings for sure. Okay. No one else from the audience? No? Okay. We've got a few from the internet. So if I can just direct a couple here, maybe start with Chris, are there any expansion plans for Onion Lake in the future? So Onion Lake, thermal project as well. It has a viable, very economic project in our five-year plan to do an expansion there. Really underpins the long-term, multi-decade plateau of production from that expansion. So definitely on the books in our five-year plan. And I look forward to at some point the right size between maybe Blackrod 1 and Blackrod 2, it could be a fit. So that's how it sits. That answer that question? Yep. Thank you, Chris. And then maybe Nicki, there's a question and a compliment in one. How do you manage to continuously replace most of the reserves produced from your Malaysia and France assets? It's probably the most impressive thing in the material change report. How is it even possible? Well, as I mentioned, organic growth is part of our DNA. And our goal is to maximize the value of all of our assets, no matter what stage and age they are in their life. And one of the best ways to maximize value is obviously increase your production volumes. And that's not just in Malaysia and France, but Malaysia is a really good example of that. So at original sanction, we had something in the region of 15 million barrels in Malaysia recoverable. We've already produced significantly in excess of that. We're on track to produce almost double that by the end of the current economic life. We've done that through just continual infill well drilling. You'll have seen that on my slide. Like I mentioned, that approach we take to all of our assets, that's one of the ways we maximize value through operational excellence. Thanks, Nicki. Christophe, maybe you could take this one. Could the CapEx of a potential Blackrod phase two be fiscally deductible to the OCF generation in Phase 1? Yeah, well, when we spend CapEx, we depreciate it over time. So yes, it's deductible, not the full amount upfront, but would be deductible over time, yeah. Also the royalties, no? Yes. Yeah. It's deductible against royalties and CT. Yeah, that's what was mentioned. If we spend more before we reach the payback on Phase 1, effectively you stay longer in a lower royalty regime, which is very beneficial. So even if there was not major synergies between a Phase 1 and a Phase 2, there would be clearly synergies in terms of reducing the royalty payment in the first years. Yep. Thanks, Christophe. Perhaps to you, Ryan, on Blackrod, what steam oil ratio are you targeting there? So again, well pair three can be a good template for what to expect early on at Blackrod. So I would expect something in the two and a half to three range early on. But leveling out medium to longer term, we're looking at a three to a three and a half SOR for that property. Thanks, Ryan. And then Will, perhaps this one for you. There's a couple of questions on potential to release schedule or cost contingency at this stage on Blackrod Phase 1. Yeah, as things stand, we're really pleased with the overall progress that's taken place, given that we've spent 70% of the overall CapEx and the value of work done is reciprocated in the money that's been spent, which is fantastic. However, there's still a lot of work set out in front of us. The last thing we want to do is sit here and overpromise and underdeliver by re-guiding our project in terms of adjusting schedule or budget. So as we get a little bit closer, as things progress, hopefully we continue to have really good progress. Everyone's working their absolute hardest to improve timelines, to improve costs. But we're going to need a little bit more time to pass before we're going to deviate from the original guidance that's been set out on this project. Okay. Brilliant. Final question really. So Christophe, a couple of years back, you talked about possibility of trying to get investment grade. Comment at the time implied you'd need more production. Yeah, there might have been a misunderstanding there. So to become investment grade, we need to talk this one out. Maybe the bankers are laughing at me now. But to be investment grade, you're already talking about 200,000 to 300,000 barrels a day. So we're not there yet. What maybe I meant a couple of years ago is that it's fair to say we're a B, we're a B credit rated company and notes outstanding today. It's fair to assume that when you reach 80,000 BOEs a day, which won't be quite the case with Blackrod, but when we look forward with a Phase 2 or with some M&A, we might get to 80,000 BOEs a day and above. And at that moment in time, if you have 1P of 300 million barrels, 2P, yeah, 1P of 300 million barrels and production above 80,000, I think we would qualify at least with a reasonable leverage to be a BBB-rated company and maybe bonds. And in that case, you can assume maybe a 1% saving on the cost of funding. Yeah, and I think that's an important thing to highlight in terms of the recognition that size matters. And if we are to add more production, whether organically or through M&A and get to that next threshold, reduced cost of capital obviously is something that's quite advantageous. But shareholders, stakeholders within IPC should be rest assured that we're very much focused on value over volume. And so we could easily go out and make an acquisition and just issue a bunch of stock and dilute everybody down and then get to that level. However, it's always going to be from a lens of pursuing value over volume. Okay, good. I think that's taken care of all the questions. So that's it from me. Great. Okay. Well, thanks everyone. If there's no further questions, we'll be standing outside here for a little bit to interact. And there'll be a further event later on tonight. And really appreciate everyone making it out here today to listen in to what we believe is an extremely exciting E&P story in IPC. And thanks to everyone tuning in online as well. So thanks to the team also and all the teams in IPC globally. It's been a really impressive year in 2024 and the best is yet to come. Thanks.