A very good afternoon to everybody, and a warm welcome to all of our guests, our analysts and investors here in the room in Stockholm today. It's wonderful to be back actually physically doing our Capital Markets Day 2023 presentation. Certainly two years since we've been able to do this together. Also a warm welcome to all of the people that are tuned in via the webcast. My name is Mike Nicholson, I'm the CEO, we've got quite a detailed agenda for you this afternoon. I'm gonna begin by giving an introduction and an overview of the strategy of the company, then I'll pass across to William Lundin, who's the Chief Operating Officer. Will and Chris will walk through the asset overview in Canada, in Malaysia and in France.
We'll pass across to Christophe Nerguararian , who's the CFO, and he'll walk through the financial numbers and the forecast and the guidance for 2023. He'll pass then to Rebecca Gordon, who is our Vice President of Investor Relations and Corporate Planning, and Rebecca will talk about the latest reserves valuation that we've just finished off. We'll finish with some concluding remarks from myself. Of course, we'll open up and take questions from those here in the conference room today. You can also send your questions in via the web. To get started, really the focus of this afternoon's presentation is gonna be on the forward-looking guidance of the company. I just want to take a couple of moments to reflect on the highlights from 2022.
It was really the best ever year for IPC in terms of across all the metrics, production and cash flow generation and balance sheet strength. If we, if we look at the investment year, we've spent about $163 million of CapEx growing production across all of our assets in Malaysia, in France, and in Canada. That allowed us to lift our production to record highs. We actually touched 50,000 barrels of oil equivalent per day during the third quarter. Our full year production numbers were 48,600 barrels of oil equivalent per day. That was 600 barrels a day in excess of our high-end guidance that we gave this time last year. On the cost side, good delivery. Our guidance was $16-$17 per barrel.
The OpEx was bang in the middle of that guidance. A combination of very strong commodity prices and record high production meant that we generated by a long margin, the best ever cash flow performance of the company in our six years. Operating cash flow in excess of $623 million, and free cash flow of $430 million. Based upon the market cap of the company at the end of January, that's close to 30% free cash flow yield. Extremely favorable if you benchmark that against our other upstream oil and gas peers. That very strong operational performance and cash flow generation of course meant that the balance sheet has been transformed.
We've gone from a net debt position of just over $90 million now to net cash position at the end of the year of $175 million. When we add in the additional cash that we did from the bond issue at the beginning of last year, it means that we're sitting on a gross cash war chest of just under half a billion dollars. On the reserve side, it's been an incredible increase in reserves. I'm gonna touch upon that on the next slide. 13x production replacement and an 80% increase in our reserves to just under 0.5 billion barrels of 2P reserves. You're gonna see we're gonna continue our focus on our sustainability efforts. We're expanding our climate targets that I'll touch upon in a couple of slides.
To get started on the main part of the presentation, if we look at IPC's reserves growth, it's really been phenomenal since we started the company just under six years ago. Actually if we cast our minds back to that period, we were producing only about 10,000 barrels a day, and we had 29 million barrels of 2P reserves. Based upon that reserves, we had an 8-year reserve life, so we could have produced all of those reserves in 8 years. If you look at the light blue bar at the bottom of this chart, 83 million barrels produced. In 6 years, we've produced almost 3x that original reserve base. It gives you a sense of how quickly we have grown.
The big news, obviously the massive increase in reserves these last years has been largely driven by acquisition and M&A. What you can see in this just this year-end, we've significantly increased our reserves up by 80% to now 487 million barrels of oil equivalent. That's been on the back of the sanction of our phase one Blackrod project, as well as adding 16 million barrels from our Cor4 acquisition. I think the feature about IPC's reserve base is a very low decline reserve base, and you're gonna see that when we show the long-term production forecasts.
We've massively extended the longevity of our reserve life, and it's gone from 8 years, when we started 6 years ago, to now 27 years at current production levels with the inclusion of our Blackrod project. If all we do is develop that 2P reserve base, so we don't do any additional M&A, we don't mature another single barrel of contingent resources into our reserves. Over the next 5 years, from 2023 to 2027, we can actually keep our production very stable, just in excess of 50,000 barrels of oil equivalent per day. Post the funding of our Blackrod phase one development, we're able to generate at $75 per barrel Brent in excess of $700 million. At $95 per barrel Brent, we're able to generate in excess of $1.4 billion.
That's an average annual free cash flow yield of between 10% and 19% per annum. Quite extraordinary when you take into account the funding of our phase one Blackrod development. What do we plan to do with all of that cash flow? In IPC, we have 3 main strategic pillars, and the first is stakeholder returns. We're in a net cash position, so there's no opportunity to pay back any debt. What we've been focused on so far is share buybacks, and I'll come back to the reason as to why we prefer share buybacks. If you look at this next slide, you can see that there's a long history of shareholder returns since we started the company.
The only dilutive event that we've had was when we combined with Black Pearl Resources back in late 2018, and we issued just under 76 million shares. Since then, we're now in our fifth shareholder return with the NCIB that we approved in December of last year. We've bought back in aggregate a total of 53.3 million shares. The average price of that share buyback program over the last 5 years has been $0.58 per share. If we take the share price from the end of January of $1.125 a share, that's added in excess of $280 million in value to our shareholders. A total of just 20% dilution.
If you look at what we've been able to deliver with just that net 20% dilution, we've seen a 5-fold increase in production. We've seen a 16-fold increase in 2P reserves. We've added 19 years to our reserves life, added in excess of 1 billion barrels of contingent resources, quadrupled our cash flow generation. You'll see that we've added between $3 billion-3.7 billion to our net asset value with just that 20% dilution. What do we plan to do this year? Our capital allocation framework that we announced 12 months ago was that as long as the company's balance sheet is in good shape, and we define that as our net debt to EBITDA is below 1x, then we're returning 40% of all free cash flow to shareholders.
If we look at the cash flow guidance that we've given, the assets are still generating significant free cash flow. If you look at the $70 per barrel forecast, we're generating in excess of $140 million of free cash flow. At $85, the assets will generate in excess of $270 million of free cash flow. At $100 per barrel, close to last year's price, we're just under $400 million of free cash flow. Big decision, obviously, to move forward with our Blackrod project, which we're very excited about. $287 million of CapEx is forecast this year to commence the development.
When we look at the free cash flow after Blackrod development, we're looking at approximately break even at $85 per barrel, and we have in excess of $100 million of free cash flow at last year's oil prices around $100 per barrel. If we took our capital allocation framework strictly, we would be looking at really only distributing above $85 per barrel. As I mentioned in the summary, the financial position of IPC is as good as it's ever been. Post the acquisition Cor4 that we announced, we're sitting on gross cash resources of $425 million. We intend to use that balance sheet and that financial strength to return at least the 7% buyback under our NCIB through 2023.
If we look at the market cap of IPC relative to the 5-year and the 10-year cash flow that we're gonna go through in more detail in this presentation, IPC's market cap is just under $1.5 billion. If we look at set the free cash flow generation over the next five years into context, we can essentially buy back between 50% and 100% of our shares outstanding over the next 5 years and fully fund our Blackrod project and repay the $300 million bonds. Quite significant in terms of the financial strength. If we look at the step change in cash flow generation once we've got Blackrod on production and on plateau production over the next ten years, you can see it's between $2.6 billion and $4.4 billion of free cash flow.
We can effectively liquidate the enterprise value 2-3x over the 10-year period, and we're still gonna have material reserves and production beyond that timeframe. The second pillar of our capital allocation is M&A. We've concluded now with the announcement yesterday, five transactions since the company has started. If we look at this next slide, we show the four most recent transactions. The first was our Suffield oil acquisition. What we're showing on the left-hand side of this chart is the acquisition price. The light blue bar in the middle is the free cash flow that we've generated from those assets. The dark blue bar on the right-hand side is the current value on the 1st of January of this year as assigned by our independent reserves auditor.
You can see that across the four acquisitions, in total, $2.8 billion in value has been added from those four acquisitions. With a total consideration of $875 million and free cash flow generation of $635 million, we're not very far away from paying back all of those four transactions in aggregate. We look forward to updating this chart in 12 months from now to show the impact of the Cor4 acquisition, which I don't think you're gonna be disappointed with. Let me turn now to the third pillar of our strategic capital allocation. It's organic growth, investing in our massive contingent resource base, even moving the Blackrod 2C resources into 2P reserves. We still have in excess of 1.2 billion barrels of contingent resources.
If we look at the development over time, I think it's been one of the most impressive stories within IPC. When we started life just 6 years ago, we didn't have a single barrel of contingent resources. We had a big jump in 2018 when we concluded the acquisition of Black Pearl Resources. Blackrod back then had 744 million barrels of contingent resources. A year later, after we integrated the company, we did a deal with MEG Energy, and we acquired an adjacent land position to our Blackrod lands for $3 million. It added 244 million barrels of discovered contingent resources, so that lifted the Blackrod numbers to close to 1 billion barrels. Then 12 months ago, we went through third-party certification.
We integrated all of our latest technical data, and our latest pilot data from Well Pair 3, and we saw a big jump in our contingent resources on our Blackrod project to 1.3 billion barrels. Having taken the decision now to sanction the phase 1 development of Blackrod, we see our 1.4 billion barrels reduced to now 1.2 billion barrels as 200 million barrels has matured into 2P reserves. I think the last bullet on the slide should not be underestimated. Certainly over this last 1-2 years, I think energy security and access to resource has come into the fray, and that's certainly something that differentiates IPC. Our undeveloped resources sit in Canada, which is the second-largest resource holder behind Saudi Arabia, and behind Venezuela, and we're certainly not welcome in those locations.
It's a very stable fiscal regime. It's a very stable political regime. It's a very favorable fiscal regime for oil and gas investment. I think the value of this resource base is materially underestimated and very happy to start to mature that now with the announcement this morning of our phase one development. How is this project sanction going to change the company as we look forward over the next 5-10 years? I think on this slide, what we're showing is the impact on our production. As I mentioned, our five-year average production guidance is around just over 50,000 barrels of oil equivalent per day. We expect Blackrod to come into production late in 2026.
Once we ramp up Blackrod to its 30,000 barrels a day of capacity much more quickly than we originally anticipated, and Chris will talk about that in his presentation, we're pushing up towards 70,000 barrels a day in the early years, and then with a steady decline, we can still sustain average production in excess of 65,000 barrels a day over the next five years. Of course, this just includes the phase one development of Blackrod, and we've still got 1 billion barrels of undeveloped contingent resources. Clearly, there's scope for further phases to extend that production much higher than these levels that we're currently showing here today. Some highlights on the valuation of our Blackrod phase one. As I mentioned, the full field total resources were 1.3 billion barrels.
We've matured 218 million barrels into our phase 1 development. The Capital expenditure in nominal terms to first oil is now $850 million. That is an increase from last year's estimate of $540 million. We have seen some inflationary increases, but the biggest single component attached to the increases is some scope changes and some acceleration to ramp to 30,000 barrels a day much more quickly, and Chris will give a lot more details of that in his presentation. We've also prudently added a large chunk of contingency to make sure that we're able to deliver the project within budget. Again, Chris will go through that in more detail in his presentation. We've been piloting Blackrod now for in excess of 10 years, so we've got a huge amount of subsurface data.
We've got the team on the ground, Chris will talk about his experience. With Onion Lake Thermal, we've got the experience of having developed these types of facilities in the past. We've got the regulatory approval for a full 80,000 barrels a day project. Through FEED studies and looking at the optimization and how we can maximize value, we've decided to move forward with a much faster ramp to 30,000 barrels a day as part of our Phase 1 development, as opposed to the previous concept 12 months ago that initially saw us ramping to 20,000 barrels per day and then a number of years later, ramping to 30,000 barrels per day. That adds much more value to the project.
In terms of the profitability and the value proposition for shareholders, when we look at the overall net present value using our third-party reserve auditors price deck, Rebecca will talk about that later in her presentation. It's essentially an $80 per barrel long-term real oil price forecast. On an NPV ten basis, we're in excess of $800 million of value added. If we're using a net present value eight, that's in excess of $1.1 billion. When we look at the break-even of the project for phase one, it sits between $57 and $59 per barrel WTI.
Still a very robust project, and I think we feel very comfortable now with the extra additions that we've put into our cost estimate that Chris will talk about later to be able to deliver these numbers. When we put that all together now and we take the base 2P business and the value additions from our Blackrod phase one project, you can see the transformation and the huge value creation since the company started 6 years ago. Back then, our net present value or net asset value, using an 8% discount rate, was just in excess of $540 million.
With the addition of Blackrod and the net cash position, $113 million of net cash that we have, following the acquisition of Cor4, it means the company 2P net asset value, not a single dollar of value to our 1.2 billion of contingent resources is $4.2 billion or SEK 320 per share. If we've obviously seen interest rates increasing, if we move the discount rate to 10%, we see a $3.5 billion NAV or SEK 270 a share valuation. Again, with no future value associated with the 1.2 billion barrels of contingent resources that we have.
Again, to put that into context with our current company's market value of around $1.4 billion, that's a 60%-65% discount to our 2P net asset value. That's the company and through the value lens. If we turn now and look at the cash flow lens, I think you can see what a material transformation the base business plus Blackrod phase one can deliver for IPC. The first 5 years, as I mentioned, in excess of 50,000 barrels a day, will generate between $700 million and $1.4 billion of free cash flow or a yield of between 10%-19%. By the end of that 5-year period, at the current market cap, as I mentioned, we could buy back either 50%-100% of all of our stock.
We will still have 80% of our 2P reserves remaining. We're able to lift that long-term production forecast by 30% in excess of 65,000 barrels per day for the next five years. The true transformation in terms of cash flow generation that you can see in the next five years shows that we can generate close to $2 billion at a $75 per barrel Brent price or in excess of $3 billion at a $95 per barrel oil price. That translates into an average annual free cash flow yield of between 26%-41% per annum. Quite phenomenal numbers.
At the end of that 5-year period, you'll see from Rebecca's presentation that we'll still have 50% of our 490 million barrels of reserves remaining after that period. We'll still have 1.2 billion barrels of contingent resources. Quite phenomenal cash flow numbers. I think this next slide really kinda taps into, if you like, the Lundin history of how you can create value by acquiring resources, by finding resources and developing contingent resources and then moving them into reserves and into production and into cash flow and monetizing value.
What this slide shows is if all we do is as a management team over the next five years is we develop Blackrod, we don't do any more M&A, we don't mature a single barrel of contingent resources into reserves, and we take the surplus free cash flow over the next five years between $700 million and $1.4 billion and just fund share buybacks. Under the $75 per barrel case on the left-hand side, we assume a share repurchase price of SEK 115 a share.
Under the $95 per barrel price, we assume the stock price is more than double today's levels is SEK 215 a share.If you just walk that valuation forward and you have the CapEx behind you and you reduce the share count, our SEK 270 per share net asset value will grow double in the $75 per barrel level and will grow more than 3x in the $95 per barrel level. It's a very similar situation that we had in Lundin Petroleum when we were developing and sanctioning Edvard Grieg and then Johan Sverdrup. Once you get through those projects and get them into production, you see transformational increases in the value of those assets and in the company and in the share price.
I think even if we trade at a discount to those types of values in the years ahead, I think we're set for some very significant increases in IPC share price in the years ahead. My final slide on sustainability, in ESG, it's been very important to us to have a very clear ESG strategy that goes hand in hand with the company's growth plans. Very pleased that last year through 2022, we didn't have any material safety incidents or environmental incidents. Back in 2019, we set in place the commitment on our climate strategy to reduce the company's net emissions intensity by 50% over 5 years through the end of 2025. Just yesterday, during our board meeting, we sanctioned extension of that commitment now to 2027.
We expect to remain at 20 kilograms per BOE of CO2 now through the end of 2027. I think that concludes the introductory part of the, the presentation. I'll pass across now to William Lundin to go through the asset overview in more detail. Will, over to you.
Thank you, Mike. It's an absolute pleasure to be here today presenting our short and long-term business plans. As per the traditional format, I'm going to spend some time on our resource maturation strategy and talk about our corporate guidance. Chris and I will go into more detail on the work programs that we've set out in each of the countries of operations. Before I get into the meat of the presentation here, I'd like to personally commend all the IPC internal teams for the tremendous work done throughout the course of 2022. It was an absolutely incredible result, and it allowed us to shape our business the way that we have done so today. Drawing your eyes to the waterfall chart, you can see we had very strong reserve replacement achieved.
Approximately 220 million barrels of oil equivalent were matured out of our year-end 2021 contingent resource position into reserves. That was further supplemented by 16 million barrels of 2P reserve additions from the acquisition of Cor4 Oil Corp. Resources, which settles out at a 2P year-end 2022 reserve position just shy of half a billion barrels of oil equivalent. That represents a reserves replacement ratio of greater than 1,300%, a remarkable achievement, and consistent with our core strategy of maximizing our resource base through organic growth and through M&A.
It's important to note that not a single dollar, as Mike had mentioned, is assigned to any of the contingent resource volumes that we have left over, and no reserve replacement is assumed in any of the free cash flow projections or the valuation materials that are shown today, which will be further explained by Rebecca in her upcoming section. As Mike stated, our 2P reserves life index stands at 27 years. That's based on our midpoint guidance of 49,000 barrels of oil equivalent per day. That means that we can maintain that production level for 27 years, and that is approximately 70% higher than our RLI number last year and greater than 3x the reserve life index back in 2017 when the company was formed.
Drawing your eyes to the reconciliation table at year-end 2021, our 2P reserves stood at 270 million barrels of oil equivalent. We produced 17 million barrels throughout the course of 2022, and with the inclusion of the Blackrod Phase 1 volumes coming into our 2P reserve book, that adds 218 million barrels. You'll notice that's a slight difference from the 2C applied volumes to our Blackrod Phase 1 volumes, which was 217. There's a slight increase, which is the result of technical improvements. There were some other minor adjustments across the other portfolio, which was offset by additional reserves being matured at our Malaysian asset as a result of the PSC extension.
When you include Cor4 into the final year-end 2P number, the exact quantity is 487 million barrels of oil equivalent, with an 86% weighting to crude and 14% weighting to natural gas. Contingent resources, this is the feedstock to our organic growth. In the other Canada section, you'll see there is a bit of an adjustment there, and that's largely due to some land package expiries near the Onion Lake property. Then internationally, as I said in the prior slide, we matured our Malaysian PSC extension volumes into reserves, and that was slightly offset by an additional infill well identified within the Bertam field. That gives us a year-end best estimate of contingent resources of 1.162 billion barrels of oil equivalent, and that's greater than 2 times our large current reserve position.
If we take a step back and we put into perspective just 20% of the recoverable resource at Blackrod was matured into reserves, and that brought with it greater than $800 million worth of value. If we're able to extrapolate that across the remaining contingent resources that we have, you can begin to appreciate the quantum of value that lies within the contingent resource base and why it's a major focus in the company in maturing these volumes going forward. Our 2023 investment strategy with an established platform of high-quality producing assets delivering strong cash flow to the business, coupled with a healthy balance sheet, the stage is set for IPC to advance commercial development at our Blackrod property, and that's exactly what we set out to do to start this year. It doesn't stop there.
Growth through M&A has enabled us to be in the position that we are in today. Case in point, we've decided to enter into an agreement with a private company called Cor4 to acquire their business, which brings with it greater than 4,000 barrels of oil equivalent per day of immediate production just adjacent to the Suffield property. This is executed with no shareholder dilution, as well as at a very attractive dollar per flowing barrel metric. A key focus this year is going to be on integrating this asset into the IPC portfolio and unlocking the synergy potential within the Suffield operations and asset management teams.
Management has made a conscious decision to dial back some of the base business expenditure and push some of the organic investments to the right because we were able to buy production for today cheaper than what it would have cost to develop within our own portfolio. That really puts us in the position to have the flexibility of having a deep inventory of mature projects whereby if commodity prices strengthen, we'll be able to add more projects into the budget and really maximize the value going forward. Additional to that, with having nearly half a billion dollars of cash at hand, the multiyear Blackrod investment does not crowd out our ability to stay acquisitive as well as maintain shareholder distributions. Our 2023 production guidance is 48,000-50,000 barrels of oil equivalent per day.
You can see on the slide here, it's been an absolutely beautiful trend of increasing production year-on-year, and that has happened in tandem with a rise in commodity price environment. 2022, as Mike stated, was a record production year for the company, settling at 48.6 thousand barrels of oil equivalent per day. This guidance range does include the Cor4 volumes, additionally to that offsets substantially our natural decline. The investments that we do have planned throughout the course of the year are high impact, where we expect a production benefit at the front end of the year from our France development campaign, as well as from the wider Suffield area drilling program.
In addition, we expect the Onion Lake thermal sustaining Pad L to come in at the back end of the year and uplift some of the production at the back end of the year. Our diversified production mix this year is about one-thirds weighted towards natural gas and two-thirds weighted towards crude of varying grades, with about 14% of our volumes coming from France and Malaysia. Our operating costs, we are guiding a range this year between $17.50 and $18 per barrel of oil equivalent. It's a slight increase relative to last year's operating costs, which settled at $16.60. This is largely attributed to the reclassification of Blackrod from E&A to PP&E, and that's for the pilot operation specifically. That had a slight effect. These cost estimates also do include the operating cost associated with our Cor4 asset.
Within the operating cost structure, it does include provisions for maintenance and workovers, of which we do have a turnaround scheduled in Bertam in Q3, which is routine in nature. That happens every 2 years at that property. Christophe will show the evolution of our operating costs per barrel of oil equivalent on a quarterly basis in his section. Strong cost discipline is a key ingredient to our operational philosophy. We also ensure that we carry out critical maintenance scopes to ensure that we maintain high uptime, and this also ensures very safe and reliable operations. We minimize any discretionary spend, and we make sure that everything is activity-based across all the regions. It's a very robust budgeting process that is undertaken, and it ensures maximum profitability potential. Very exciting capital expenditure year.
The majority of the capital is going to be directed towards Blackrod. Chris has a great section of that within his Canada presentation. The rest of the base business expenditure is going to be allocated towards Onion Lake Thermal, where there's some carryover for the bottlenecking project, as well as to complete and tie in the sustaining Pad L. There's also some activity to take place within the wider Suffield area on the very exciting Ellerslie play. In France, we have some investments going towards finishing our development program, which comprises of a three-well infill program, pardon me, a step out program at the Villeperdue West field. We also have a Merisier sidetrack plan to take place within the Paris Basin. In Malaysia, we're spending money on maturing the next development plan there.
As I had mentioned on the investment strategy side, we've deliberately scaled back some of the base business expenditure because we're able to purchase production today, but there's a very mature set of projects that can add immediate production that we have ready to go on the sidelines. If commodity prices are to strengthen, we do have the ability to add that in if it meets the corporate objectives. We take a look at the business in a more medium to long-term lens. We're expecting to average approximately 50,000 barrels of oil equivalent per day for the next five years. At the end of that period of time, we'll still have 80% of our 2P reserves remaining.
For the ensuing five-year period, we expect to average 65,000 barrels of oil equivalent per day, and we'll have 50% of our 2P reserves remaining past that point in time. The long-term investment strategy, you can see what Blackrod does for shaping the business. We have a deep, deep inventory and long-life assets contained within the portfolio. Once we get through the Blackrod growth CapEx, you can see that our sustaining capital beyond that is expected to be to the tune of around $5 per barrel of oil equivalent. The remaining expenditure that we have planned for the next 5 to 10 years is really at Onion Lake Thermal, where we look to increase the nameplate production capacity from 14,000 barrels of oil per day to 16,000 barrels of oil per day.
There's also some drilling to take place within Suffield as well as at Ferguson. Some gas optimization activity as well. It assumes no further investments within the international assets that we have once the program is in complete in France. Quite an exciting and achievable business plan that again does not assume any reserve replacement. Now I'll transition to Chris to walk through Canada.
Thank you, Will. I'll walk you through Canada's 40,000 barrels a day of equivalent Canadian assets. Then we'll do a focus on our Blackrod development and then also a little bit on the Cor4 acquisition that we had. Blackrod getting lots of attention. First of all, just bring your attention to the map on the right-hand side. Blackrod is located in the southern Athabasca region of the oil sands area in Alberta. It's close to lots of infrastructure, roads, pipelines, both diluent, dilbit and fuel gas. It's strategically located from that perspective. It's a large resource. We have over a billion barrels that you've heard today, with 200 of it now matured into what we call our phase one development or our initial development area.
It still leaves quite a bit of resource left to continue to mature. How did it all get started? A bit of a timeline on Blackrod. You know, land was amassed in the late 2000s, and it was being well defined with stratigraphic holes and seismic to really understand the play and understand the delineate it and take a look at the resource. We started drilling pilot holes. We've drilled three pilot holes there now, so there's three well pairs, well pair one, two, and three. Each time, we've able to kind of progress the learnings associated with that development, whether it's the length of wells. We now drill 1,400 meter wells. You can see to the bottom right of the slide. The first pair was to the west.
It was about a 700 meter well. The second pair was to the north. It was a 900 meter well. Then our third pair has been 1,400 meters well. What we're doing there is looking at how far can we drill a well bore from heel to toe to really minimize the total number of wells that need to be drilled in the project, which again reduces the number of pads, roads, and above ground pipelines that have to go with it. A little bit about the pilot. The plot on the bottom left is showing Well Pair 2 and Well Pair 3. Well pair 3 being the one in excess of 800 barrels of oil per day. That's the 1,400 meter well.
It has, it is going along at a great SOR of less than 3 today. You'll see we're designing our commercial facility to about an SOR of 3. It's been operating less than a 3. We're really happy with the results today. A couple things you could see there on Well Pair 2 and Well Pair 3. Well Pair 2 is approximately just about 600 barrels a day. It was. We shut it in. The facility can only really handle 1 well at a time. When you do shut that in to drill the third pair. When you look at Well Pair 2 and you look at Well Pair 3 on a per meter drilled basis, production per meter drilled, they really overlay each other perfectly.
We knew we were onto something in terms of the completion that we were dealing with there. If I take a look at a 900 meter well at 600 barrels a day, and I look at a 1,400 meter well at 850 barrels a day, it's very close in the production per meter. We feel really good about the commercial design that we're gonna bring forward for the first phase of development. The overall commercial development plan at this time is, you know, it's an 80,000 barrel a day approved project. Original phase is gonna be a 30,000 barrel phase. We'll talk a little more about that. It originally was gonna be a 20 with an acceleration to 30. 20 with some growth to 30.
Through some economy of scale, we're able to start off at 30,000 barrels right out of the chute, and there's definitely some economics associated with that. You can see over on the right-hand side, that's our first pad. Some of the learnings that we've done with the pilot is we figured out well spacing, we figured out the length of the wells. That first pad has 32 well pairs on it. 16 well pairs going to the north and 16 well pairs going to the south on that first pad. 32 total well pairs. 40 well pairs will be drilled in total for our 30,000 barrel a day project. That's included in the cost estimates that we're gonna talk today.
You can see where it's located in terms of the Well Pair 1, 2, and 3, just off to the west. We have a schematic, just making sure we're very clear on the, you know, the type of technology that we're dealing with, SAGD. We've got two horizontal wells. They're about 5 meters spaced apart between the injector and the producer. We warm up by circulating both those wells. The injector and the producer gets a steam circulation. After enough of a steam slug, we're able to convert to true SAGD mode, where we are injecting into the injector and producing into producer with gravity drainage. A little bit about the facility is, we're starting off with 90,000 barrels of steam and 30,000 barrels of oil.
Approximately 12 months ago, when we looked at the project, we're talking 20,000 barrels of oil and 80,000 barrels of steam. As we'll talk through the CapEx movements, just keep that in mind. It's a plot plan of our first phase of commercial development, what we see here. What this is it's a modular designed facility. Everything is built in a shop and is brought out in sequence as per a construction plan. Everything is landed and put together in, you know, again, a very organized construction plan. It removes a lot of risk and seasonal problems of building in the field. We've done this before. At Onion Lake, and we'll talk about that project next. At Onion Lake, it was a 12,000 barrel a day build in two phases.
It wasn't quite this large, but very similar concept on how we did build that and the project management and the execution plan for that has been brought forward on this project as well. We built Onion Lake on budget and on time, both phases. We believe we kind of have the right learnings that we've brought forward to this central processing facility as well. We feel pretty good about engaging in it. It's an island power. What I mean by that is we're not connected to the grid here. It is close to, could be close to power. Again, we have lots of infrastructure in the area. The most cost-effective for power at this facility is going to be turbines with heat recovery units, and there's some efficiency around capturing steam with using those heat recovery units.
It's a cogen turbine-powered facility. Capital, movements in capital. Approximately a year ago, we were talking around $540 million to put on a 20,000 barrel a day facility. Since then, we've accelerated some scope. We've dealt with some cost inflation. We've developed the project through FEED and into some detailed engineering, so we're able to refine different work scopes to understand where our costs lie. We do got some contingency that you see is a major part of the increases, 'cause there is some unknown unknowns that we're gonna have to deal with. There is some further definition of work scopes that has to happen. That's where that 15% contingency at $110 million sits.
If we talk about the scope acceleration, which is key to the cost increase and why. On the facility side, we went from, like we mentioned, from 20,000 to 30,000 barrels a day. An incremental 10,000 of oil out of the chute versus expanding the facility at a period of years after the first phase. What we've done there is we've been able to do that without adding equipment or adding vessels. We're able to just upsize some of the equipment and the vessel size, so you get that economy of scale. We don't have extra vessels, we don't have extra pumps, we just have everything's a little larger. We were able to capture some economies of scale.
On a dollar per, on a CapEx metric in terms of flowing barrel from a capital build, we are more efficient with this particular design. Additionally, there was some new but surplus equipment that was on the shelf that we were able to capture, which gave us some further cost savings to help us with that CapEx metric. It really did help on schedule and long leads as well. There's a fair few long leads associated with this facility. We've captured, again, now we've had a lot of our long leads are in place. We've procured them. We understand the costs. We feel really good about the incremental acceleration in the facilities. On the drilling side of things, we went from 20 to 30,000 barrels of oil, so we require more wells.
We've had to build another pad, we drill eight additional wells, or sorry, a total of 16 additional wells have been added to the total scope from the 20 thousand barrel to the 30 thousand barrel. In addition to that, we have a bunch of utility wells that we've added in here. An additional disposal, additional source water, and also we're dealing with a salt cavern for the disposal out of waste that comes out of the produced water recycle system. We've added some drilling scope. We have our cost inflation, again, it's just been a stressed supply chain. I think the world has seen it, a stressed supply chain, so it's come with some increased costs, longer lead time when it comes to equipment, and we've captured it there in our inflation number.
Then again, contingency, a large portion there. It's about 15% of the project, and we hope not to have to use all that, but there is some known unknowns that do go on. We've done some things with our contracting strategies to manage that very well. Having that in place will ensure success, and we've ran our economics as such. Schedule. We start spending money. When do we get some, when do we get some oil back? When do we start getting cash flow? This year, 2023, we'll be doing detailed engineering, finish the procurement of our long lead equipment and line up when we expect to be able to get those delivered, and start fabricating in the fab shop, start putting some of the fabrication modules together. Gets going in about quarter three of 2023.
In 2024, we hit the field, we start doing some civil activities. We have a good road going in there now, but that road is gonna be expanded. It's gonna be built up, it's gonna be widened, and that will happen in early 2024. We'll also start building the leases. We'll start building well pad 1 and the CPF, so clearing the site, start moving the organics and the topsoil and then bringing in clay. In late 2024 and into 2025 is when we'll really start to build the facilities out there. We'll start to bring in all the equipment and stand it and start putting the modules together for the 30,000 barrel oil treating, 90,000 barrels of steam central processing facility. In parallel with that, we'll be drilling.
We'll have two types of drilling rigs out there. We do it in batch style, so we'll be drilling surface holes. You move onto a pad, and you go through that pad with one rig to do surface holes. You come back with another rig, and you go through that same pad, and you do intermediate and set intermediate casing. Then that, with that same rig, you go through the batch of wells again, doing your horizontal laterals. That allows us just to bring in the expensive tools in a smaller period of time versus having them sitting around on standby throughout the time to drill. In parallel with that as well, in 2024, 2025, we have some commercial requirements.
We need to bring in fuel gas, we need to bring in a diluent, and we need to take away our dilbit and tie it into a line that takes us into an Edmonton market. Those are progressing now. We've identified right of ways. Consultation is happening with the third party commercial requirements that we have. Those are advancing in parallel as well. First steam, late 2025, so Q4 2025. First oil approximately, you know, a year after that, which is late 2026. We have some belief that we hopefully will be able to be quicker than that on first oil.
We based on the ramp-up procedures that we've had at the well pair, we've factored that in, and so this is our best guess at this point. Onion Lake Thermal. You can see on the production chart, it's running now close to 13,500-14,000 barrels a day. This facility was built in two phases. It was built in the 6,000 and then another 6,000 and then a bit of an expansion. It was built on time, and it was built on budget using some of the same plans that we're going to use on Blackrod, so we got a lot of learnings from that. We're very happy with what we have here. We have a big resource.
It's a sustaining level to keep us in that 13,000-14,000 barrels a day for a long time. Lots of inventory, lots of resource. It's a nice sustaining cash at this point. The plots on the right-hand side are showing drainage patterns. We've drilled everything there that you see. Pad L is the most recent one that we've drilled. It has not came online yet. Have not required it. We plan to start to warm up some wells and put some production on later this year off Pad L, that drainage pattern. Suffield. The large yellow blob is really our land base, where we are on the Suffield base. You can see the different deposits that we are developing there.
What we're showing here is there's some, what we call our expansion to Suffield, taking account our comparative advantage of what we've been doing at Suffield. We were able to chase a play that was just west of us that IPC had some land on. We were chasing this particular fairway. There's this Ellerslie fairway. Cor4, which you've heard, a recent acquisition, we'll talk about it in a bit, was well developed into that fairway. It was a very natural transaction to acquire Cor4. The production that's coming from Cor4 is predominantly oil. It's 80% plus oil, may 18% or 20% gas on a production split perspective. You can see the production growth that we do expect on there.
Our Suffield asset on the oil side will be greater than 10,000 barrels for a period, quite a period of time. A little bit about Suffield, going back to the history of Suffield. Through just good oil optimization, the drilling of our end-to-end field that was in the existing Suffield, we're able to get reserve replacement in that 31 million barrels of, you know, organic reserve replacement throughout the years. Again, just from good oil optimization of the existing asset and looking where there was places to drill. In addition to that, with adding the Cor4 barrels, another 16 million barrels of 2P associated with that, we are about 47 million barrels of reserve addition.
The plots are showing a couple significance on the plots are the bottom left being the oil. You can see since the acquisition of IPC that the decline of those assets has really changed. That, again, is through optimization projects, working the well stock that we have out there, ensuring that those facilities are running with the highest uptime possible. In addition to that, drilling some of the plays that were in there, and we call that one is our end-to-end, which is a polymer type flood. On the gas side, very similar story. You see the decline that was happening, the work that went into giving the asset some love. Really, these are shallow gas wells. They fill up with water. They fill up with mud.
You need to take quite a bit of time to swab these wells and keep them flowing. It keeps our production rate quite up. You can see each winter, you can see there's always a blip down around November through February. There's always a blip in gas. A shallow gas doesn't come with a lot of pressure. When we get the very cold -20+ weather, we do get freeze offs, but everything does come back afterwards. Back onto the Suffield extension and the Cor4 acquisition, just a bit of a blow up there. The Ellerslie fairway was a play that we were chasing at Blackrod, at Suffield, and we were planning to drill a well ourselves this August.
Coming into that land sale, we did pick up some land that IPC was interested in to be able to grow that play. At the same time that we're watching that play develop, Cor4 was moving along that fairway quite well. That acquisition was very natural to want to bring them into the fold. We had about 10 development locations associated with the land that we had picked up. The Cor4 land has an additional 25 plus drilling locations. These wells are, you know, IP30s and greater than 200 barrels a day, and they recover around 200,000 barrels each. They're great cash flow wells. They're good production right out of the gate.
This year, we'll be drilling approximately 6 wells on that acreage in the 2023 year. Ferguson. Ferguson came through the an acquisition of a company called Granite, as you've seen in the earlier in the presentation. It's done what we expected it to do. It has a inventory of drilling locations. We tackled 16 of them. These are long horizontal wells. We tackled 16 of them in 2022, and we've brought them on production. You can see production has approximately doubled, peaked a little higher than that. We've had a little issues over the winter here with the cold weather, and we had some cold weather downtime issues, so the production had dropped off a little bit, but it is coming back now.
Again, we have an inventory of wells that are ready to go, and we'll drill them as cash flow permits. Conventional assets. On the conventional side assets, these are kind of primary producing type wells. Really what they do is they provide free cash flow for our growth projects. We go in there, we drill these wells. They typically pay out very quickly at the right price environment, and we use the free cash flow to focus on our growth projects. That's the base business and a focus on Blackrod and Cor4. Thank you.
Thank you, Chris. I'll spend some time on the Malaysian and French business and the assets that we have. For those who aren't familiar with the IPC story, these are the 2 main assets that IPC inherited upon spin-off from Lundin Energy back in 2017. As announced at the end of last year, we managed to extend our PSC in the Bertam Field for an incremental 10 years. That goes all the way up until 2035 now. It was a great achievement, not only for IPC Malaysia, but also for the host country as a whole. Our plan this year is quite straightforward, which is to deliver on our safety targets, our cost budget, as well as meet our production volumes. We'll also be looking to evaluate the next field development plan. Hats off to the Malaysia team again here.
They're continuing to fire on all cylinders, the operational team. They managed to deliver greater than 99% uptime excluding planned outages, which is a phenomenal achievement to continue to do year after year. We also had a very successful development campaign last year, where we did the A15 sidetrack as well as 3 ESP upgrades. You can see on the production plot the production benefit that we got from that program, where we had multiple months with excess of 6,000 barrels of oil per day. This program was executed in an environment where Dated Brent prices averaged around $100 a barrel. The high-quality nature of the crude from the Bertam Field commanded a premium of greater than $10 a barrel throughout the course of last year. That resulted in an absolutely rapid payback of the program of approximately 4 months.
You can see what the infill campaigns have delivered in terms of the ultimate recovery. It's really gone above and beyond what our pre-drill expectations were. Another point of significance with our Malaysian asset was in last year, we managed to achieve 100% reserve replacement, and this year we had an excess of 100% reserve replacement again as a result of the PSC extension. France, a very exciting time in France right now with development activity underway. We recently spudded the third and final well within the Villeperdue field, and following completion of that well, we will mob the rig to the Merisier field to execute a sidetrack, which is also within the Paris Basin. We're looking to continue to maintain a high level of operational efficiency and continue to mature our organic growth opportunities.
The picture to the top right that you can see, this is actually an older picture. It was taken in 2019 when we were doing the Vert-la-Gravelle development campaign there. You can see in the production plot the benefits, what we got from a production perspective from doing this program. The goal and hope here is to replicate the success that we've had with our current program in Villeperdue and Merisier. As a reminder, what we're targeting is a Dogger carbonates wells, formation, pardon me, in France, in the Paris Basin, within the Villeperdue fields and within Merisier. These wells are single-legged horizontal wells with approximately 500 to 600 m long drain lengths, open hole completions. We equip these wells with Beam pumps or pump jacks, and we have a lot of ESP in inventory.
Once production rates stabilize, we'll look to install the ESP to increase the output. Our current 2P reserves, the vast majority of them at this point in time are within the developed producing category. If the program is successful that is underway at this moment in time, there is the opportunity to increase undeveloped reserves with the locations that are currently held within our contingent resources. In summary, our production guidance this year, 48,000-50,000 barrels of oil equivalent per day. We have a robust plan that underpins flat production rates of 50,000 barrels of oil equivalent per day for the next 5 years, which grows to an average of 65,000 barrels of oil equivalent per day for the ensuing 5-year term.
The Blackrod Phase 1 investment is an absolute game changer and is a key component to the growth that we expect to see. We will continue investing in the base business to ensure that we maximize the value creation here, and we're all extremely bullish when it comes to the pricing outlook. What this does is it sets us up for continuous reserve replacement and overall being in a very, very strong position to continue shareholder distributions as well. With that, I will invite Christophe Nerguararian to come to the podium and go through the financial numbers. Thank you.
Thank you, Will. Good to see all of you again. Let's move on to some numbers. I think this slide is really important almost respectively of what is your view on oil prices or gas prices. This is a matrix that you can use to really plug in your own price deck, lower, higher, in between. It's essentially proportional and linear amongst those three cases. We've picked up Brent prices of $70, $85, and $100. We will also show you what is the impact in terms of sensitivities on cash flows in case you would wanna change the WTI, WCS differential. We will show you the impact on cash flows if that was to increase or decrease by $5.
Even if our AECO base case is using three and a half Canadian dollar per Mcf, you can see the impact of that gas prices being increased or decreased by CAD 1. With all this in mind, we will show you what the netbacks in terms of US dollar per BOE are in terms of revenues, OpEx, CapEx, free cash flow, or EBITDA. Using those different cases, you can really play with those numbers, adjust to the scenarios you would like to run. Translate that in free cash flow going forward. We're using as a base case $85 Brent with a $5 discount to the WTI and another $20 discount to the WCS.
You can see that in our high case at $100 with $95 WTI and $75 per barrel WCS. It's pretty much in line, that high case, with what happened in 2022. AECO gas price is lower. I'll come back to that. I've talked about the sensitivities. In terms of guidance, I reiterate what's been said by Will. With a production in between 48,000-50,000 BOE per day. We have a significant CapEx program, which is really comprised of $78 million for our base business and $287 million for Blackrod. We're guiding operating costs in between $17.50-$18 per BOE. It's really in line with 2022.
I'll show you why. The output I can mention already is just shy of $50 per BOE netback in terms of revenues. $21 of operating cash flow and $15 of free cash flow in the base case before the Blackrod CapEx for this year. In terms of realized prices, you can see here that we're assuming, so with a Brent at 85, we're assuming that we're selling our Malaysian barrels with a premium of $5. That we're selling our French barrels on par with Brent. That we're selling our Suffield and Onion Lake heavy barrels almost in line with the WCS.
A tiny discount on the Suffield. We're assuming for 2023 that all of the Onion Lake production is blended and sold on parity with WCS. The AECO price, you can see how it compares the CAD 3.50 to the previous year. Obviously in 2022 was much stronger, but the CAD 3.50 is essentially in line with 2021. We're using a modest premium for Empress of CAD 0.10 on average for the year. We are selling, as you know, our gas on the Alberta-Saskatchewan border. We tend to benefit from a premium there because we're closer to the end market, which are Toronto, Chicago, or New York.
In times where there are some logistical challenges or challenges to inject gas in storage in Alberta, we tend to benefit from a higher premium at our selling point. In terms of hedging, I mentioned this morning in Q4, we hedged a good chunk of our WTI, WCS differential exposure, we had some hedging gains. In 2023, we initially wanted to protect ourselves against potentially issues in the transportation of oil from Western Canada to the US Gulf Coast. That WCS quality in Hardisty is referenced as the WCS, and the WCS quality in the Gulf Coast is referenced as the ARV.
By hedging 60% approximately of our Canadian oil production between this WCS and ARV, we're essentially hedging ourselves against any issues we may face in terms of transportation costs for that part. There was a small leak on the Keystone Pipeline in December. Immediately, the transportation costs widened quite a bit in January. With that hedge in place for the whole of 2023, we already benefited from hedging gains in January 2023. Otherwise, for the rest of the year, it's relatively in line with that $10 differential we hedged at.
On the gas side, we wanted in the context of what we believed were reasonably high prices, in any case, decent gas prices in Q4. We didn't really anticipate that the winter would be so mild and gas prices would come off so fast. In any case, we hedged more than 33 million scf/ day during Q1 at in excess of CAD 6 per MCF. For the so-called summer strip from April to October this year, we've hedged the same volume at in excess of CAD 4 per MCF, CAD 4 per MCF for that period of time. Those are really the two hedges we have in place. No Brent or WTI hedges.
We don't have any covenants, you know, in our bank facilities to do that. In terms of other hedges that was on the FX side, the US dollar was extremely strong in the Q4 . Because we need to pay a good chunk, if not, all of our OpEx in Canada or France in Canadian dollar or euro respectively, we've brought forward some of those euros and Canadian dollars.
They're really in the money right now because the dollar strengths have come off a bit against those two currencies. If you look at the margin netbacks, I talked about in our base case for around $50 per BOE revenues and with our operating costs right in between our guidance at between 17.5 and $18 per barrel of oil equivalent gives us a cash margin of $22. Just want to explain a bit on the operating cost front.
You can see quarter-over-quarter, we have a small spike in the third quarter, which is just a function of a slightly lower expected production when we're going to have to shut down Bertam for the FPSO for a few days for regular maintenance. Otherwise, it looks to increase, and it marginally increase against 16.60 that we realized on average for 2022. The reality is that because we've sanctioned Blackrod, it's an accounting technicality, we are now reporting Blackrod. Even the Well Pair 3 is going to add to the revenues and to the OpEx on the P&L. Until last year, it was just reported on the balance sheet. Those costs were capitalized on the CapEx line.
By adding a bit of operating cost here, you bump up the $ per barrel. In terms of net free cash flow, it doesn't change. What it means in terms of operating cash flows and EBITDA, in terms of netback, you're around $20-$21 between $27 and $29 in our high case. You can see that it's. There is still some upside compared to 2022, which was a very, very strong year. There's still a bit of upside in our high case compared to 2022. In terms of net profit, in our base case, we're looking at $8.50 per barrel
I'll let you play with the numbers again if you want to, if you have a different set of oil and gas prices. I think this one is important, and again, we'll help you play with numbers and realize what is the impact of the sensitivity on the WTI, WCS differential. With a $5 increase or decrease, the impact on cash flows would be $2.3 per BOE or roughly $41 million. Same with a decrease or increase in gas prices. With an increase, the impact on revenues is $1 per BOE.
Of course, the operating cash flow impact is a bit less 'cause we're using gas as an input to our Onion Lake operations to steam the water we inject in the ground. It's in case this gas price would increase, it increases revenues, but it also increases some of the OpEx. You can see, we told you that on average, we are producing 3 x more gas than we're consuming, hence the ratio between the revenue impact and the OpEx impact. Net-net, a CAD 1 per MCF increase on gas prices will improve our free cash flow by $11 million. Whether it's operating cash flow, EBITDA or free cash flow, that's the same impact, obviously, $11 million.
This slide is important. I will let you spend some time if you wanted to. I think the one important number here on this slide is the base case and the free cash flow before Blackrod CapEx. We would be generating in 23 at that in that base case, $15 per BOE. After CapEx for Blackrod, we roughly break even at $85. Of course, cash is fungible. As we speak, we're sitting on $500 million of cash.
The funding of the Blackrod project for this year comes irrespectively from our free cash flow or from the cash at hand. In terms of capital structure, our balance sheet remains extremely strong, is unchanged for the last few quarters since we issued bonds. We're still fairly unlevered. We issued $300 million of bonds at a 7.25% coupon almost a year ago to the day. Our bonds are trading yesterday.
There was a trade at around 97.5%, so not so far from the par, which is important 'cause the base rates have increased, and what that means is our credit spreads for IPCO, for IPC have improved quite significantly. There is, we still have this very small EUR 13 million French loan, which we amortize on a quarterly basis, and a fully unutilized $75 million revolving credit facility in Canada. Maybe just to draw your attention on a few people in the past asked us whether Why we raised the bonds and why we were sitting on cash.
It's interesting if you do the math, believe it or not, for with capital guarantee, just overnight deposits, we can generate 4.5% on our deposits, whether it's Canadian dollar or US dollar. Effectively, with 400, if we place on deposit $480 million of our cash, that generates 4.5%, that fully covers the seven and a quarter coupon we were paying on our $300 million bonds, right. Everything being equal, it's, we don't have a cost of carry as we speak for the bonds, but obviously we're in a comfortable position with all this cash on our balance sheet. Thank you very much. Very happy to take some more questions later on, and I let you let Rebecca explain what's gonna happen in the next few years.
Okay. I have to bring my own presentation 'cause six years at IPC and I can't see the screen. Let's talk about reserves valuation. We've shown you a lot of numbers today, a lot of short-term numbers that Christophe's outlined. We've shown you our short-term budget production profiles. Will and Chris have taken you through a lot of detail there. We've also shown you our medium-term forecast through 5-10 years worth of cash flows and our reserves valuation. A little bit of information on what our major assumptions are behind these numbers, and we'll start with price deck. For our reserves valuation, we take a bottom-up approach. All of the assets, we bring in all of our technical profiles.
We apply, of course, the macroeconomic and the fiscal environment, and this is the major part, our reserves order to price deck behind our NAV 10 and NAV 8 numbers that we gave you previously. As you can see, 2022 was a bumper year at $100, and then there's some backwardation in the price deck there. It starts from $90 but then goes to an $80 long-term forecast. When we convert that to a WCS, Christophe has indicated in his short-term forecast that he's got a $20 WCS differential. Our reserves auditor also is using that short-term $20, and we expect that, as you can see by their forecast as well, that it'll come back to a pipeline differential.
There is Trans Mountain coming in the Q3 to Q4 of 2023, we expect that the barrels will move back into the U.S. strategic storage as well over the next couple of years. In terms of the Empress gas price, we've given you the hedging information there. The $6 that sits there in 2023, which is the reserves auditor forecast, we have actually got 30% of our Q1 hedged at that particular level, and then long term, we're coming into a CAD 4.50 long-term forecast there.
To the more interesting slides, and Mike has taken you through this as well on the 5-10-year forecast, our enterprise value of close to $1.3 billion, you can see that our NPV 10 of 2P, so this is excluding the cash component, 2.7x our enterprise value today. We've got a 1P that is 2 x our enterprise value today, and actually our enterprise value is pretty close to our PDP value for our reserves. Really important to see just how undervalued we are on these metrics. And if I can draw your attention to the slide on the pie chart on the right as well, because this is really important. You know that we've given you our Blackrod value, yeah, it's about SEK 94 a share.
Of our SEK 270 , which includes cash, so 262 without the cash, Blackrod is 25% of that value. 75% of our 2P value is backed by our current producing assets. Most importantly, Onion Lake in Canada, but also our Suffield, including our new Cor4 valuation. We've got Canadian tax balances. We will publish our tax balances, but I can tell you that that includes about 900 million CAD worth of future depreciation there. Of course, Malaysia and France, which are still producing nicely, as Will outlined in his presentation. From this value here, Mike has taken you through how then we convert from this 270 over the next five years. We use our cash flows of SEK 700 million to SEK 1.4 billion.
We can then convert that 270 into between SEK 500-900 per share by buying back our shares using this cash generation, which is phenomenal from our underlying producing assets. Also, of course, fund Blackrod at the same time. Very quick, we put this slide up because it is important to note that, you know, end of last year, we had a NAV of $2.2 billion. If we run at last year's price deck, our reserves of this year, not only did we generate $430 million of cash in 2022, but we've also managed to replace all of that value through organic growth acquisitions and also value replacement at our base assets.
You can see that actually we've got a small increase that goes to $2.4 billion worth of NAV there. Then, of course, a slightly higher price deck this year comes up to the $3.5 billion level that Mike has talked about previously. It was relatively quick, but we can then turn to conclusions from Mike.
Thank you very much, Rebecca, and to the IPC team for the very detailed presentations. Just one final slide from my side and some concluding remarks before we can open up for some questions. I think you've heard obviously last year was a record year for the company. We reached new heights in terms of production, we generated record cash flows. As Christophe took you through in his presentation, I think the financial position and the balance sheet of the company has never been better. I think as we look forward, the company has never been in a better position and has such a bright future to continue our long track record of generating huge amounts of value for our shareholders.
If we just recap, our production guidance for this year is 48 to 50,000 barrels of oil equivalent per day. That's a bump from where we were this time last year. We expect to be able to stay on average at 50,000 barrels of oil equivalent per day over the next 5 years. Once we've developed and put Blackrod into production, we're gonna see that long-term production grow by another 30% to in excess of 65,000 barrels of oil equivalent per day. Extremely positive long-term production growth coming from the business over the next 5 to 10 years. Will has walked through the reserves growth, the phenomenal increase from the decision to sanction our Blackrod phase one development. Chris went through in great detail.
We're adding close to 220 million barrels of additional 2P reserves. As Rebecca has shown on the value presentation, in excess of $800 million of 2P value from that project. As I showed earlier, as we continue to fund that project and the capital gets behind us, the increase in our NAV per share as we continue to buy our stock back increases exponentially. Value perspective, the 2P reserves value that Rebecca just walked through is $3.5 billion. She showed on a like for like price deck, we've still managed to materially increase the value. Of course, at the same time, we reduced and canceled the share count. 12% of our shares were retired last year.
Of course, if you took that into account, you're gonna see an additional 12% uplift in value. When we run our numbers and divide our 2P reserves value with a much lower share count, we're seeing today a 270 SEK per share net asset value. When you compare that against IPC's current share price of around 100 SEK per share, that's a huge discount to just the 2P net asset value. It assumes that we don't convert any more contingent resources into reserves, and it assumes that we don't do any more M&A. The balance sheet is in great shape. It's never been in better shape.
The net or the gross cash, if you like, post the funding of the Cor4 acquisition, has us sitting on a war chest of $425 million. Of course, that means that we've got the financial strength to really attack all three of our capital allocation pillars. We can fully fund our Blackrod development project, but we can still continue an aggressive shareholder return framework. This year, we've made the commitment to at least conclude the NCIB and buy back and cancel 7% of our shares outstanding. Of course, we're also in the position with that in excess of $400 million war chest. It doesn't crowd out our ability to do further M&A. We've generated huge value from M&A over the last 5 acquisitions that we've done.
We were very pleased to announce another acquisition adjacent, as Chris showed, to Suffield property. Very strategic, nice little tuck-in. Adds 50% to our Suffield oil production. I certainly believe that we've got the capacity to do further M&A in the years ahead. Last but not least, on our sustainability focus, we are very pleased that we've been able to extend the longevity of our net emissions intensity reduction targets through the end of 2027 as opposed to previously, which was by 2025. That concludes the presentation part. If I can maybe ask the IPC team to
We'll go to the audience for questions first.
to come up and we can, and we can take some questions from the audience here. Rebecca, you can moderate some questions f rom the, from the internet.
Can you go that side? Yep. You go that side, Chris. You go.
Okay.
All right. We start with the audience. Perhaps, Robert, if you can run. There we go. Lars is there.
Hi there. First of all, thank you very much for what you delivered in the last... When did you do the spinoff?
6
I was a shareholder day one.
Just under 6 years ago, Lars.
I remember with you and Christophe sitting there having a long discussion if we should keep this very small firm in the portfolio or not. Luckily, you convinced us, which, thank you very much again for that. Having a couple of questions, and I'll leave it to the audience and more further questions, is what about, as you said, we are bullish on oil prices. If throughout the year, we are seeing higher oil prices, is it more about production growth, what we heard from Chris, or is it more about shareholder return opportunities, additional shareholder return opportunities? Number one.
Okay. No, it's a very good question, Lars, and maybe I just pull up the shareholder return framework as a reminder. I mean, I think if you look at if we're in the $100 per barrel price environment, you can see that even with the funding of Blackrod, we've got around in excess of $100 million of surplus free cash flow. I'm not gonna say we've made a commitment right now to say that an SIB will take priority over organic growth.
I think what we'll do is at the time when we've got the confidence that we're gonna be generating hopefully a significant surplus free cash flow, we'll look at where is the stock trading, we'll look at the returns from incremental investments, and we'll allocate the capital to the activity that's gonna give us the best possible returns. The one thing I would say is when you look at now our 2P value inclusive of Blackrod. I think the math that I showed you when you walk through and you look at the multiplication effect that you get as you retire your shares, you know, we certainly wouldn't rule out further shareholder distributions in the $100 environment.
At SEK 250 a share price, you would consider some organic growth as well?
Potentially, yes. We messed up that problem.
Another question. Sorry. One follow-up directly on Blackrod. Was 30,000 really the ideal point? You obviously said there are some efficiencies. Was there consideration to go directly to 40 or 50,000? How did you actually come really up with the 30,000? Is it the ideal point of the cost versus benefit? How did you actually come up with the 30,000?
I mean, it. Through FEED, of course, there's multiple different development scenarios were analyzed, and we were looking at. It's, of course, it's a trade-off between maximizing value and also looking at the capital exposure. I think when you get to that 30,000, as Chris talked about in his presentation, this is very kind of modular. By upsizing the vessels, as Chris talked about, we found that that was really the sweet spot to get to in terms of returns and break evens. You know, of course, we could have gone straight to 80,000, but of course you look at the capital requirement, and that would have, you know, produced for us, it would have been just too much for us to swallow in one go. Really the 30,000 ramping quickly.
When into an environment, obviously we are, we're quite bullish on oil prices in physical markets. We can get there in three years' time. I think that combination delivered, for us anyway, the biggest, value proposition for shareholders.
Thanks.
Okay.
Thank you. It's James Hosie from Barclays. I guess on Blackrod, I appreciate your oil price bulls, clearly. How do you respond to the challenge that a $59 break even, a 10% NPV is too high, particularly for a project of that kind of long-term duration?
You know, it's a, it's a good question, James. I mean, I think sub $60 per barrel break even and still a full 10% rate of return is pretty good. I think as Chris showed in his presentation, it does also allow a certain amount of contingency in there. Of course, we hope to be able to do better than that. I think, you know, when you look at investing in a project with the balance sheet that we have, even if oil prices drop back for a number of years to $60 per barrel, we're still in a position to be able to fully fund that project. I don't think it, you know, it's not too big a bite, if you like, for IPC.
I think when you put it in context of the value creation that I showed as you get through the investment and the experience we all had in Lundin Petroleum when we did Edvard Grieg, and that's how you build companies. That's how you deliver exceptional returns. I think when you look at the value creation over just 3-4 years, once you've done the heavy lifting and you've put these projects into production, that exponential impact, I think, is difficult to replicate through just organic growth or share buybacks. Yeah, it's that kind of transformational growth that's really driven us to move forward with a sub $60 per barrel break even project.
Okay, thank you. I could follow up then. You sort of mentioned a contingency. Could some of that almost come out this year as you identify some of the known unknowns? How fixed is that kind of budget now? Are you effectively locking in contracts for the whole project at this point? Is there points over the next couple of years where you can adapt the project subject to the market conditions?
Do you wanna take that one, Chris? Or.
Yeah, sure. Sure. Yeah, as work scopes do get completed, we should be able to take some contingency off the table. As each year progresses, we'll be able to lower that contingency amount. We are working on contracts this year to be able to kind of lock in the scopes. The contracting strategy does deal with some lump sums, does deal with some target prices, different ways to incentivize the vendors and contractors to kind of work with us as one team. We will have the majority of our contracts put together by the end of 2023.
Thank you.
Thank you.
Thank you. Jørgen with Pareto Securities. Thank you, first of all, for the presentation. Second, I was wondering with the Blackrod, Chris, you mentioned that it might go a little bit quicker than what you showed on the board. I was just wondering, what sort of milestones do we need to look for? What needs to go according to plan for that to go quicker than the end of 2026?
Yeah, good question. Mike jumps to the schedule. So it's really field activities that need to get done. Everything that we're planning to do in the shop, in the fabrication yard, that schedule will, you know, should be very close to what we've planned out just because it's in a controlled environment. When we do hit the field, there is some a little bit of time in there that if, you know, we had good weather, goes with us, that will help. You know, we'll gain some weeks, some, a month or so in that type of thing. We, it's really field seasonal type activity while we construct out there. We're playing with our workforce to man up at the right times and not to over-man up.
Just make sure we're as efficient as possible through that. It's really field execution that could, you know, bring the schedule in a few months early.
Great. Thanks. I think William mentioned that it's actually now cheaper to buy production some places than actually develop it. We've seen a lot of activity from you in Canada lately. Are you seeing the same trends elsewhere, or how are you looking for future M&A activity and that sort of thing?
No, go ahead.
Yeah, you know, yeah, I think, we cast a wide net, so we're not wedded to one particular jurisdiction. Obviously, we've got a huge business in Canada. We've got a lot of capability, you know, across conventional, across EOR and across the thermal business, and we've got a big team in Canada. Curtis, who's here, was kind of driving a team that just delivered the Cor4 acquisition. I think we're always just given the size and scale and the number of deals that we see in Canada that there's gonna be a focus. Still, internationally, there's no question the majors are still looking to the energy transition. They're still looking at disposing of some of the assets that they have within their portfolios.
We've been involved in multiple processes, you know, still looking at assets internationally. Thus far we haven't been able to do anything about, apart from the 25% of our Bertam project that we picked up for zero. That was a nice one. Yeah, we still continue to cast a wide net, and I think the success of any of the Lundin Group companies, it starts with asset quality, and it starts with the subsurface rather than jurisdiction. If we can find the right asset for the right value proposition, then we're happy to bring that into the company.
It's fair to say, as you mentioned, a quarter ago or two quarters ago, that when we look at M&A, we focus exclusively on production and cash flows. We have enough development on our plate. That's a way to increase cash flows and also give us the opportunity to deploy more capital to buybacks and shareholders' return.
Great. Thanks. One final question from me. You have been quite successful with hedges lately. Do you have a strategy, or is it more looking at what's going on in the market at the time?
Well, if you take the gas hedge, for instance, we felt that if gas prices were to stay at CAD 6 and we hedged only at CAD 4 during the summer, given that it's only a portion, nobody would be extremely upset that we underperformed a bit. That. It's always a matter of maybe we want to protect the downside more than fully benefit from the upside. We believe, like, when you look at some transportation risk for the Western Canadian barrels, there is more risk, there's more downside than upside, so we're happy to forgive a bit of, forgo a bit of upside, protect the downside. That's been what, that's been our strategy so far. It worked very well in 2022.
If you look, we hedged WTI, WCS at $13. We lost, a bit of money in the first 2 quarters, but was generally happy days to see a differential at $11 or -$12. Again, when there is some screaming imbalance, you know, in our view between the downside and the upside, that's usually when we act.
I think that's a fair comment. Certainly we haven't hedged the FX in the last 6 years. When we saw the, you know, the real strength in the US dollar late last year, and of course our euro exposure and our Canadian dollar exposure, we just felt that there was. It was a bit asymmetric. We decided it was a little bit opportunistic in that respect. I think, I think the big question in terms of the benchmark that Christophe showed in his presentation, we're obviously got a very, very strong balance sheet. You know, we can still fully fund all of our projects and our growth plans down to very, very low oil prices.
For the time being constructive on oil prices in the medium term, we wanna kinda allow our shareholders to participate in that upside. That's why we have decided not to hedge the benchmark at this stage.
Great. Thank you.
If I can go along, I'm Max, also from Pareto. I think Christophe kind of explained the rationale behind the capital structure, but what do you think of financing going forward as Blackrod progresses? How supportive do you feel the banks are at the current moment?
Yeah, I think from our past experience, with Lundin Energy, for instance, we've learned that you wanna raise money or talk to your banks when you don't need them. It's probably easier and faster, so that's why we issued bonds exactly almost to the day a year ago. We always maintain those discussions with the banks who helped us issue the bonds or with our Canadian banks. Typically, we have this CAD 75 million Revolving facility which we've not used. We know, 'cause we talk to them all the time, we know that there is some willingness to further support us.
It's we're always considering whether we wanna further strengthen the balance sheet given that we're under-levered for two reasons, essentially, either as a sort of a hedge if oil prices were to go significantly below where they are today in the context of the CapEx spend for Blackrod. Also in the context that we are very credible as a buyer if we can demonstrate to the seller that we're we can act very quickly and we have the money to act on an M&A decision. I won't go into too much details, but over the history of M&A, we've rarely been the highest bidder, but we've always been the funded bidder, and that makes the conversation much more fluid with sellers.
Yeah. I think that's a really important point. Even just in the recent Cor4 acquisition, and certainly in discussions, I think the fact that we could write a check tomorrow give us a huge advantage and to be able to move quickly. Certainly in the discussions with the majors and the processes that we've been in, that's been the feedback with respect to, you know, the financial strength that the company has. As Christophe mentioned, when we now have half a billion dollars, it's not costing us anything. You know, if you're looking at where kind of interest rates are today to raise additional capital, it's a very, very small marginal cost to add to the business.
What it does open up is a lot more opportunity to do value-accretive acquisitions.
Return more cash to shareholders.
return more cash to shareholders.
Faster.
I think as Christophe said, yeah, best raising money when you don't need it.
Okay. Thank you.
Okay. I think we're done with questions from the audience. Yeah? I've got about 25 questions so I might, I might summarize a bit.
Yeah
Will, if I could start with you, because we have a couple of questions on emissions, what we intend to do for the future, how carbon capture would be integrated in our plans. Basically, when Blackrod comes out, what is our plans, what happens if the fiscal regime changes, and carbon capture, please?
As Mike had explained, we've extended our emissions reduction target through to the end of 2027 to maintain 20 kg per BOE of an emissions intensity level. It's really a two-pronged approach. Getting to that stage is a combination of direct emission reduction projects that are being undertaken across all regions, whether it be changing your instrumentation source from previously gas to air, tying in single oil batteries to prevent venting from happening. We're also looking at a number of flaring reduction projects, so there's quite a lot of emission reduction projects that are underway within the company. As well, we've formed a partnership with FirstClimate that has a variety of projects under its portfolio. We get carbon offsets and use those as well to net against our emissions intensity.
As Chris had shown in the capital in the layout for the facility with Blackrod, you can see that we have provisional tie-ins and a place left on the area of the CPF to incorporate carbon capture in a future point in time. There isn't immediate plans to do that right now, but we have initiated working that up, and we will consider incorporating that design down the road into the facility. I think as years progress through time, there's gonna be a lot of advancements with technology improvements on carbon capture. It's something that we're definitely gonna be looking into as we get closer to commissioning and most likely would be something that would come in after we get first oil.
I think maybe just a follow-up on that from Will is there's also the fiscal framework. You know, if you look at our experience in Norway where investments in CO2 reduction were effectively incentivized by the government, I think if we wanna get serious about carbon capture, we need to see a more encouraging fiscal framework. I think that technology development in parallel with some fiscal incentives for operators like us to invest will give us the best possible opportunity to get after this seriously.
Very good. Thank you. Chris, just a couple of specific questions, one on Onion Lake Thermal, actually. What are our future plans for growth in the Onion Lake Thermal asset? Are we looking at a future expansion?
There's a few options. It'd be an acceleration of reserves. There is an ability to grow the facility, put in more steam capacity, a little more oil treating capacity, and we could take that into the 16,000 barrel a day range and accelerate the reserves that we have associated with the project. That is a project that we've materialized, it's matured it, we understand it, and we just have to decide at the right time when we'd like to put that capital in.
Super. Just a follow-up question, Chris, just on Canada, are you seeing some inflation in your day-to-day business? How is that working at the moment for your base business?
We did definitely see some inflation kind of across the base business everywhere. I think it's done. It seems to be leveled out where we understand our supply chain, where we order things from, where our supplies are coming from. It seems to be leveled out. We understand that. It did impact our costs a little bit, but it's, you know, it's kinda leveled itself out now. I hope that answers.
Okay. Yep. No, that's good. How long until an additional pad after Pad L would be required for Onion Lake? I guess it depends.
Three years.
... on the expansion, right?
Yeah.
Three years? Yeah.
Depends on the expansion.
With the expansion.
For sure, yeah. If we did the expansion in that timeframe, we'd like to do one quicker. We'd start working on another pad in maybe 2024. We'd start working on the pad to bring it on some time in maybe 2025.
Yep.
Late 2025.
Okay, Mike. There's been a few questions about our discount to NAV, how undervalued we are. There's been a couple of questions relating to, you know, why we do share buybacks instead of dividends. Following up, how would you intend to close the gap on this NAV discount in the future?
Why do we want to buy our shares back rather than, sending a dollar for dollar out the company? I think, you know, shareholders can effectively create their own dividends right now when you have a situation like this where you have a do nothing more and just deliver what we've got ahead of us, and you've got a SEK 270 a share valuation against the current share price of just over a SEK 100 a share, without $1 of value attributed to 1 billion barrels plus of contingent resource or any further M&A. When you look at our track record in both those regards, I think that's our best answer as to why we prefer to retire shares.
Again, just as a reminder, if we just deliver that 2P plan and just use our surplus cash, that SEK 270 a share can go to SEK 500 a share, or SEK 900 a share between $75 and $95 per barrel if we continue that share buyback strategy in parallel with our growth plans, all fully funded from within cash flows. It's that transformational increase in value for shareholders that really drives our strategy of share buybacks over dividends.
Okay. Then just a related question, is there a Brent level where you wouldn't be looking at buybacks in the next five periods?
no, we haven't set a firm limit, no. Is the short answer.
Okay, good. Christophe, perhaps one just on the differential, and it's how confident are you that the Brent WCS differential will approach 15 from 2024? What do you see as the main risks for that?
It's an interesting question. We've discussed obviously with all our, with our reserves auditors and some of the other firms based on an economic review, they're seeing the differential really tightening from 2024, actually from the end of this year, when we get closer or when we reach the point where the doubling of the Trans Mountain Pipeline capacity comes on stream. We've commissioned an independent...
I mean, we can't tell you who, but we've commissioned an independent, review, which confirmed as well from an economic, analysis with some more refining capacity coming on stream to refine heavy oil, the Trans Mountain Pipeline and the all the different projects in Canada and the potential increase in production all points to a narrowing of this of this differential. The market, if you look at the forward curve, the market to some extent is showing also, a tightening of this of this differential, along, in the next few quarters. It's a long way of saying we're reasonably confident, that this is really gonna happen.
Whether it's gonna be in the fourth quarter this year that we'll see, we'll see a tighter than $20, whether it will be sometimes next year, it's very hard to pinpoint and get our timing absolutely right. Directionally, we are very confident that we're on a track to seeing that not to find it in the future.
Okay, very good. Sorry, we've just got another follow-up on the CO2 per barrel. At the moment, what is the Canadian carbon tax, and what do you expect to pay in the future?
The current Canadian carbon tax this year is around CAD 65 per ton of CO2 equivalent. That's ramping up by CAD 15 every year until it caps at CAD 170 come 2030, and that's Canadian dollars per ton of CO2 equivalent. All of those carbon tax numbers are fully baked into the numbers that we've provided today as well.
Yeah, that was actually the second follow-up question.
Is the carbon tax forecast sitting in your estimatesi? Is obviously yes. Mike, another M&A question. IPCO has a tradition of finding value through acquiring assets that have been underinvested. The question is, with Blackrod, has the type of M&A that IPCO would target changed? Are there still underinvested value deals out there?
Yeah, there absolutely are. We've got a very odd problem, inverted commas, than most other oil companies. We've got a 27-year reserve life, and we've got 1 billion barrels of discovered oil sitting on our books. We definitely don't need undeveloped barrels. We're extremely long undeveloped barrels. The type of thing that fits the IPC portfolio very well right now from an M&A perspective is highly developed, short reserve life, high free cash flow assets. It kind of actually dovetails very well with the types of stuff that the majors are looking to sell. It's kind of more mature, more developed.
Things that, you know, when you have a new operator that comes in and you do the kind of things that Chris and the team have done with Suffield, just pick the low-hanging fruit and deploy a little bit more capital, you can still extract a lot more value. Really, our kind of M&A focus right now is on production that's generating decent cash flows, that, you know, with just some quick fix and a good team and some additional capital, you can really deliver the quick wins, if you like. That is, it's a much more narrow window that we're looking at in terms of M&A.
Okay. Very good. That's pretty much all of the questions that we have all integrated together, so apologies to the audience. Yeah, we've got finished on that one. Mike, perhaps a couple of closing remarks for the audience?
Yeah. I'd just like to thank everyone here in Stockholm for attending and to listening to the presentation. Thanks to all the listeners who've tuned in on the webcast. Also thank you very much to the IPC team for the presentations today. I think the company's had an amazing past, but I think we've got an even brighter future, and we certainly look forward to reporting in the first quarter the progress we're making at achieving a number of these plans that we set out today. Thank you very much, everybody.
Thanks, everyone.
Thank you.