International Petroleum Corporation (IPCO) Earnings Call Transcript & Summary

Attending in person today in Lundin 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 along to Nicki 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 was a record investment year from a capital expenditure standpoint. We spent USD 327 million, which was in line with our latest guidance of USD 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 51,100 barrels of oil equivalent per day, and our operating expenditure was in line with guidance between $17.50 and $18 per BOE. It's 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. And notwithstanding, we executed the transaction to acquire Cor4 resources in March 2023 for USD 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 USD 58 million. And when you include the bonds available to us, we have greater than $0.5 billion 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 20-kilogram per BOE by 2025, and I'll expand on that in the ESG section in the upcoming slides. So starting into the meat of the presentation here, a big milestone was achieved for IPC. We have 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 more than 3x 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 in between $900 million to $1.8 billion in free cash flow. So that has less all the development costs associated with Blackrod. And when we look at capital allocation, there's 3 core strategic pillars that IPC has starting with organic growth. This is a 10-year production profile based on our 2P reserves. And as you can see, the second half of that first 5-year period, we start getting a serious production uplift from the Blackrod Phase 1 development, which is going to push the subsequent 5-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 will 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 I development. So within the Phase I 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 kilometer square, it's about 2.5. So 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 kilometer square, it is about 0.2. So what that means in distilling it down to a simplest form is that 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-plus 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 USD 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 USD 1 billion using a 10% discount rate and now has a sub-55 WTI breakeven price. Now contingent resources with in 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 value is applied to any of these volumes and the valuation or free cash flow numbers that are shown today. And 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. But 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 16x. 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 going to be taking place. But what is important to note is between $70 and $90 Brent on the base business, excluding the growth CapEx associated with Blackrod, we expect to generate between $140 million to $270 million in cash flow, which represents nearly a 10% to 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 and in just the first 5 years at $85 Brent be able to liquidate the market cap in the 10-year horizon, we expect to generate between $2.65 billion to $4.6 billion in free cash flow, assuming a $75 to $95 Brent price. Moving on to our third key strategic pillar, which is M&A. So we've crystallized greater than USD 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 going to continue buying back our shares, provided the balance sheet stays in good form. So I've touched on the 5-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 5-year period which will be around 65,000 barrels of oil equivalent per day. And between that timeline between $75 to $95 Brent, we expect to generate between $1.75 million to $2.8 billion in free cash flow. So as we walk 1 year closer to first oil with Blackrod, what you're going to see is the free cash flow start to enlarge in the front 5 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 1, 2029, the NAV 10 per share and a $75 pricing scenario would be in excess of SEK 750 per share or under a $95 Brent scenario, slightly more bullish the value would be in excess of SEK 1200 per share. And 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 in between SEK 115 per share, SEK 215 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-kilogram per BOE from 2025. And 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-kilogram per BOE. And 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 Nicki for the operations section.

Thank you, Will, and it's my pleasure to take you through our 2024 outlook before going 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. And there's been some minor ups and downs rather producing assets. And 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. Onion Lake Thermal in Canada and Bertam Field in Malaysia, we've matured some contingent resources into our 2P reserve space. And our Mooney asset in Canada, our contingent resources now are matched to the latest field development plan. So just moving on to our 2024 investment strategy. So 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 and 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 USD 18 to USD 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 here 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 5- plus 5-year outlook. And on the back of the progress at our Blackrod Phase 1 development, we're extremely strongly positioned for longer-term growth. And if I look at the next 5 years production, it's 50 -- we forecast average 55,000 barrels of oil equivalent per day, growing to 65,000 barrels of oil equivalent per day in the second 5 years as we reach plateau rates and stability of our Blackrod Phase I development. In that time, it's no surprise that our capital cost in the first 5 years as we complete the execution market Blackrod's Phase 1 are slightly higher, USD 11 per BOE coming back down in the second year to a more normalized sustaining cost of USD 5 per BOE. And in that time, from an operating cost perspective, we expect to be stable around USD 18 per BOE. And with that, I'll hand over to Chris to take you through the Canadian detail.

Thanks, Nicki, 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 '23. 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 fabrication facility that is fabricating all our free water knockouts and treater facilities, big vessels. The middle picture is referring to -- as our evaporator. So these are some of the heavy hauls, the long-term 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 going to 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 piles and [indiscernible]. The bottom left is a better picture of the evaporators that are going to 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 for produced water recycled technology. So all the produced water goes to, we call IGF. We cleaned 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 peer water off the top and the waste, call it, the salts and the hardness comes out at the bottom, and we disposed of it in salt cavern, 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 steam chamber, understanding steam chamber growth. The salt cavern wells that I mentioned to dispose 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 geologist 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 prognosis. So we actually were able to add a couple of meters of SAGD pay to that, which again, helps our Phase 1 plan. Where the schedule sit for Blackrod today? So nothing has shifted. We're still expecting first oil in October of 2026. All major equipment has been procured all the long lead and critical path type things have all been identified and mitigated if there -- it was something that is at risk. So we have mitigation plans for that to be able to achieve that October 26 first oil. Jumping into our base assets that again, diversified portfolio from gas to an in situ molecule, 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 5 drainage patterns that are currently producing today. We have another pad -- we call another drainage pattern, we called our L drainage pattern. It's also drilled, 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 at nameplate today, and we'll just continue to hold it there 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 here, the conformance of the production that we're getting. So all thumbs up for the Onion Lake Thermal project. Suffield. Again, another strong asset, great base production, minimal declines. There is 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 the reserve growth of over 40% of reserve growth through acquisitions and just good base optimization work. Bottom right is 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 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 our -- 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 -- it's a horizontal -- it's a multi-well horizontal type play, and we're seeing some really fantastic results from it, and we have a deep inventory of wells to continue to work on that organic growth and really help that asset. It's kind of tuck-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 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 II 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 we're not surprised with 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 successful development campaigns or the recent successful development campaigns in both regions, we're now integrating the results and maturing our next phase of development targets there. And as I mentioned, the well workovers are complete in Malaysia. And just moving on to Malaysia, you see the impact of these workovers 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 are 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 on 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 to 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. And 2023 was another excellent year for reserves replacement. 78% of our production and reserves were replaced year-end '23 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'll see how those -- all the description of our offer activity, the production guidance and our CapEx, 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 just above like $1.50 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 market would show. In any case, we have 70% of our exposure to WCS with a hedge at minus $15. So it's fair to use $15 that's where most of our exposure is hedged at. In terms of gas, as you may have noticed, the gas market in North America as a whole, is a bit weak. There's a lot of production, including in Alberta and 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 Nino weather impact that's positive in terms of temperature [indiscernible]. 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 2 sensitivities. One on the WTI, WCS differential and one on the gas price. So with the 3 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 Nicki previously. So we're guiding a production of between 46,000 to 48,000 barrels a day. USD 437 million of CapEx, the bulk of which obviously is dedicated to the Blackrod Phase 1. And operating cost per barrel of oil equivalent 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 netback, 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. And the interesting point, obviously, is the difference between the free cash flow before the Blackrod investment and after the Blackrod investment. And 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 funded the 100% of the Blackrod CapEx in '23, it's going to fund again a good chunk of the CapEx in 2024, and that this 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 on -- for our Malaysian barrels, hopefully, a bit on the conservative side because we achieved between $7 and $8 in 2023, we're assuming we're setting our French barrels on par with Brent tiny bit less because 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 in -- 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 to $1 below the WCS. And the AECO, you can see is our assumption is historically below the last 3 years for a reason because the -- as discussed, the market is a bit weak right now. In terms of hedges, with, as usual, [ trade 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 -- our 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 USD 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 minus $15. It's in the money right now, as I was mentioning this morning, for those of you who listened, 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 WTI, 50% of the condensate we need to blend with our own production before we set it on par with WCS. And then we've been quite active on the FX front. We took the opportunity of having a reasonably weak Canadian dollar against our reporting currency, which is the U.S. dollar to hedge quite a bit of our OpEx, roughly 2/3 of OpEx in '24 at $20 million CAD per month and half of our OpEx for 2025 at $15 million CAD per month at [ USD 136 ] per Canadian and we've hedged a significant portion of the future CapEx for Blackrod as well between $132 and $135. 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 operating costs, as we guided at minus $18.2 and some cost of blending. So as you know, we need a 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 $19, which is the same, if I just -- which is the same almost as our operating cash flow netback or EBITDA netback. On the operating cost per barrel, you can see the trajectory. It's going to remain at or below $18 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 -- it's all very coherent, consistent and when you'll be, I'm sure, playing with your own model at different price decks, you realize that the base business is going -- 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 depreciation, some minor G&A. Happy to report that G&A remain 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 USD 0.5 billion of cash all of this cash is deposited mostly with Canadian banks, which -- and those deposits yield between 5% and 6%. So the $450 million 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 would compare that slide to the same slide last year, you realize that we're 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 minus $15. So obviously, we -- sorry, when we play -- when we increase the differential from minus $15 to minus $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 -- sorry, $1 per barrel in terms of operating cash flow or EBITDA. So a more significant one than the same on the oil price -- that 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 mentioned, and that's attributed 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 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 '22, and that was done also in anticipation that the base rates were probably going to increase. So that helped us locked in a reasonably low coupon at 7.5%. We tapped the bond market again in September last year. So the main question we had to answer the time from investors was, why did 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 pretty committed and almost fully undrawn revolving credit facility of CAD 180 million in Canada. So that puts us in the comfortable position or in viable position where we have more than close to $650 million between cash and access to cash to carry to deliver on our 3 strategic pillars, which are delivery of Blackrod, share -- continuous share buyback and to remain opportunistic as we've been last year with Cor4, if we can find some acquisitions which make sense. That's the end of 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 present value to you, and that's the result of 6 to 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 order 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 past -- over the first 5 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 5 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 Canada. So that automatically brings all of your forecast 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 NPV10 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 Chris have 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 bar producing assets. So our PDP, which is our producing assets doesn't include the development, is backed by almost USD 1 billion 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 2/3 of our assets are our producing assets, 2/3 of the value sits in our producing assets, 1/3 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 at last year and also funding some of our share buybacks and other shareholder-related activities. I can do it in 3 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 decreased 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 '18, we've got BlackPearl coming in there. Year-end '20, 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 '21 and year-end '22, 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 in 3 slides. Will?

Okay. So 2 more slides, well done, everyone, and 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, take calculated risks and go into places where maybe people are scared to invest into. And that company ended up merging with another company called Sands Petroleum that called -- to form Lundin Oil and Lundin Oil was eventually sold for just under USD 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 sole -- to sell the company for cash and shares to Aker BP for in 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. When we started the business, we were at SEK 32 per share. 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 to 48,000 barrels of oil equivalent per day. The game-changing Blackrod Phase 1 development is going to 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 USD 1 billion at USD 981 million. We've had -- the 2P value is greater than $3 billion using a 10% discount and the NAV per share is about SEK 244 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 a 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 USD 650 million in cash resources available to the company. We canceled out 7% of our shares last year. We're going to 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.

Yes. We will do the audience first. So someone wants to raise their hand, yes.

A few questions from me. First on capital allocation. You've definitely been very clever to handle your balance sheet and you're going 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 optimal capital structure for IPC? Should it be net cash, net debt or zero 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?

Yes, maybe you take the first one.

I take the second one.

Second one, yes. On the cash dividends, you've seen the free cash flow that we expect to generate coming once Blackrod Phase 1 is online is going to 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 I think we're going to have to see where we're standing in a few years' time to make that decision whether we want to continue buying back shares if we're trading at such a discount or click the dividend button. So no formal decisions made at this point in time. We are 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.

Yes. On the debt, I think one of the pitfall in our industry would be to hit the bottom of the cycle with too much debt on the balance sheet. So what you want to avoid. And you never know when the bottom of the market is going to show up, but you don't want to get there with 2x or 3x EBITDA kind of leverage. That's been the issue with some of our peers in the history. So we don't want to 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 a cash dividend, for instance. So I think that 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 -- and be in a position to sanction and deliver Blackrod almost irrespectively of what the oil price environment we would be in. So 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. And then 2 more from me, while I have the microphone. It's -- I think we all can agree and this has been on very positive story since spin from Lundin Energy. So where is the biggest risk as also with the business right now. And then finally, maybe a personal question to Will, you're pretty young CEO. Where do you seek advice?

Thank you, Teodor. And I think for the biggest risk for the company, I mean, there's no denying yet we have going to be spending a lot of money this year. It's a record investment year associated with the Blackrod project. We're going to be deploying USD 362 million into that. By the end of 2024, we're going to be 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. And with Chris and the teams in Canada leading this project and having the experience in the past of doing big projects, not only for the teams in BlackPearl, 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 going to be able to get through this the right way and manage the project the right way. So I think that's largely derisked. But I think -- that would be the main one to point out to as we're looking towards 2024 specifically. And 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 I try not to let my head get too big or have too big of an ego. You got to 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 in excess of 5 years now and being in the executive position for the last 3-plus years. So with an organic succession, 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 rule.

Just to add on, this is not from me. It was from Lucas in his old days, and [indiscernible] Lundin would say the same thing. The biggest risk I would say is not to own IPC stock.

A couple of questions from my side, as you would probably expect, is if I remember correctly, 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 refine, define or matured some of the scopes of work we have used up, but we're still sitting approximately USD 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 a name of the game and [ Bertam ] acquisition, we welcomed very good. What's about France? France is stable. We see the production there. We saw that you sold a couple of assets nonproducing and producing time producing in Canada. Are you open for more divestments?

And we very much have an opportunistic approach to M&A. As you know, Lars and 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, 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, we're not looking to do acquisitions that are going to 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. We're able to get to another acquisition done like we did in 2023 with Cor4 resources where you get immediate production oily weighted. That's what we're going to 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 going to 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 going to stay opportunistic.

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, on your lake and then Blackrod. If you just can confirm how much of your production of the current traction 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, prices are pretty low, I can't 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 oily company.

It's a great question. And so from a gas consumption standpoint, we consume roughly in excess of 20 million scuffs per day at Onion Lake Thermal asset. And Blackrod, when it's fully ramped up at peak production, we're talking about in excess of 40 million scuffs per day in terms of overall consumption. So the inflection point where we're actually consuming more gas than we're selling. It's going to be around [ 20-30 ]. So we're vertically hedged up into that point. 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 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 going to be coming to sale that are going to be at suppressed valuations. It's something that we are intrigued in, but we're not -- it's unlikely that we're going to 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 Nicki, 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 that. Can you a bit comment on that?

Yes. No, sure. And nice to meet you, Lars. No, it was 2 unique events we've seen. So we've had 2 well pump failures. Historically, the Bertam field has been highly reliable. And then we're still investigating the root cause, but they look like 2 distinctive events that we don't expect to be repeated.

Okay. And what about this year, generally speaking, we saw in Christophe'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 as 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 things really going. You said we are on budget. Obviously, we are on time. Can you give us a bit of probably a time table 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 going to continue to solidify some of our long-term contracts associated with egress of our deal bit 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 and additional getting 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. I think we'll see a progress update on where our SAGD drilling is the producing and injector wells are actually at. So those are probably 2 big things for '24, 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 say as a type curve in Ellerslie?

So it's also a great question. These do have a steeper decline type wells. So our type curves are in about 400 barrel a day well kind of IP 30, IP 60, and you do start to see some declines off.

What would you need to see happening $650 million of liquidity now to be comfortable enough to do and go with a special offer on the buyback side again as well, kind of how far would you need to be in execution of Blackrod how high an oil price? Or when could you think that that's [ able ] opportunity?

It's a good question, Tom, Eric. We don't have any firm particular target or timing or juncture specific milestone in terms of when we're going to do an SIB, and we haven't confirmed we're going to do an SIB, the beauty of doing normal course issuer bids 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 I think we have to see how this year progresses with respect to the Blackrod spend. And if we ramp up the NCIB, we'll have to see where we're at, but no firm commitments to doing an SIB at this time.

Okay. And also just a follow-up on Blackrod. I think there has also been mentioned that there is a contingency in terms of the timeline there. Can you comment 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 the 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 USD 90 million left in our contingency bucket of the total $110 million approximately that we had. The -- how quick could this production come on, could do 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 26 first oil and getting steaming a few months before that. I think that should answer.

Okay. 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.

We are able to take advantage of a relatively hot market in the middle of 2023 by selling some noncore 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. I think what's a 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.

[indiscernible] 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 it is going to be on stream and I do think it's going to 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 going to 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 it'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 potential for convergence between North American gas benchmark pricing and international gas prices.

[indiscernible]. Question regarding to -- regarding hedges. You said that you were considering or had considered to up your hedges? How should we think of hedges going into 2025? Is this a one-off here led to the large CapEx in '24? Or how should you think about it?

Yes. I think in terms of hedging the benchmark of 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% for 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.

Yes. 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?

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. We're going to want to 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 5-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 going to make more free cash flow for the next 5 years or we are going to make less. And if it -- if it's less than typically unlikely for us to go any further.

Yes. 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?

It's a good question and the beauty about having a diversified portfolio and Brent-related mix as well is 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 100% oily asset with super low operating costs, that would be great to do that, but also another key metric that we're looking at when we're doing acquisitions is it cheaper to buy back our stock versus this acquisition. So it's really got to be accretive, which can be challenging with those type of assets that are 100% oily and very, very low operating costs that typically trace premium.

Yes, me again. Just strategically, probably a bit early still, but so let's say Blackrod coming on in end of October and the full ramp up in '26 and then full ramp up. There are 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 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 you string 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 engineering, all the design will be a mirrored approach. So it is 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 going to 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 of scale going 30 and probably another 30, we could expand with the reserve life index there to do further stages. 80 is our current regulatory approvals, so we would have to get that amended. But there is a cost advantage to Phase 2, for sure, and also a schedule advantage. Exactly that amount of dollars, I don't know on the top of my head, but we definitely do see some efficiencies because we are using -- the road, for example, is a quick one. There's over $30 million into road infrastructure that never have to build again that 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 we don't pay more on a per barrel basis. So there's definitely some advantages. I hope that helps a bit.

And 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'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 assets. 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?

That does not make 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, you'll stop on a relative basis. And the contingent resources are relatively to develop so cheap that it wouldn't make any serious sense to do any realistically any more acquisitions, right? In the second phase, call it, in 5 years' time, notwithstanding a short-term acquisition like you did with Cor4.

Yes. We are of the firm belief that once we get closer to first oil coming online, I think the market is going to wake up a little bit and hopefully, we're going to 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 or is measuring in terms of what is going to give us the best bang for our buck. So I think that's quite an insightful comment on your behalf that if we're looking to acquire something that's got to be benchmarked against, well, one about Phase 2 at Blackrod on 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 versus an acquisition.

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 derisked depending on what we're looking at, hopefully.

[indiscernible] again. Just more on Blackrod. You currently have a very high on share. What do we need to see for you considering a farm down? And is that on the agenda at all before for first oil?

No, that's not on the agenda. I mean I think we found our partner in 2022 when we made $430 million in free cash flow. And before that period in time, we are contemplating getting a partner in to help fund this project as well as we are thinking about going 20,000 barrels of oil per day and fortunately, through the big cash generation that we had, had. We said, let's keep the pie for ourselves. We want to take this 100%. We're going to upsize this to 30,000 barrels of oil per day. And my late father before he had passed on when he told me about Blackrod, who he was always mesmerized by the asset and he always wanted us to go for go for it, go for it. He said 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 I think that's quite unlikely given that it's not in production yet. So it's very likely that we're going to 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 the -- with $850 million of CapEx and with the unwinding effect of the discount rates, when you look at the value of Blackrod between 2023 and 2026, it more than doubled, almost triple, right? So doing anything, losing some of the working interest in that asset, having to deal with a partner where 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 these assets.

Understood. That's clear. And then I talk a 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. Do you view that definitely share. But are you in a position to quantify or give some scenarios of how much you think that gas price in Canada may improve just because of increased LNG export capacity from North America and of course, obviously, strong gas in Europe.

The forward curve for AECO gas prices right now for just 2024, relatively in line with our what our budget state, which is about $2.13 per Mcf. So we're assuming $225 through Q1 and Q4 and $2 in the summer. And I believe once you're starting to get to the back end of 2025, that, 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 have a view beyond that.

[indiscernible] 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, that should ideally compress the discount. I think the cash flow, the valuation, there is a wide array of attractive attributes within this company. And so I 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 [indiscernible] or even if you 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 1-day blip, it's a steady rise up into that point in time. So you're able to form a long-term view. This is the company you want to be looking into for multi-returns.

Yes, 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 of 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 -- leaving one full build season ahead of us if we had to, if things slipped. So it's some third-party pipelines and then just a clean execution of the project.

One question. Onion Lake, I think you thought for some time about increasing the capacity from 14,000 to 16,000 in terms of processing. It seems like you're putting that on hold. Just interested in 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- to 5-year window, we are better off to delay it, push it out and just kind of 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 mentioned it, the drilling on the Pad L has been very successful. So we're in a situation where effectively the production capacity is slightly above the nameplate capacity of the facility. So 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've grouped together and reported 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 know where those numbers are exactly?

No, not something. He's referring to Ferguson, Mooney and Primary. Ferguson, Mooney and Primary.

And Suffield oil.

You have that one life saver [indiscernible].

It's a bit of a different grouping, Nick. Can we get back to you on that. Thanks. Okay. So we just got a couple of questions from the Internet. We do 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 comment on this? Can you please elaborate why your scenarios on future cash generation are based on a Brent price range of $75 million to $95 million. What gives management the confidence that the lower band is $75? And why do we use those 2 bands?

As you know, last year, our range was $70, $85, $100, we believe $85 was a bit too much. We didn't want to ask to answer the question, why did 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 is a form of a floor from OPEC Plus 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 -- it's reasonable to assume $70 is a form of a floor for the coming 3.5 quarter.

Yes. Thanks, Christophe. I think one other thing that giving you a range gives you is relatively linear when it comes to free cash flow generation at different price tags. So it gives you 2 bands 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 additional subsidies that oil and gas needs or expect from government in order to go ahead with some of these carbon capture projects and what would make sense for us as a company.

Yes, 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 an economic 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 going to spend about $1 million doing a comprehensive CCS study isn't mainly going to be at our Onion Lake Thermal facility. So we are progressing our understanding of it and how we're going to deploy that technology. But we do want to see some fiscal incentives improve beyond what's currently structured.

Okay. Thanks, Will. Chris, perhaps you could just answer or Nicki, 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 '24. The remaining work that is done in '25 is what 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 really spreads over the last $240 million.

Thanks, Chris. Just one for you here, Nicki, what can we expect in terms of Malaysia production. Now those 2 wells are on and producing well for 2024?

So we're seeing spot rates, as I mentioned, up at 4,500 barrels a day, and 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 this collection of a really, really strong team, and I'm fortunate to have made a really good relationship with a lot of these people in the company given I've worked in it for almost 6 years, I believe, now. So it's been a lot of fun. We're all pulling and we're unified pulling in the same direction. So I think the sky is limited in terms of what we can achieve and excited for the years ahead, can be happier.

Thank you very much. I think we'll close out there with all the questions. So thanks, everyone, for your participation in CMD, and we'll finish there.

Thanks very much. I appreciate the attendance, everyone, in listening into the IPC CMD. So that concludes everything here and look forward to having further engagements following this event here in Lundin. So thank you.