Okay, so welcome everybody to IPC's Capital Markets Day presentation for 2026. I would like to say thanks to everyone joining in person here in London today for the event and those tuning in on the web. We have a lot of material to get through today and an exciting outlook for the company, but before going into the agenda and the materials within the presentation, we'd like to show a little video edit that was recently put together just demonstrating the importance of energy and what's taking place at Blackrod as well. So a little five-minute edit we'll put up.
Every day, everywhere we go, everywhere we look, almost everything we use relies on oil and its petroleum products. As one of the most versatile resources available, it has transformed the world and helped create our modern society, the cities we live in, the homes we grow up in, the heat and lights we rely on, and the technology that surrounds us. It is used to produce the medicines that keep us healthy, the fertilizers that help us grow the food we eat, the phones that connect us, the bicycles that keep us active, and the roads that carry us toward the people and places that matter. Energy shapes human lives. International Petroleum Corporation is an emerging energy producer with assets in Malaysia, France, and Canada. In Canada specifically, IPC has embarked on a transformational development at its Blackrod asset in the province of Alberta.
The Greenfield development was approved in 2023, with first production expected in 2026. Phase 1 is designed to process 30,000 barrels of oil per day and targets more than 250 million barrels of proved plus probable reserves. Given the heavy nature of the oil, Blackrod uses an enhanced oil recovery method called steam-assisted gravity drainage, or SAGD. It involves drilling a pair of horizontal wells, an upper steam injection well, and a lower production well. High-pressure steam heats the oil, reduces its viscosity, and allows it to gravity drain into the lower production well bore where it is pumped to the surface. It's a process that reflects decades of human innovation and collaboration. SAGD recovery accounts for nearly 40% of Canada's total oil output. Its small surface footprint and highly efficient energy exchange make it a cornerstone of Canada's energy future. Blackrod is strategically positioned with access to major infrastructure.
With IPC's operations office in Calgary, fabrication facilities around Edmonton, and strong relationships with indigenous and local communities, this project is rooted not only in engineering excellence but in meaningful partnerships. Bringing a project of this scale to life requires precision, partnership, and planning. IPC turned to local fabricators in Alberta, leveraging modular construction to reduce on-site labor, increase efficiency, and enhance quality control. At IPC, our commitment to health, safety, and the well-being of our people and the environment is our highest priority. Our goal is to execute operations at Blackrod safely and efficiently, to deliver the project without harm and with minimal environmental impact. Under IPC's leadership, Blackrod's construction remains on budget and ahead of schedule. Civil construction, facilities construction, and drilling are all progressing as planned.
First oil from Phase 1 is expected in the third quarter of 2026, ramping up to 30,000 barrels of oil per day by the end of 2027, with future phases already on the horizon. With Phase 1 advancing and strategic planning underway, Blackrod is positioned to be a stable supplier of energy for decades to come because, in the end, energy is about people and the future we build together.
Fantastic. Okay, so with that motivational video that got put forward, I will then now go into the overall presentation. So starting with the agenda here in traditional format, I will begin with the overall introduction as well as the overview and strategy for the company. Then I'll pass it to Nicki and Chris, who will go into the operational assets as well as at the corporate level. And then Christophe will touch on the financial overview specifically for 2026. Following that, Rebecca Gordon will expand on the reserves valuation for the year. I will conclude with a summary slide, and we'll take some Q&A. So jumping right into it, to touch on the 2025 highlights after this slide, the majority of the presentation will be focused on 2026 and going forward. So what do we do in 2025?
I think the big achievement for the company was delivering first steam at Blackrod at the end of 2025. This was something that was ahead of our original expectation. We expected first steam at Blackrod in Q1 of 2026 when we sanctioned this project back in 2023. So it's a testament to the quality teamwork and execution overall at that asset. On the capital expenditure front, we spent $344 million for the full year 2025. It was the second highest capital expenditure program for the company, trailing the year prior to that. We're really now on the heels of the major investment at Blackrod with only around $30 million left to execute the Phase 1 development project specifically.
Delivering within guidance on capital expenditure as well as on production, the full-year production level for the company in 2025 was 44.9 thousand barrels of oil equivalent per day, close to the high-end CMD guidance range. On the operating expenditure per unit production, full-year costs settled in at $17.80. Good cost control overall there. Good production and average prices of around $69 Brent throughout the course of 2025 meant that we generated around $259 million in operating cash flow, which was slightly above our Q3 latest guidance between $245-$255. Balance sheet, we prudently and opportunistically undertook a bond refinancing at the end of 2025. That closed in October. We were pleased with that. That's $450 million of Nordic bonds, and the maturity of that now is in October of 2030.
We also have a revolving credit facility in Canada where we have around CAD 200 million available at this point in time. On the sustainability side, no material incidents throughout the year, which we're very pleased about. In the share repurchase front, we completed our share buyback program for the 2024-2025 NCIB, which a big highlight there in getting through that program is we now have less shares outstanding relative to when the company was formed back in 2017. To expand on the growth that the company has achieved in a relatively short period of time, I think it's important to have an understanding and appreciation in terms of where we started, how our track record looks, and what it looks like going forward. So in 2017, 113.5 million shares outstanding for the company. Now there's 112.2 million shares outstanding for the company. What's happened on production?
We've increased it roughly fivefold. Our 2026 production guidance is 44,000-47,000 barrels of oil equivalent per day. When the company was formed, there was less than 30 million barrels of 2P reserves. It's been an 18x increase to that number where we now have in excess of 520 million barrels of proved plus probable reserves. It's been a 4x increase on a reserve life index. Now we have a reserve life index in excess of 30 years. And contingent resources, zero contingent resources in the company when we were formed back in 2017. We now have 1.2 billion barrels of contingent resources, very much the feedstock for organic growth within the company. Share price was approximately $4 per share when the company was formed, and now we're up to around $20 per share.
It's been great growth within the company and really a key focus on increasing and improving and enhancing the per-share metrics overall. Expanding on the 2P reserves, 18x, as I had mentioned, in terms of the overall growth and reserves since we started. We've now produced 135 million barrels, which is shown in the light blue bars on this bar chart, which is a significantly higher amount than the starting 2P reserves. Also to highlight again here, the red shading between one bar to the next is the reserve replacement that's been achieved. Notwithstanding 2020, there's been material reserves replacement achieved by the company through a combination of acquisitions as well as through organic growth.
This is something that's not assumed going forward in our valuation numbers or our corporate cash flows in terms of achieving any reserve replacement despite having a proven track record of doing so. So what are we going to do over the next five years? If we just look at that 2P reserve position, we don't assume any contingent resource maturation and no M&A. Between 2026 and 2030, expect to average production of 62,000 barrels of oil equivalent per day. Between $65-$85 Brent, expect to generate between $1 billion-$2 billion of free cash flow. We have three key strategic pillars when we think about capital allocation for the company, which is organic growth, stakeholder returns, as well as M&A. I'm going to begin with the production growth. This is a slide that shows a little bit backward-looking, our current year and also forward-looking.
What's important to highlight within this chart is, of course, we have meaningful production growth coming. If you look at between 2026- 2028, we're expecting in excess of 50% growth in production as a result of the Phase 1 development project at Blackrod coming on stream. Represents around a 15% compound annual growth rate. And you can also see when we made this decision to sanction this project back in 2023, we made a deliberate decision to accommodate capital for the growth project at Blackrod as well as shareholder returns in the form of buybacks. And there's been very shallow decline overall, and that's one of the key highlights within the IPC portfolio. It's a low-decline business.
We've actually managed to keep our production per share flat through this period, and now it's going to grow quite high as we get Blackrod coming to first oil in Q3 of 2026. So this slide is an overview of Blackrod and really what's taken place over the last two decades. This is a classic story of long-term staying power. And when you have the opportunity to get exposed to vast resource-like an asset at Blackrod, you want to keep it. You want to maintain 100% working interest, and you want to keep putting capital into this asset through time to eventually get yourself into a position where you can sanction a development and extract and convert those resources into production and ultimately into cash flow and monetize them.
So I think what is also important to highlight on this slide is really that Pearl Exploration was the company that originally acquired some working interest in the Blackrod asset. And that was a company that was majority shareholder was the family in that company. That company ended up merging with a company called BlackGold to form Black Pearl Resources, which, of course, we're also a shareholder in the Lundin family was. And through the years, there's been a lot of capital put into the asset for delineation works, pilot facilities, shooting 3D seismic. Lots of wells have been drilled there. And notably, in September 2016 is when we achieved regulatory approval or Black Pearl did for the 80,000-barrel-per-day development.
There's been three separate Well Pairs that have been put forth at this asset, and all of them have been very successful, proving the commercial viability. Now we're finally getting to the stage where we're about to produce oil from the commercial development, which has been essentially around a 20-year journey. So very, very exciting to be getting to this point in time. On the Blackrod valuation itself, the 30,000 barrel per day development that we're embarking on for the Phase 1 project has 311 million barrels of 2P reserves. We saw a significant increase in 2P reserves through 2025, which Nicki and Chris will expand on in their section of the presentation. This 30,000 barrel per day development is an $850 million CapEx program to first oil. This project is very much on budget.
We spent around $820 million to the end of 2025, so very much de-risked. The value of Blackrod Phase 1 project is $1.4 billion using a 10% discount rate based on our latest reserve auditor price deck. The break-even of the project is sub-$50. It's around $47, WTI for the break-even. What's really exciting as well at this asset is, again, regulatory approval to bring an extra 50,000 barrels per day forward at this asset. The upside that exists is 1.142 billion barrels of contingent resources. Further to, as I had explained on the prior slide, through time with the money that's been deployed and maintaining ownership within this asset through the different vehicles, there's been a substantial increase in the overall recoverable resource. We're talking about an excess of 2x .
And even back a few years ago in the mid-2010s, about a decade ago or so now, let's call it, it was booked into reserves at a point in time as well. And so that really highlights that this project has been shovel-ready for a significant period of time. BlackPearl Resources elected to develop Onion Lake Thermal as opposed to going forward with the Blackrod development. And as a result of doing the combination with BlackPearl Resources that we did at the end of 2018, going into 2019, it was definitely very much a one plus one is bigger than two type of transaction, which has given us the financial firepower, of course, to go forward with this development. So what's valued today in our numbers is the darker part of the bar chart on the slide. And this is all upside that has not yet been valued here.
This is a contiguous, laterally extensive reservoir that's fully connected. So we very much believe in future phase expansions at this asset. Some of the recent history as well, we've learned big fields get bigger through time. Of course, as I had mentioned, we've already seen that at the Blackrod asset without producing a single barrel from the commercial development quite yet, but also within Lundin Energy at Alvheim Field, Edvard Grieg, Johan Sverdrup. These are the numbers essentially. On the left-hand side is at the time of plan and development and operation, the expected 2P reserves. Then at the time of the sale when Lundin Energy went to Aker BP, that is the cumulative production as well as the point-forward 2P reserves for the EUR. So there's been significant increases at those particular fields in the latest data points that we had.
On Onion Lake Thermal, coming from BlackPearl, of course, within the IPC portfolio today, also a significant increase in overall recoverable volumes there relative to the time of sanction. So we definitely are excited to see this bar continue to grow on the right side of the Blackrod chart as we continue to mature resources into reserves. Moving on to our second key strategic pillar as a company, stakeholder returns. So share repurchase has been an important part of the equity story within IPC. We purchased, repurchased 77 million shares since the company was formed at an average price of SEK 79 per share or CAD 11 per share. That equates to in excess of $1 billion in value created from all the share repurchase that have taken place compared to our current share price. So very value-enhancing by doing those buybacks.
The Normal Course Issuer Bid program for 2025, 2026 has been renewed. We do have the ability to purchase up to 6.5 million shares, which represents around 6% of the shares outstanding. We haven't been buying back at this point in time. We were made steadfast and focused on executing the Blackrod Phase 1 development. We're going to be monitoring oil price conditions throughout the year before we get back into buying back our shares. What's also on the slide on the right-hand side is showing the overall liquidity for IPC in both Stockholm as well as in Toronto there. So through 2024 and 2025, we've seen a pretty sizable uplift in terms of the value of shares traded, which was around $3.4 million per average trading day in 2024. In 2025, that uplifted to 5.1 million shares.
Looking forward into January and the beginning of 2026, we've also seen an increase in trading liquidity, which has been quite positive despite free float coming down and insiders not selling their shares. Cash flow per share growth. This is one from one of our close banks as well. We've taken this chart to demonstrate what we really believe is going to create a lot of value for the company, which is the cash flow per share growth in the years ahead. This is showing a basket of different publicly traded Canadian oil and gas companies. This assumes a $65 WTI price, $3.50 AECO, looking at 2026- 2030 in terms of the overall growth in cash flow per share on a CAGR percentage. You can see where IPC stands right at the top of that list.
Moving on to our third key strategic capital allocation pillar, which is M&A. And so we have a very profitable track record within IPC, all the assets that we have acquired and companies. There's been five separate transactions that have taken place in the company. Total acquisition price for all of these different acquisitions is around $940 million, excluding the Blackrod CapEx. Those assets have generated in excess of $1.2 billion in free cash flow, so essentially more than paid themselves back. And if we look at the free cash flow from our starting assets, those assets have generated a significant amount of around $450 million in free cash flow. So really an important metric for the company is free cash flow. And we're in this inflection point year here with Blackrod set to come on stream later this year.
We're going to be positioned to generate really meaningful and serious amounts of free cash flow, which is very, very exciting. This slide is a testament to that as well. What we're showing is the enterprise value of the company is approximately $2.75 billion. So this is a range of free cash flow sensitivities at different prices. You can see at $75 barrel, we're looking to liquidate our enterprise value through the free cash flow generation of the company based on our 2P Reserves. Of course, it's also important to note again here that we have a 30-year Reserve Life Index, and this doesn't assume any contingent resource maturation either.
Touching on the portfolio being very much weighted more so to Canadian oil, I thought it was important to give a little bit of an update in terms of how the outlook is within the Western Canadian Sedimentary Basin. So this chart on the bottom here is showing the total export capacity that exists within the Western Canadian Sedimentary Basin. The black line is the total supply forecast as well. The red line is the projected diff and the previous actuals for the differential WTI between WCS. So as we've seen with new egress capacity coming on stream, that's resulted in an excess takeaway capacity, an excess buffer, which has resulted in tighter differentials. We saw a differential of $11 per barrel average in 2025, which was one of the tightest years, actually the tightest year in the differential since the company stepped foot into Canada.
Also to note here with one of the most recent expansions to the export system in Canada, the TMX pipeline going to the West Coast of Canada, there's been a major uptick in the overall oil exports going to places other than the U.S. So I think that that's going to be a common theme going forward as well as there still is excess takeaway capacity going to the West Coast. And there also is low-hanging fruit opportunities to increase the takeaway capacity from that system as well. On the net asset value, when we started the company, it was $500 million roughly was the net asset value. If we look at our NAV as at the beginning of 2025 using the latest and greatest reserve auditor price deck, it stands at around $2.2 billion.
I think it's important to note, and Rebecca will also expand on that in her section, that there is a material pricing adjustment to the reserve auditor price deck. It came down around $10 a barrel on flat price, which was quite significant, and notably is a $62 oil price expected for 2026. We're in a situation right now where prices are much in excess of that. If we were to look at our net asset value using the year-end 2024 price deck or the prior year's price deck, our net asset value looks to be at around $3.1 billion, not any value assigned to the contingent resources of cap, of course. We see significant upside associated with that. Our market cap today is around $2.3 billion.
The power of the growth of the buybacks is a slide we do like to show, which really shows the value that you can create through share buybacks. So what this mathematical calculation is demonstrating, if all we were to do over a five-year period is use the surplus free cash flow generation between 2026- 2030 to buy back our shares, the point-forward value of the company coming at the beginning of 2031 at a $75 oil price would be around SEK 500 per share or CAD 74 per share. At that point, you'd be effectively private with 1 SEK of cash left over to be returned to shareholders. This assumes there's no insider selling taking place. In a more bullish scenario, at $95 oil over the next five years, we would be at SEK 950 per share, CAD 141 per share.
With some of the good share price performance as well, we've updated these share prices and really is a testament to what the power of the buyback can do overall for the company. With that, I'll hand it to Nicki to touch on the operations outlook. Thank you.
Thank you, well. It's my pleasure to take you through the 2026 operations outlook and then on through some of the asset detail with Chris Hogue, who will go through our Canadian assets. Just kicking off with our year-end 2025 2P reserves update and you're very happy to report it's been another excellent year for reserves replacement IPC with positive revisions in all of our operating regions. The 277% reserves replacement has been largely driven by our ongoing job of maturing the 2C resource of Blackrod into 2P reserves, and then we eventually bring those resources onto production.
Also at Blackrod, in the back of the very positive drilling campaign, we've seen an uplift in total volumes in the field. And you see that reflected both in our 2P reserves and in the next slide in our 2C contingent resources. So notwithstanding that increase to our 2P reserves and the maturation of those barrels from 2C, we have also seen an uplift in our 2C resources. We continue that track record of maturation from 2C- 2P reserves. But also we've increased the volume of our 2P resources, which are now sitting at over 1.2 billion barrels of oil equivalent. At Blackrod, we've acquired and secured some land around the Phase 1 development. And also, like I mentioned, on the back of the very positive drilling results, we've increased volumes there as well. So moving on to our 2026 investment strategy.
It's no surprise that the focus in 2026 is the startup and ramp-up of our very exciting Blackrod Phase 1 development. Elsewhere, there's a focus on production optimization. And we're really fine-tuning the next round of sanctionable projects at the other assets. And of course, at the discretion of the company, we can pull some of those projects forward if we feel the environment is right to do so. OK, so just moving on to our 2026 production forecast and very happy to announce our 2026 annual average production guidance of 44,000-47,000 barrels of oil equivalent per day. This is a guidance range that's very much underpinned by the performance and ramp-up at the Blackrod asset. And that's very clear.
If I just draw your eyes down to the chart here, you can see through the first half of the year, our production is at the lower end of our guidance range and then ramps up through the second half of the year as Blackrod's brought online. We expect to exit 2026 in excess of 50,000 barrels of oil equivalent per day. From an operating cost perspective, I'm very happy to report that our operating costs are stable. We've announced an operating cost guidance range of $18-$20 per BOE in 2026. So with that very exciting production ramp-up and startup at the Blackrod asset, it's no surprise that our capital expenditure forecast in 2026 is dominated by the asset. So we have around $90 million of spend in total at Blackrod in 2026, $31 million to complete the Phase 1 project.
To take advantage of the economies of scale during our current drilling campaign, we've added six sustaining well-pairs to that campaign. We've also made the decision to capitalize our operations costs until we reach first oil. It's just worth pointing out here, there's a very low cost to mature our barrels from 2C resource to 2P reserves at Blackrod. That's something we plan to continue to do into 2026. Just before I hand over to Chris to take us through some of the asset details in Canada, I just want to touch on our five-year outlook. On the back of the very exciting production ramp-up at Blackrod this year, we're forecasting our five-year average production to be 62,000 barrels of oil equivalent per day. In that period, we expect our operating cost to be very stable, around $17-$19 per barrel.
On the back of a significant period of capital expenditure, our long-term sustaining capital outlook is around $5 U.S. per BOE. You can actually see where we've been from a capital expenditure perspective in this chart here. So we've had the heavier spend during the Blackrod Phase 1 project. That comes off now as we start to harvest more free cash flow from the assets. The other thing I just want to mention here, this doesn't give any credit to the 1.2 billion contingent resources that we hold. We have a track record of developing these into reserves and bringing them online. With that, I'll hand you over to Chris for the Canadian asset overview.
Welcome to the Canadian asset overview. We're located in Western Canada, Alberta, and Saskatchewan. Our flagship project, Blackrod, is in what we call the Athabasca Oil Sands area, the largest oil sands producing area in Alberta. 2025 was a big year, lots of key achievements. I guess the first thing really is we achieved steam in December of 2025. We did that by using progressive commissioning. You don't need all the plant right away. You only need certain areas of the plant to start to warm up the reservoir by circulating steam down your drilled Well Pairs and getting the reservoir starting to heat up. So by doing progressive commissioning, we can do just that. We can get using some of the plant and then use the circulation from that operation to be able to commission the rest of the plant. So we'll dive into that a little bit more.
The workforce at site is approximately 300 people today. It is starting to come off from about a peak of about 400 people that we had. And it eliminates Q2 this year, we get down to wrapping up the project. All of our infrastructure to get our oil sales to market, being our diluent pipeline coming in, our gas coming in, and our dilbit pipeline going out, is all in place and ready to go. So we're just waiting for a ramp-up and we can start to sell some oil. Just to connect you with what we've built out here is a good visual kind of shows the tight, neat package to develop 30,000 barrels a day. So you can see right in the centre, that's the central processing facility that has a big water handling plant. But that's where you do recycle water.
You use all the produced water that comes back from the formation. You clean it to a boiler spec. You create steam and you steam all the wells from that facility. You see well pad A up to the top left of that slide. There's a drilling rig on there now. It's drilling the pad A south drilling pattern. You see pad B over to the right, which is completed and ready to go. We are steaming wells currently on both well pad B and on well pad A currently. Up to the top right of the slide is our construction camp. So that is not permanent. That holds about 330 beds. There's a camp just to the north of that that is our operations camp. That is permanent. It's about an 80-bed camp. And that remains.
Just south of that is our pilot facility that we've been operating for a decade and a half now. Really shows 30,000 barrels from a very, very tight package. How did we get from first investment to first oil as quick as possible? So the strategy was to do a bunch of simultaneous operations at the same time to ensure we can get that first oil as quick as possible. So there was a number of things that started at the same time. We only had engineering at a certain level of percentage complete. We had some regulatory work that we had to do from the beginning. But we were able to deploy that strategy to make sure we kept that time from first investment to first oil as tight as possible, which is key to the project. This takes into account a bunch of seasonal effects.
We had to build a road going into this project. It's a 32 km road. Most of it needs to be built in the wintertime because of the type of wet road that we had to deal with. All heavy loads had to be brought in in the wintertime when it was frozen as well. So the strategy for the construction had to take into account those seasonal type effects. You can see the man-hours now tailing off in 2026. We got a commissioning wedge of people out there. We are a prime contractor. So we've commissioned all this ourselves. We set our safety culture at the beginning. We've stuck with the safety culture. We've had over 2 million man-hours to date on the project. We've done it safely. So we've just really kind of held that safety culture as prime.
We're pretty excited about where we sit today to continue to bring wells on throughout 2026. Progressive commissioning. What does that mean a little bit? So we didn't need all the plant right away to start warming up the reservoir. So you bring on the pieces of equipment that you do need first. So you focused our engineering. You focused construction. You focused drilling on the places that you need to get your first type of wells on. So we're able to do that, get steaming, get warming up the reservoir, and then use those circulation returns to commission the rest of the plant. So it just works naturally and in sequence. Stage one is complete. We're circulating now. And stage two is well underway to start adding wells throughout the program. What are we producing? So we've got three drainage patterns online today.
So you can see on the right-hand side, B north, A north. So there are 30 well bores, 30 SAGD pairs there representing two different drainage patterns. Then there's A south representing the third drainage pattern. So between those three drainage patterns, we have the 40 wells that are included in the project. And we also have six sustaining wells that we will be drilling at the same time to capture the economies of success, the scale of economy, I guess, really, to keep things going. We figure it's about a 30% savings in drilling costs if we had to demob and then mob back to do those six sustaining wells. So we're continuing with that as we speak. Pad A south, sorry, pad B south is our future drainage pattern that we would look at some time in 2+ years from now. Steam chamber development.
Very key to ensuring that we are getting the recovery that we want. We need to sweep the oil from these drainage patterns. We need to sweep them very efficiently to run at the best steam-oil ratio that we can, extracting that 60% oil recovery that we expect to get out of the reservoir here. Making sure that you have conformance, good steam from heel to toe as part of your warm-up and steam chamber development period is very critical. What I'm showing here is the top right, you can see the two Well Pairs approximately 0-4 meters off the base of the pay. Then the well between the producer and the injector at the heel is about 6 meters apart. Then throughout the lateral, it is about 5 meters apart.
You start to inject steam down a long string and up a short string. You use the enthalpy of ensuring you get saturated steam to the toe of the well to start to heat the reservoir up. The bottom right is showing an example. So we have lots of eyes in the ground. We have fiber in the ground. So we have fiber that goes from the wellhead through the build section all the way out to the toe. And you can read that fiber real time, see what's going on. And we can monitor how we are doing in terms of warm-up practices out there. What I am trying to show there is pre-warm-up, you see a very cold blue pipe along the lateral section, heel to toe. And you see a red line about reservoir temperature around 16 degrees Celsius.
Right away on day two, after getting some steam going, you start to see saturated steam in 200 degrees Celsius range starting to heat up the pipe in the build section, the intermediate build section to the heel. After about a week, we've moved steam progressively down to about halfway through the heel to toe. And then at week two, we have optimized whereby we have saturated steam to the toe. And that is where you want to try to get to. You don't want to push more than required because you're just wasting steam. You really need to get it right to get saturated steam to the toe to ensure you're using that condensation from saturated steam to fluid as part of getting that heat into the reservoir.
Ensuring that conformance is consistent across the heel to toe for the entire drainage pattern ensures that we get the drainage that we're planning from this resource. Production ramp-up. A bit of an illustrative plot at this point, but it does bring a point of view to a few things. As we mentioned, we are ramping the wells up in steps. You can see us moving towards 40 wells over the course of the year. You can kind of see the production from the three drainage patterns starting to layer on. Within a 24-month period, we will be at our peak rate. Right now, we are planning to be at a 30,000 barrel a day peak rate by the end of 2027. Blackrod is a large, very homogeneous depositional environment whereby all wells look very similar. The reservoir is very similar across the entire play.
That's huge because we have over 1 billion barrels of contingent resource that you heard earlier in the presentation, which we haven't valued, we haven't looked at. But at our discretion and when we feel it makes sense, we continue to add drainage patterns. We continue to plan out and design how we'd like to drill the horizontal wells into drainage patterns to grow the project and mature resource into reserves. You can see in 2024, we added some drainage patterns. And again, in 2025, we've added some drainage patterns to continue to draw. And we're at the 311 million barrels of 2P today associated with the project.
And again, at our discretion, when it makes sense, the right time to use capital, we can continue to grow that resource, get ready for future other expansions of the existing facility, add another 5,000 or 10,000 barrels to the existing facility, or do a Phase 2 growth, a whole other 30,000-barrel phase, or both. So it gives us the ability to be flexible when it makes sense for us. Jumping off our Blackrod flagship in the Onion Lake Thermal, our other thermal project. It's operating between 12,000 and 14,000 barrels a day. Has been for a decade. It has those are the drainage patterns you see in the bottom right. You see the A through H drainage patterns. H is the next drainage pattern to do. The other ones are pumping and operating today.
In addition to those inside those drainage patterns, we use 4D seismic to figure out where oil hasn't been swept. There may be unswept areas. We're able to slide in infill wells, which we have done that. We're showing a few infill wells in there in 2025 to go ahead and ensure we're getting that maximum recovery from those drainage patterns. Then you can see a number of future drainage patterns. We got a large resource here as well that again, we have different capital projects whereby we could continue at this pace or we could accelerate some and put some capital into this facility, expand it, and bring forward 2,000 barrels a day on this project as well. Very exciting from there. Our results from our infill wells are excellent. The wells continue to pump in a very, very good way.
Suffield area assets. So we have a mixture of molecules down here. We have gas through to some heavy oil. We like the gas, a bit of a natural hedge against all the fuel gas that we do burn on our thermal projects. So it's nice to have that gas down there. What we've done here is just through good prudent workovers, both on the gas asset and on the oil side asset, we're able to keep that decline to a minimum without the right care and attention, the right focus to those ones. That decline would be twice as what it is today. We're able to do that very economically and keep those barrels on production. Continues to be a really successful story, these assets down here.
We have an inventory of drilling locations set in here as well that at any time we could drill when the price is right and we come improve the balance sheet a bit. We have some drilling targets here as well on the books that we can get at to both grow and offset further decline here. Just kind of wrapping up with our other assets. Most notably is our Mooney project. So it's an enhanced oil recovery. It's a polymer flood in northeastern, sorry, northwestern Alberta. It has been in the company portfolio for some time. We drilled it in three phases: Phase 1, 2, and 3 on primary horizontal production. It was very successful. We started flooding it with polymer in Phase 1 , had great results. We've moved the flood now to Phase 2 . We're starting to see very similar results as well.
So very exciting on what we're seeing there. And there's additional expansion in Phase 2 to continue moving that flood forward. So we're very happy to see the success we're bringing with that project. That comes to the end of the Canada asset overview at this time. Thank you.
Thank you, Chris. And just moving on to our international assets, and I'm just going to touch on Malaysia first. So on the back of a successful drilling campaign in 2025, the field development studies continue in Malaysia. And the focus really in 2026 is continuing the operational excellence that the team in Malaysia really have flown the flag for. And we've not had a material incident at FPSO Bertam in over 10 years. And last year, and once again, we've had facility uptime in excess of 99%, which is almost unprecedented for this type of facility.
On the bottom right-hand side of the chart here, oh, sorry. On the bottom right-hand side of the chart, I just wanted to draw your eyes down to this, which is a very important part of the story, not just at Bertam, but really shows what IPC do. So at original sanction, we sanctioned Bertam with around 13 million barrels of recoverable oil. And as you can see to date, we've produced way in excess of that. And actually, to the end of economic life, we expect to produce almost double that. And that's not a coincidence or by luck. That's through the continuing development or maturation of 2C reserves into 2P reserves and continual infill well drilling campaigns, which give you value for that total resource. And not just that, the operational excellence we see obviously then helps with the value story.
So this is a blueprint that we like to take forward in all of our assets. Moving on to France, where we also have a history of offsetting historical declines through infill well drilling programs. Although it's not budgeted or in the firm 2026 budget, we have firmed up the next round of infill well targets. We will sanction them at the discretion of the company when the environment's right. The next round of targets sit up in the northern part of the Villeperdue field and extension we call Fontaine-au-bron . So we have three well sidetracked there that will be sanctioned when we feel that it's the right time to do so. Before moving on to the budget summary, I just want to touch on sustainability. Safety performance is at the very foundations of operational excellence.
Operational excellence is something that we really pride ourselves on in IPC. I'm very happy to report that we've had no material incidents since inception. In 2025, we issued our sixth sustainability report. From a climate perspective, we remain on track to deliver our 50% net emissions reduction to 20 kg CO2 per BOE. We aim to maintain that through to the end of year 2028. In summary, for 2026, very happy to announce an annual production guidance range of 44,000-47,000 barrels of oil equivalent today. A range that's very much driven by the ramp-up of the Blackrod Phase 1 development. With the ramp-up of that Phase 1 development, our five-year business plan targets 62,000 barrels of oil equivalent per day on average. Our investments in 2026 really focus on bringing that asset online and ensuring the best possible, fastest ramp-up there.
We have the ability to ramp up our investments at the other assets. We will do if the right environment happens. From a reserves perspective, we've continued that track record of maturing our 2C resource into 2P reserves. We've had 277% reserves replacement year-end 2025, which takes our year-end 2P reserves to 521 million barrels of oil equivalent. With that, I'll hand you over to Christophe for the financial overview.
Thank you very much, Nicki. Good afternoon to all. For those of you who've been here for a few years, you know that we like to give you the opportunity to actually pick up the price deck you want to analyze IPC under. And so from a base case perspective, the market has told us what to use, essentially. So we're using a Brent price of $65 per barrel ± $10 for a low and high case. We've been a bit conservative using a $5 differential from Brent to WTI. And we've seen the differential between WTI and WCS slightly widening at the beginning of this year. So it was -11 last year. It is now currently around -14. I'll show you we have some hedges at -12.5.
But for the purpose of running our base case here, we're using -14 between WTI and WCS. And you can see the reference of the actual realized prices in 2025 on the right-hand side. For the AECO gas prices, we were a bit optimistic that it's going to continue to improve a bit. In 2025, the gas prices were a bit depressed. The storage levels were reasonably high. We're making not we, but Canada and Shell with the LNG Canada project are making progress. And they brought on stream the second train of that LNG plant on the west coast side in British Columbia. And so we believe that it's going to help unwind a bit those high levels on the gas storage. Long story short, we're using CAD 225 per MCF for our base case and across the low and high case.
But again, as usual, and to help you navigate and pick your exact in-house price deck, we're giving you as well sensitivities about what the impact on cash flows would be if the WTI/WCS differential was to widen or tighten by $3 per barrel. And same thing with the gas prices. We're giving you the cash flow impact of ±1 CAD per MCF impact on prices. Again, if you've been following our capital markets there over the last few years, you notice that we usually give a 2,000 barrels a day range for production. Of course, we're at this turning point where in Q3, we're going to turn on finally the production at Blackrod Phase 1. And the ramp-up is going to be reasonably steep and fast.
But of course, if you take ±2 to 3 weeks of delay or acceleration because the ramp-up on the production is very steep, it's hard to actually pinpoint only 2,000 barrels a day of production range. So we've widened it to 3,000 from 44-47 for the whole year. Very happy to report that we're finally off the peak investment years. We've had three heavy years of investment here until the end of 2025. We've spent $820 million of CapEx at Blackrod Phase 1 . We're going to invest only $122 million this year. And the bulk of it is really focused on delivering the first oil at Blackrod. Same comment for the production range and the operating cost range. We usually give our operating cost range. Here, we're using $18-$20.
The reality is that in the early days of Blackrod, sorry, the operating costs per barrel are going to be slightly higher. So that's why it's moving roughly from $18 in 2025 to $19, the midpoint operating cost per barrel in 2026. As soon as we get into 2027 with much more production coming from Blackrod, you should expect that operating cost per barrel to smoothly go down and reduce down to $18, if not below. So when you wrap all of these assumptions together, taking into account, of course, the gas prices, the revenue on a net back basis are in the range of $38, around $38, with operating cash flow of $10, EBITDA in the same range, just below at $9.5 per BOE, and roughly breaking even in terms of free cash flow at $0.2 per barrel for the whole year.
If you look at a bit more granularity approach, very consistent with what we've been telling you years after years, in Malaysia, we continue to enjoy a very strong premium over the dated Brent. We're assuming here that we're selling our Malaysian barrels at $4 premium over the dated Brent. The reality is that we tend to achieve and realize higher prices. That was the case in the fourth quarter 2025. And we've already sold our next cargo in March. And we've realized already a higher premium than four. In France, we're selling roughly on par, slightly below dated Brent. And for the Canadian heavy oil barrels, we're assuming we're selling exactly on parity with the WCS and a very small premium on our gas price, for our gas realized prices for the Suffield assets.
You know what we've been telling you in the past, and that's still very much the case. We usually like to leave our investors with the choice on how to manage their own exposure to commodity prices, with the exception of two cases when we would have significant debt maturities or when we would be in the process of massively investing. Those CapEx years are over. We've refinanced our bonds. So we have no material CapEx, no material debt maturities in 2026. That being said, the oil prices have been a bit on the weak side. And so we've been opportunistically taking advantage of some blip in the market to secure slightly better oil prices than in our base case.
So you can see here, we've managed to hedge 1,500 barrels a day of Brent at $66.7 per barrel, so higher than our $65 base case level. Same with WTI. We've hedged until the end of June, 7,500 barrels a day at $61.5 per barrel. Originally, in late last year, we hedged 5,000 barrels a day of the WTI/WCS differential at - 12.5. Frankly, the idea was to protect us, to protect the business and the cash flows against any potential leak or anything can happen on those pipelines. We didn't know about Venezuela. But the reality is that with a few barrels of heavy oil from Venezuela hitting the U.S. Gulf Coast, the differential has widened to - 14. That hedge protects us against that unexpected event.
You can see here that we've locked in some very decent gas prices for the summer period between April and October at CAD 2.8 per MCF. So again, what does that mean in terms of net back? Again, we're giving you those net backs. And so you can pick which production you believe is reasonable to assume for the whole year 2026. On that basis, depending on whether you're looking at the low base or high case, you will see in the base case here, so $38 of revenues net back with $19, which is the midpoint range of operating cost, it translates into a $10 per barrel of cash margin or operating cash flow. That compares to $15, almost $16 per barrel in 2025.
So you can see that if we can hedge a bit more at higher prices or if oil prices are a bit more optimistic, that will have a significant immediate impact, positive impact on net backs. This is hopefully an initial view of what 2027 holds for us. I was telling you that in the early days, the operating costs per barrel on Blackrod are a bit higher than on a normalized basis. So you can see that while production at Blackrod is ramping up in Q3 and more, significantly in Q4, the operating costs per barrel are driving down within that $18-$20 range. So you can expect that trend to continue into 2027. Looking at the operating cash flow, so we won't be paying cash taxes at $65 Brent. That translates into an operating cash flow net back of $10.4 in line with the cash margin net back.
If you look here in terms of profit before tax, once you've deducted our depreciation and depletion, some very light exploration costs, G&A, which remain at $1 per barrel, and financial items, which are reasonably constant at around $3, of course, a bit more or less depending on oil prices and how much money we'll have to use and draw under the revolving credit facility. That translates into profit before tax of -$2 per barrel in the base case and -$2 on a net profit basis as well. I think that's an important slide. Again, going back to how you want to play with your own model, you see that a widening or tightening of the WTI/WCS differential of $3 will impact your operating cash flow by ±$1.2 per barrel.
So that translates if you take the midpoint production guidance range, that would be 45,500 barrels a day x 1.2 is $20 million. So effectively, for $3 on the differential, that translates into an impact of $20 million of operating cash flow. And a dollar up or down, a Canadian dollar up or down per MCF on the gas price would impact our operating cash flow by ±$10 million. You can see here going from the operating cash flow net back to the free cash flow net back. So we're breaking even on the base case, but with some upside if differential were to be better or if we can lock in further hedges in the weeks and months to come. It's a bit sad.
But the reality is that if there is some political instability or tensions, we'll probably use those opportunities to hedge a bit more. The capital structure is reasonably unchanged. Effectively, what we did end of September and early October, we refinanced and so extended the maturity of our bonds. We benefited from good market conditions by then. And it was pleasant to see a lot of bond investors continuing to support us. So our coupon moved from 7.25%- 7.5%. That was really the result of higher base rates. But the credit spread shrunk at that time as a testament to the quality of the business of IPC and the strength of our balance sheet. The rest has not changed. We still have access to CAD 250 million revolving credit facility from our Canadian banks. Maybe just one word here.
Because we were able to book PDP reserves at Blackrod, we will have the opportunity to increase that Canadian revolving credit facility with our Canadian banks if we wanted to because traditionally, Canadian banks lend against the value of those PDP reserves. And now we have PDP reserves at Blackrod. And that's it for me. Thank you very much.
Nine years of Capital Markets Day. We're all going blind. Thanks, Christophe. So Will's taken you through our short-term cash flows and what we're looking to do in terms of strategy for IPC in the future. Chris and Nicki have taken you through the project, Blackrod. We're so close coming in Q3 this year and also our base production and how well we're doing on the base.
And then we've got Christophe, who's taken through our liquidity, strong balance sheet, good position, ready for the second half of this year, which is what we're all excited about, I think. And I get to do the fun part, which is the long-term valuation. Not as fun when you look at the long-term pricing forecast. But this is a pricing forecast that's put in place by our reserve auditors at a point in time, right? So Will was saying before that they came down to $62 a barrel in 2026. Well, we're at the beginning of February, and we're already at $69. So you can see that you can almost pick your price deck and decide where the value of IPC sits. But we think this is just a 2P position as well. Our value is a lot more extensive. And it's more extensive on price.
And it's more extensive because of our contingent resources. But we'll get into that also. And more than a $10 drop, actually. So for the first two years, you can see $15-$18 has come off the reserve auditors' price deck. And we're also off a bit on gas. It's clear that the reserve auditors and actually most of the Canadian market still think that the gas price will come back up to those sort of $3 levels. And Christophe explained a bit about the LNG Canada situation there, which should clear up some of that storage position in Western Canada. And so net present value. And so if you look at this graph here, you can tell at the bottom in the red line, this is the five-year average of the reserve auditor price deck that we use, which happens this year to be ERCE's rule.
We had an average of $80, which you saw in the previous graphs. And then that's dropped to an average of $70. But importantly, what I want to point out here is year-end 2024 sorry, year-end 2025. We're at year-end 2025. If we run that price deck at the year-end 2024 price so we just pull it back a year, you can see that our value goes from $3.3 billion at the end of year-end 2024 to $3.6 billion. And what does that mean? It means that technically, we've been extremely strong, and we have increased on a like-for-like basis the value of our underlying assets. And then we have a $2.7 billion, which is still coming up close to $3 billion valuation at the end of year-end 2025 using the new price deck. What does this all mean?
So my favorite technical words this year have been contiguous and extensive lateral reservoir. So if you look at what that actually means, you come from a technical perspective and we're economists in this room mainly. And you realize that what that translates to is reliable reservoir. And that translates to reliable cash flows. And that's why you see here between an NPV10 1P and an NPV10 3P, it's a really close range, right? So you can see the upside sitting there at $3.4 billion. And even on a downside case, you're still up close to $2 billion. And that is really a reflection of Blackrod and the reservoir that sits underneath all of these numbers. And we are mainly now an oil sands-focused company. You can see that 75% of our value sits in oil sands, 50% of it in Blackrod.
This is really important because it is the underpinning of long-term cash flows into our forecasts. Lucas Lundin always used to say to me, "Rebecca, you've never met a number that you couldn't discount." So he used to say, "Show me the cash flows." So here we go. This is it. This is the Blackrod Phase 1 cash flows from $65-$85 a barrel. It is undiscounted and before taxes. But what it does do is it shows you the longevity of these assets. This is how you create generational value. And this, again, is just Phase 1, right? So $65, you're going to generate between $180 million and $300 million of cash flow a year, between $65 and $85. And this is there for the next 30 years. We couldn't even fit it on the graph.
Then you will replicate this time and time again to create the real base of the company. Having shown you this, I'm then going to pass it on to Will to talk about how we're going to return value to shareholders, Will. There we go. Thanks, everyone.
Thanks so much.
No worries.
Great. Well, thanks very much, Rebecca, and the rest of the team for the solid presentation overall, creating generational value. It's what it's all about. And it's what we remain steadfast on executing and doing within the company overall here. So production 2026 guidance, 44,000-47,000 barrels of oil equivalent per day, an uptick relative to our 2025 numbers, largely as a result of Blackrod set to come on stream at the second half of this year. We expect a 50% increase in our average annual production from this year to 2028. That is coming very soon. Growth, Blackrod Phase 1, 311 million barrels of 2P reserves assigned at the Phase 1 project represents $1.4 billion in value using a 10% discount rate. Cash flow generation between $65-$85 Brent is $1 billlion-$2 billion in free cash.
Balance sheet, again, we've got the bond refinancing complete at the end of last year, as Christophe had mentioned, in favorable conditions. We also have CAD 200 million of revolving credit facility availability through our Canadian syndicate and shareholder returns in excess of 27% absolute share reduction since 2022 relative to where we stand today. It's really turbocharging that production growth and cash flow growth with less shares outstanding is really what we believe is going to translate into significant value creation for our stakeholders. M&A, five acquisitions since inception. We remain opportunistic at growing through M&A and safety focus. Again, no material incidents since inception, which is super, super important for us given that we are operators of all the assets that we have within the portfolio.
So I'd like to give a special shout-out as well to the worldwide teams in IPC for everyone's dedication, commitment, and hard work to a tremendous year in 2025. It's going to be a really exciting year in 2026 and the ones ahead. Of course, to the other IPC personnel that are here on the stage with me and also in the audience here, really appreciate all the commitment and hard work given to the company. We're very well positioned to create significant value for our stakeholders. So with that, we're ready to jump into Q&A, which we can field questions from the audience and then also can be submitted via the web.
Congratulations on a strong quarter. Thank you for a good presentation, as always. I have a question regarding Blackrod Phase 2 . What do you need to see from Blackrod Phase 1 before sanctioning the project? Thank you.
[audio distortion]
Yeah. Yeah. No, it's a great question. Blackrod Phase 2 , I think that resource is there. It's well delineated, well understood. So it's largely going to be a capital allocation decision that's going to take place to bring forward a material expansion. As Chris had shown in his portion of the presentation, we retain a lot of flexibility in terms of how we want to bring those contingent resources forward into reserves, whether it just be tying back to the existing central processing facility, expanding or debottlenecking the Phase 1 CPF, or developing a brand new CPF as well. So it's going to be a balance of looking at liquidity conditions, oil prices, and also seeing how the performance of Phase 1 comes along as well. And if there's any lessons learned that we can take into account from that into a future growth expansion.
Thank you, echoing all of a great presentation, as always. I have a question on the Phase 1, actually. Not being an engineer, we rely all on your estimates on time from first steam to first oil. So does the 6-9 months estimate still? That's still in play? The question is really, when in Q3 should we expect first oil?
Yeah, it's a good question. I mean, we haven't been specific on the exact month or date deliberately. I think we're really well positioned as things stand. And as Chris had shown in terms of the heat conformance that's starting to take place early out of the gates on some of the Well Pairs that we're circulating steam under, things look really good at this point in time. So we're confident to be able to deliver within that Q3 estimate for first oil. And depending on how things go, I think there might be a little bit of upside on that as well.
Clear. Thanks, Will. And in terms of funding, this is probably for you, Christophe, or both of you. I guess now, as you said as well, answering the question a bit, you probably are more capacity now given the 2P reserves that you have on Blackrod and strong balance sheet with less than $1 per barrel in 2P in debt in general. So to fund further growth, what do you consider the most in terms of funding opportunities? Strong access to the bond market, of course, but also probably more secure funding options as well.
Yeah. No, you're absolutely right. If we want to deploy further capital in our portfolio, we can raise more debt effectively. If we wanted to look at some M&A opportunities, that could be a combination of raising debt on the target and maybe issuing further bonds if those were very long-term cash flows. I think the reality is that in terms of leverage, whether it's early or later in Q3, when you get to first oil, that is when the business is going to deleverage. So in terms of trajectory, you should expect the leverage to continue to grow before dropping again. So it's probably not the right time to re-leverage right now as we speak. But effectively, towards the end of this year or early next year, it's something that we could consider if we wanted to sanction any new projects or consider M&A.
Yeah. Makes sense. Thank you, Christophe. Then the last one from me is on M&A. And do you have any comments on region and type of assets that you would be looking at now? Is it Canada primarily? And what type of asset would be a good target for you at this stage?
Yeah. I think our message on growing through M&A has been pretty consistent in the past and really hasn't changed as well where we have existing areas of operations. It makes sense to grow in those jurisdictions, mainly the likes of Canada and also in Southeast Asia as well. So these are areas of interest given the footprint that we have existing there and the relationships as well with the key contractors and people in place. But we are also opportunistic in growing elsewhere within the world. We've done a number of screening opportunities in other places outside of Malaysia and Southeast Asia, also in West Coast Africa as well. We've looked at things in Latin America also. So we really remain opportunistic at our core.
But I think also what I would add to that, too, beyond geographical location, is something that we'd be looking at, which we're interested in M&A, is something that's in production. We're very long resource as a company, clearly with all the contingent resources and the barrels that we have in place. So when looking at M&A right now, the priority focus is something that's in cash flowing. It's in production and ideally has low leverage to it as well.
Thank you.
[audio distortion]
Thanks for the overview. It's kind of a two-part question around your CapEx program go forward. So we see a bit of a step up in 2027. Is that just reinvestment back into the legacy assets? And then we see a material drop in 2029. Is that related to the timing of sustaining Well Pairs, or is there an asset that comes offline? Because it does bounce back in 2030.
Pardon me. You want to take that, Nicki?
Yeah. Yes.
2027 slide.
Generally, what you're seeing there is a combination of investment in the legacy assets, if you want to call them that, and also the next sustaining pad, so like an Onion Lake Thermal. The reason you see it fluctuate is because these pads come on between 18-24 months. You will see variations in the year. But I think what's notable here is the major step down from 2025 down into the future. That's what we're trying to highlight.
Gotcha. And then in 2028, when Blackrod's fully up, your corporate breakeven will improve materially. Do you foresee yourself becoming a dividend-paying company, or will return of capital be exclusively geared to buybacks, whether it's through an NCIB or an SIB again?
No, we retain the optionality ultimately, of course, in terms of dividends or buybacks. We really believe in the power of what the buyback can do, as I showed on the previous slide there. But when it comes to that point in time in terms of making the decision whether to go dividend or buyback, we're going to look at the return potential under both mechanisms, also compare that and weigh that against investing within the portfolio through an organic growth perspective. And essentially, what delivers the best set of returns, in our view, will dictate which form of shareholder returns we decide to pursue.
Perfect. Thanks.
Hi. I had a couple of questions. One is on, you touched on Venezuela and the widening of the spreads. I don't know if you could. What's your best guess as to the delta of barrels that could actually impact Canadian exports and maybe link to that the upcoming USMCA negotiations and what that do or not for Canada. Then the second question, given that the current price tag and it sounds like Blackrod is probably going to go post-payout later than you thought before, would the Onion Lake Thermal expansion make more sense? And when you think about acting on that? And then my last question is on gas. As you go towards the end of the decade and you become net gas consumer, and if your view is that gas prices are on the up, are you worried there, or what are your options?
I think Chris mentioned there's some inventory in Suffield area that could be tapped. I don't know if that's an option, but just generally trying to understand gas resource for you. Thank you.
Yep. Thanks very much. So I'll try and head those off, starting with your last one there in terms of the natural gas position. So we do enjoy being in a net long position on the natural gas position within Canada, which essentially means we sell more gas than we consume, which is ideal from a thermal producer standpoint. And then that net long position, based on the latest reserves that's been executed, looks to be around 2029 or so in that inflection point where we start consuming more gas than we're selling. And if we see gas prices go much higher relative to current levels, we are sitting on approximately 25 million barrels of contingent resources at Suffield, whereby we could increase additional natural gas production in the block there if prices were much higher relative to where they are today.
However, in saying that, it's a nice-to-have, and it's not a key priority to ensure that we're always in a net long position. If there's an M&A opportunity that has some gas components to it, that is a nice attribute in terms of trying to extend that net long vertically hedged position that we have. In terms of some of the other projects that we have within the portfolio, again, based on the reserve auditor price deck that we've seen, some of the expansion project Onion Lake Thermal we've pushed out into our long-term plans as a result of that.
What's really important in the company, given that we operate all the assets, is that we mature all expansion growth projects to the best of our ability to put the company in a position where we can decide which project is best to allocate capital towards when the time is right to do so. So that will be continue refinement work taking place throughout the course of 2026 on that. And then, of course, Blackrod's going to have some sizable expansion opportunities, which also will be consistently worked on.
And so within Canada as well and the differential outlook, I think what's important to highlight, if I just take a step up here and point to this graph specifically or the map, pardon me, from Canada and the Western Canadian Sedimentary Basin, the vast majority of the barrels that get exported from the country do land in this PADD 2 area. It's around 2.5 million barrels per day. And at this level here, there's no pipelines that flow up north going to this region and that PADD specifically. And the refineries are geared to take the heavier crude at that location. And then there's around 0.5 million barrels or so that goes to the Gulf Coast as well. And so this is the area where there could be some competition for Venezuelan crude.
When we entered the beginning of this year, the forward differential was around just $12.50, around just under $13 a barrel for 2026. The differential between WTI and WCS, as a result of the Venezuelan commotion, we did see dips widened by $1-$2, predominantly because of the potential competition of the similar grade, given that there's heavy refineries processing that type of crude in the Gulf Coast. But what we have seen is increased exports going to Asia and other markets as well. And I think what's interesting here is that with Venezuela, if it's no longer sanctioned cheaper barrels that are being purchased from China, then China is going to look to continue to increase and hoover up more barrels from Canada.
The logistics to get to Asia from the West Coast of Canada, as opposed to from Venezuela, is a lot more favorable from that point. So despite a slight uptick in the differential, we still remain very constructive and positive about the overall outlook. And it is also very much grounded in the situation where there is excess takeaway capacity relative to the supply. And with some of the commotion that's been taking place between the neighboring countries in North America, I think the large demographic of Canada recognized that need to have more flexibility and be able to have more diversification possibility to send more barrels away from the U.S.
And there's a number of major projects, the Northern Gateway project being one of them, which we're hoping to hear more about later at some point this year, whether that goes forward, which would be a 1 million barrel per day pipeline to enhance this overall, which is not assumed in these numbers put out. Curtis, it looked like you might either no.
Well done.
Great.
Thanks. Just a couple of quick questions. First, just on the buybacks. Over the past three years, you've fully utilized your buyback even when you were outspending cash flow. This year, you're pausing on the buybacks right now, even though you've switched to positive free cash flow. So just curious, what are you waiting to take place before you do start initiating buybacks? Are you just waiting for Blackrod to be completely built, or is there a certain WTI price in mind?
Thanks, Amir. Yeah, we're really taking a position of prudence when we're thinking about 2026. I mean, of course, our net debt has naturally risen as a result of the spending program that's taken place largely at Blackrod and the share buybacks that have been undertaken by the company. And so it's really going to be a level of monitoring oil prices, liquidity hedge room. Blackrod starting up, we do have that NCIB renewed. So it gives us flexibility to be able to reinitiate buying back shares. But for the time being, we feel the prudent move is to hold on shareholder returns for this very moment in time.
Okay. And the second question is just on Blackrod in terms of PDP reserve bookings. Was there any Blackrod booked last year in PDP, or is it all shifted into 2025? Is it fully booked in PDP?
Yeah. We had 2 pads that we got PDP recognition as we achieved steam circulation and first steam in December there. And we had some oil circulation returns coming that resulted in approximately 40 million barrels of a high-grading classification of reserves for Blackrod Phase 1 into PDP classification.
Okay. Thank you.
Hello. On Blackrod again, in terms of the ramp-up phase, what are kind of the key activities that may push the first oil back and forth that we need to kind of pay attention to throughout this year and the risks around them, please?
Sure. I can take that.
Okay.
Just make sure I heard your question correctly. But you're asking about what kind of key activities need to be underway to ensure first oil shows up at Blackrod?
Yeah. More like what are kind of the key elements of the ramp-up phase that could kind of push the time of first oil?
Got it. Yeah. Very clear. So we underpinned everything from our pilot. So Well Pair 3 had a warm-up cycle. And then we talked about that a little bit earlier on how much time we need to do before we will be able to put pumps in the ground to start the ramp or the production ramp. So we do have a strategy and a plan in place based on 10 years of operating out there already. And we're on that line. So the key things are once we need to confirm conformance. So after we put a volume of circulation in the ground over a certain period of time, we start doing what we call fall-off tests. And we start doing pressure cycling so we can confirm that we are having good conformance in our drainage patterns.
From heel to toe, we are seeing proper heat out in the reservoir. So that's our first indication before we can really move into production mode. So make sure that we do got good heat and conformance throughout the drainage patterns. That's one. And we believe, based on the strategy we have, there is a little upside there, but we're holding and underpinning what we've done with our Well Pair 3. So then the second piece to that is actually stripping out all the circulation completion and installing the completion for production. So that's the second big event that we need to do. And there's capital associated with that. And that is the next big thing to do. And we expect to start doing that kind of in the Q2 this year so then we can really start the ramp.
And that's when we call it our ramp to 30,000 barrels as we start to put artificial lift in the ground, these ESPs that we're using. That's the second component. And then the third, I guess, is, and we're already there on that one. We've kind of de-risked that, is just to make sure that facility is ready to handle all the oil production, the facility's ready to treat all the produced water that is coming back to it so we can create boiler feed water so we can continue to steam the wells and warm the reservoir up. So we're quite far ahead on that third step of making sure that the facilities are ready to go, but that continues. So that's kind of the three steps to get our ramp to 30,000 barrels. I hope that answers your question.
Yes. Thank you. And then on hedging, so some of the feedback when we did the bond issue was your hedging activities. And you've done some hedges already now. When you kind of move into a next phase when Blackrod is on stream, can you elaborate a bit on kind of what kind of hedging strategies you would consider?
Yeah. And I think, as Christophe laid out in his portion of the presentation, there's kind of two conditions where we're a little bit more open towards hedging, whether it be large capital expenditures or debt maturities coming up. And we don't have a strict hedging policy in place, but it is largely an opportunistic one. What we really did enjoy was back in 2022 when we had zero headline benchmark oil hedges in place. And of course, it's a $100 oil environment. We printed $430 million in free cash flow. So I think it's likely to expect that on Blackrod ramping up and looking more forward into 2027 and 2028, it's probably less likely that there will be many hedges in place as there has been in years prior.
Then on financial policies, like when you get kind of complete this year when you get more free cash flow generation, would you have any kind of target in place on leverage?
Don't have a particular target on leverage. We have said in the past that getting to below one times is a reasonable level that we'd like to be at. And I think through time, we're going to be going into a rapid deleveraging situation upon Blackrod ramping up. But there's no strict framework that relates to stewarding to an exact leverage ratio.
Okay. Thank you.
Okay. First of all, congrats on a strong 2025, and also thanks for taking my questions. I have one question on a topic you have already touched upon. As you showed on one of your slides, the NAV per share shows significant upside if cash is used for buybacks going forward. How do you balance the Phase 2 versus kind of aggressive share buybacks and capital returns given your discount currently to NAV?
Yeah. It's a great question. And bringing back again to that 2022 period where we generated a significant amount of free cash flow for the company, and we also progressed feed studies on the Blackrod Phase 1 development, we put ourselves in the position where we are in a net cash position. And we made the decision to sanction the Phase 1 development project. But we also scaled back some of the base business investment on our existing producing assets to accommodate for shareholder returns in the form of share buybacks. So what we're going to be doing is trying to strike that right balance. We feel like our capital allocation measures have been deployed in the right way previously. And it's always going to be looking at the lens of what's going to get the best returns and what's going to maximize the value for our shareholders.
Thank you.
Hi. Thank you for taking my question. I just want to follow up on the previous questions regarding buybacks in this year. Do you see a firm kind of oil price environment when you can unwind buybacks?
Appreciate the follow-up. We're not going to get drawn into a particular oil price specifically in terms of what will dictate when we go back in. We're going to be monitoring oil price conditions, liquidity hedge room, Blackrod progress, which we very much believe in to continue to go well. And when the appropriate time to do so to return value back to our shareholders in the form of buybacks will be a decision taken by the company.
All right. A brief question as well. Blackrod break-even, you guided it $47. Do you see any kind of cushion for this break-even guidance in the lower price oil environment, or?
Can you elaborate on that, please?
I mean, what kind of oil prices I mean, kind of is it reasonable to assume in the lower price environment that this break-even level could be lower in case, for example, input cost will be lower as well?
Yeah. It's a good question. I mean, obviously, you have things like chemicals that sit in your operating costs, which are then sort of oil price-dependent. There's a couple of factors like that. Big one is gas price. If gas price moves down, obviously, your break-even will also move down at the same time. So there's a few sort of dependent factors on price that will push that break-even at a lower level if you have a lower level oil price.
Okay. But what prices were used for this 47? Is it currently?
It's the crude price deck again. So your gas price is $3+. And then your, I mean, the chemicals price is at the current oil price, the crude price deck. We haven't messed with that for the break-even. So it's at the $70 long-term price deck.
So we're using the OPEX as they are in the base case. So we're reducing the WTI price down to the level where the NPV 10% would equal zero . That's how we calculate that break-even. Then you have two realities which are a bit contradictory. We look at ourselves as essentially a fixed price, a fixed-cost business until 2020 because in the COVID days, when oil prices were low, we realized that actually we could further improve and reduce OPEX. In a normal whatever that means, in a normal oil price environment, OPEX are reasonably fixed with the element of the gas price, which may go up or down. But in a very low oil price environment like 2020, we realized that actually we could further reduce our OPEX.
It's a very good question and a long way of explaining that what I'm trying to say, I guess, is that that break-even price could go lower in a lower oil price environment. But we have to keep all the assumptions the same to calculate the break-even to be intellectually correct.
Yeah. Thank you.
Okay. Is that it from the audience? Yeah. We have some questions from the internet, so I'll just run through those quickly. Nicki, perhaps you can comment on this one. If prices increase to $80-$85, do we have any sort of quick production wins that we could put onto the books from our base portfolio?
Yeah. Indeed, we have a number of opportunities that are ready for sanction. The pace that they would come on depends on which opportunity we decide to sanction. And again, that would be something that we look at at the time depending where we are with the Blackrod project and the general environment.
Okay. Great. Chris, just a question on potential Phase 2 execution time. About how long after sanction do you think we could get a Phase 2 up and running?
Yeah. Great question. We're able to utilize some of the existing infrastructure we have now to bring Phase 2 on, things like roads, things like some of the existing pads, the tank farm, the gas line, the diluent line. So we don't require the full timeframe that we had did before, but it's probably two years.
Two years? Perfect. And I might flip this one to Curtis, who's VP of Marketing from Canada in the audience. And the question is, how do you intend to market the Blackrod barrels, Curtis?
Thanks, Rebecca. So I guess our view is that landing heavy oil in Edmonton has never really looked better than it looks today. We have a number of refining customers as well as global customers that are really excited to see a new barrel come down there. We can move west. We can move east. And there's a really constructive picture right now in order for us to be able to get the best value for that barrel.
Yep. Great. And perhaps you can pass that to Ryan. Just Ryan, a general question about recovery factors for the Blackrod barrels at the 2P and contingent resource level.
Yeah. Thanks, Rebecca. And so just to tie back to a point that Chris made earlier, we have over 10 years of pilot history at Blackrod, which gets us very well grounded in what we can expect in terms of recovery factor and steam oil ratios. So Well Pair 2 and Well Pair 3 are both pointed to that 60% recovery factor range. So in terms of our base case, we're looking at 50%-60%.
Okay. Perfect. Christophe, just maybe on these operating costs, can you just explain how we expense them pre-production on Blackrod, how that works, and then how it will work going forward with Blackrod operating costs?
Yes. You can do it in a couple of different ways. But the most logical way is that you capitalize all the operating costs until first oil, which is what we're going to do. And so those capitalized costs are part of the CapEx program in 2026. From the day we turn on the commercial production at Blackrod, we'll be accounting for those OpEx as what they are, i.e., OpEx.
Okay. Perhaps we've got even more questions on M&A here. Obviously, Blackrod Phase 2 versus M&A, would you be looking at Canada? How would we fund that?
Yeah. I think it's the classic response in terms of capital allocation considerations and, again, what's going to give us the best bang for our buck. And we're very fortunate to be in a position where we are as long as resource as we are. So as we mature the development plans at the likes of Blackrod for future phase expansions, understanding what type of economic enhancements that's going to deliver to the business and being able to benchmark that against looking at M&A opportunities ensures that wherever the capital is going to be deployed is going to be the place that gets the best value for the company ultimately there.
Yeah. And one of my favorite questions so far, which is, commodity prices, if they go on a run, when do you no longer need to or want to hedge?
Yeah. No. Exactly. I think when I had mentioned in 2022, we were in a really strong position. The balance sheet was in good shape. Our leverage ratio was very low. And so we enjoyed being in a position where we gave our investors exposure to commodity prices. And I think that's a traditional theme across Lundin Group companies, generally speaking, as well. And so as we look to get a sizable increase in our overall cash flow generation coming from the Blackrod asset, it's likely to expect there won't be a lot of benchmark hedges in place. There may be things like differential hedges or other condensate hedges or things of that nature.
But in terms of benchmark hedging, likely looking forward into 2027 and the year beyond, subject to what's happening in the oil market conditions, of course, there's less likely to be a lot of hedges in place.
Okay. Great. A couple more have just come in. Yeah. It's probably Curtis on this one. Would you be looking at pipeline capacity for Blackrod to export barrels?
Yeah. We look at everything that comes out. I would say we don't need to have any particular pipeline product in order to bring our barrels to market or have future sanctions. So I'd say we look at each one independently. Overall, we're supportive, obviously, of more pipe. We'll help fill it if it comes at really good price. And the other thing that I'll say is that maybe sitting here today, we feel a little bit better about that overall long-term market with some of the constructive open season market that we've seen. So there's a lot of options out there, which maybe wasn't the case historically. So I'd say we feel a lot better this time this year as opposed to this time last year with what we've seen.
Great. Thanks, Curtis. We just have a question on M&A, which is, would we be looking definitively for assets that have tax balances? Quickest way to answer that is we have, at the moment, more than $1 billion worth of tax pools to use against our current tax. So we won't be paying tax anyway for the next 2-3 years at current prices. So not necessary for M&A. Always nice to have, but it wouldn't be at the forefront of our policy right now. One more question. It's on M&A, strangely enough. Are you also looking at Brent-linked jurisdictions like Africa, South America? Would we be looking external to Canada and the current jurisdictions we're in?
No. Absolutely. It's all on the table. Essentially, in looking at M&A, it's all about being very disciplined and very selective. I think there's a ton of value to be created from our existing portfolio. Given the business model that we have within IPC, it's very much one that is scalable. The capital allocation decisions that have been made to sanction Blackrod, we have been looking at growing through M&A over the past few years as well. There hasn't been the right opportunity that we've really sunk our teeth into quite yet. We will remain vigilant and persistent on continuing to screen assets and companies to look to grow through M&A.
Okay. That's it for the internet questions.
Fantastic. Okay. Well, thanks, Rebecca, and thanks for all the questions that came through from the audience and as well as in the web. It's great having a good attendance in the audience. I hope everyone enjoyed the presentation today as well as those who are tuning in. And we very much look forward to reporting at the next period, which is our Q1 results early in May. And with that, that concludes our Capital Markets Day presentation for 2026. Thank you very much.