Okay. A very good afternoon to everybody, and welcome to IPC's 2022 Capital Markets Day presentation. My name is Mike Nicholson, and I'm the CEO of IPC. Also joining me this afternoon to present is William Lundin and Chris Hogue, who will go through the 2022 outlook and the details on the asset overview. They'll then pass across to Christophe Nerguararian, the CFO, and Christophe will run through the financial forecast for 2022. He will then pass to Rebecca Gordon, who's our Vice President of investor relations, and Rebecca will give an update on our reserves valuation. We'll finish with some conclusion and some concluding remarks and a Q&A session. Quite a lot of material to get through.
To start with though, before we get into the 2022 forecast and long-term plan, I want to spend just a couple of moments highlighting the exceptional performance that IPC delivered in 2021. Our production for the full year was just above 45,000 barrels of oil equivalent per day, and that was in excess of our high-end guidance of 43,000 BOE per day. On the cost front, excellent delivery. Our full year operating costs were $15 per BOE, and that was below our latest guidance. The capital program came in at just under $50 million, in line with guidance. With strong production and increasing commodity prices across the entire energy complex, IPC was able to deliver its record financial performance in terms of cash flow generation. Full year operating cash flow was $337 million.
F ull year free cash flow was $263 million. Based upon the current market capitalization of the company, that represents an extremely attractive free cash flow yield of 26%. The free cash flow has been used to deleverage, and the balance sheet's in extremely good shape. The net debt decreased from $321 million at the beginning of the year down to now $94 million at the end of 2021. The leverage decreased significantly from 3x at the beginning of the year to less than 0.3x at the end of 2021. Will get into this and Chris in their section in much more detail, but a phenomenal performance in a low CapEx year.
In terms of our reserves, we've managed to replace more than 90% of our 2P reserves and now have 270 million barrels of oil equivalent. A huge increase in contingent resources above 300 million barrels of additions, lifting our 2C resources to above 1.4 billion barrels. A continued strong strategy with respect to ESG, and we're well on track to meet our long-term targets of reducing our net carbon emissions intensity by 50% through the end of 2025. Also a very good HSE performance for the full year with no material incidents to report. All in all, an exceptional 2021.
I think as we look ahead over the next five years, there's an even brighter future for IPC, and we've created a phenomenal platform to create significant value for our shareholders. We're lifting our long-term production forecast up by 2,000 barrels a day from 45,000 to 47,000 barrels a day, flat over the next five years. Assuming average Brent oil prices between $65 and $95 per barrel, we're in a position to generate between $900 million and $1.8 billion in free cash flow. That represents an annual free cash flow yield on average of between 18% and 36%.
That gives us a phenomenal position to continue to return value to our shareholders, to continue to acquire and grow the business through M&A, and to continue to mature the significant contingent resource base that we have, which is in excess of 1.4 billion barrels of oil equivalent. If we start now with the reserve growth position, it's been extraordinary since we started back in 2017. We had just 29 million barrels of oil equivalent. If you look at the light blue bar on the bottom of this slide, you can see that we've produced more than double our 2P reserves, 65 million barrels produced in the first five years.
If you add the 270 million barrels that we have at the end of last year, that's a total reserve increase inclusive of production of more than 11x . We've also significantly increased the longevity and the quality of our reserve base up from 8 years to 16 years. When you see the numbers that underpin our 5-year business plan, there's significant remaining resources of close to two thirds of that resource base at the end of the 5-year business plan. Contingent resources has been even more dramatic. When IPC started, we didn't have any contingent resources. Through a series of upgrades to existing assets and through acquisition of companies, assets, and land acquisitions, we've been able to significantly increase our contingent resource base from last year at 1.1 billion barrels to now in excess of 1.4 billion barrels.
The biggest single increase came from our Blackrod project, which saw around 300 million barrels of oil added to the 2C resource base at Blackrod. With the capital program that we have this year in Canada on our Ferguson project, with the Malaysian drilling program that Will's gonna take you through, and also the French drilling program, we've also got a lot of investment that's gone in that can help mature some of that 120 million barrels of 2C resources that sits outside our Blackrod project. That's a significant inventory of future reserve and resource replacement. Turning to the production guidance for 2022. We announced this morning our production is expected to be between 46,000 and 48,000 barrels of oil equivalent per day. We're targeting investment in all of our areas, in Canada, in Malaysia, and in France.
What you can see from the chart on the right-hand side of this slide is that we're forecasting production to return back in excess of pre-COVID levels. Both Chris and Will will go through much more details on the projects that are underpinning that growth in the operations section. Turning to the cash flow generation. You can see that year after year, with the exception of the 2020 pandemic year, IPC has been able to increase our cash flow generation. I think if you look at the forecast for 2022, you can see that we're lifting the company to new heights. If we assume much more conservative oil prices of $55 per barrel, we're estimating to generate somewhere between $220 million and $230 million of operating cash flow.
At prices of between $70 and $100 per barrel, we're looking at generating between $360- $375 million at $70 a barrel, up to $600 -635 million at $100 a barrel. A significant uptick in cash flow generation in this higher commodity price environment that we're experiencing. Turning to the investment program that we've announced today. The focus and the strategy very much remains on free cash flow generation. It's a measured capital investment program that you're going to see. We plan to invest just under $130 million of capital expenditure. It's targeting growth in all of the key assets in all of our regions. That program is fully funded, assuming Brent price is below $50 a barrel.
Gives us also the opportunity to invest and mature in our organic growth opportunities, and we'll be talking about Blackrod later. Of course, the cash flow generation puts the company in a very strong position to continue to be opportunistic with respect to M&A activity. When we look at the cash flow generation, we take off the investment that were planned for this year. We can see how much free cash flow IPC is projected to generate in 2022. At the low end of the forecast, assuming $55 per barrel Brent pricing, we expect to generate between $60 -$65 million, so that's around a 7% free cash flow yield. You can see that's why we can fully fund the investment program at below $50 per barrel.
At higher prices of between $70 and $100 per barrel, we're looking at generating between $210 million and $480 million, which represents a free cash flow yield of between 20% and 45%. If we look at how that free cash flow generation compares to the rest of the industry, this chart shows a benchmark of global integrated E&P companies, and it's been compiled by RBC Capital Markets. We can see that the average projected free cash flow yield across the sector ranges from a low of 6% up to a high of 20%, with an average of 13%. That's assuming oil prices of $80 per barrel. The equivalent free cash flow yield for IPC is 30%, so well in excess of double the industry average.
IPC trades extremely attractively relative to the rest of our industry peers. What do we intend to do with the cash flow that we're generating? We're very pleased this morning to announce a new shareholder distribution framework. What we plan to do in the framework is that provided that our leverage, our net debt to EBITDA ratio is below 1x , and the average Brent prices are in excess of $50 per barrel. We plan to distribute up to 40% of that excess free cash flow above $55 per barrel. When you look at the guidance that I gave on the previous slide, from $55 to $100 per barrel, that means that we're in a position to distribute between $0 and $166 million of free cash flow.
At the high end of that forecast, assuming $100 prices, that's a 17% yield. That's the short-term 2022 position. If we now turn our thoughts to the longer-term 5-year business plan, we expect this capital program that you can see on the chart on the right-hand side, which amounts to $400 million spread over the next five years or $4.65 per BOE on average of sustaining CapEx. That sustaining CapEx program can keep our production flat at 47,000 barrels per day on average over the 5-year period. I think it is worth reiterating that IPC operates almost all of our assets 100%. We have full discretion on the pace of development, such that if commodity prices do change, we can adjust that capital program accordingly.
With such low sustaining CapEx, with a long-term OpEx forecasted between $15-$16 per barrel, company is in a phenomenal position to generate free cash flow, well in excess of our industry peers. Feeding into the long-term cash flow story, and we've touched upon this slide in many of our previous presentations, is the supply and egress position in Canada. That's important because it feeds into Canadian crude price differentials, and just under 50% of our production relates to Canadian heavy oil. What we've seen in the last couple of years is a material improvement in the egress system. In the fourth quarter of 2021, Enbridge's Line 3 came into service, and that added an additional 370,000 barrels of oil per day of pipeline export capacity.
The second big pipeline project, which is under construction, is the Trans Mountain Expansion Project that will take Canadian crude to Vancouver to supply West Coast U.S. markets and also Asian markets. That pipeline has around 600,000 barrels a day of additional pipeline capacity. As at the beginning of this year, that project was already 45% complete. When you look at the projections on the top right-hand side of this chart, you can see that for the next five years, we have excess pipeline capacity relative to Canadian crude supply, which is the yellow line, and we have not been in that position for more than five to six years. That's extremely constructive for WCS differentials.
What we've taken the opportunity to do is to lock in for this year, for the remainder of 2022, 60% of our differential exposure has been hedged at an average price of $13 per barrel. If you look at the chart on the bottom right-hand side of this slide, which shows Canadian storage numbers, you've seen that since Enbridge's Line 3 came on stream in the fourth quarter of last year, storage levels have dropped to recent historical lows. That's also extremely constructive for Canadian price differentials. Turning to what that means in terms of the 5-year business plan outlook, if we first reflect back on the first five years of IPC's existence, we've averaged production of just under 36,000 barrels of oil equivalent per day. The average Brent price over that period was just over $60 per barrel.
IPC, in our first five years, generated in excess of $660 million of free cash flow. When we now look ahead over the next five years, as I've mentioned, we expect production levels to be in excess or around 47,000 barrels of oil equivalent per day. What that translates to into our free cash flow generation in a more bearish market where crude prices average $55 per barrel over the next five years, we can still generate in excess of $600 million on a 12% per annum free cash flow yield. If we look at a more bullish oil price environment of $95 per barrel, around where we are today, you're looking at in excess of $1.8 billion of free cash flow or an annual average free cash flow yield of 36% per annum.
To put that free cash flow generation in context, it's good to compare it to IPC's current enterprise value. If we take the net debt at the end of last year of $94 million and add that to the current market cap, which is just above $1 billion, that gives an enterprise value for the company of around $1.1 billion. Compare that to the free cash flow forecast over the next five years, you're looking at between $900 million and $1.8 billion, between $65 and $95 per barrel.
Just above $70 per barrel, we can liquidate the entire enterprise value of the company, and we'll still have remaining two-thirds of our 2P reserves, and we'll still have 1.4 billion barrels of contingent resources that are not included in the cash flow numbers. Very strong story in terms of cash flow generation for IPC. If we now turn and look at the company through the value lens, we also look extremely favorable. Since IPC was started, we've been very active on the M&A front, and we've conducted four acquisitions in the last four years, and they've been extremely value accretive for all of our stakeholders. If we look at the slide and the charts on the bottom of the slide, we can see that the first acquisition, our Suffield acquisition was completed in January of 2018.
We paid $420 million for that asset. It's generated through the end of last year, $200 million of free cash flow. Using our independent reserve auditors price forecast, we're estimating that that's worth today $593 million. More than $370 million of value added. You can see a similar story for our Black Pearl acquisition. Significant value added, more than $1.1 billion. Likewise, for Granite in excess of $110 million. Our most recent acquisition in Malaysia, more than $48 million. When you put those four acquisitions together, you can see that we've aggregated $1.7 billion in value add from those four acquisitions. That's an exceptional track record since the company started.
When we put all those acquisitions together with the organic reserve replacement that we've had since we started, you can see a material uptick in our value and our net asset value. When we started back in 2017, we had a net asset value of $543 million. Rebecca will go into much more detail in her presentation, but the asset value at the end of last year is in excess of $2.5 billion. When you deduct our net debt, that brings our net asset value down to just over $2.4 billion, and that represents SEK 143 a share. Compared with our share price currently of around SEK 60 per share, that's about a 58% discount to the fair value of IPC's 2P reserves.
It doesn't assume a single new barrel of reserve added. It doesn't assume a single barrel of our contingent resources is converted into reserves. I think when you listen to Will and to Chris's presentation, you can see that we've got a track record of consistently adding reserves to the resource base that we currently have. Turning to the contingent resource base, we've made a lot of progress in the last two years in starting to unlock the option value that we have in that biggest contingent resource, which is our Blackrod project. As I mentioned in the highlights, we've materially increased our 2C resources on our Blackrod project, up by around 300 million barrels to now just under 1.3 billion barrels.
For the first phase of development, previously, we estimated just under 180 million barrels of 2C resources, and that's now been uplifted to just under 220 million barrels of 2C resources. For a phase one development, the latest CapEx estimate is around $540 million. This, these numbers have been independently verified by Sproule, who are our third-party resource certifier in Canada. You combine this project with the expertise that we have in Canada, where we've operated the pilots on the Blackrod project for more than seven years, and we've got expertise from our Onion Lake thermal project on development and operating these types of projects, puts the company in a very strong position to start to crystallize more value from this project.
The team has spent significant time and money, and Chris will go into more details in his presentation, but we've got all the approvals in place for an 80,000 barrels a day production facility. The team has done an excellent job in optimizing the phase one development concept for this project. What we're now looking at is starting with a 20,000 barrels a day facility that will then ramp after a couple of years up to 30,000 barrels per day. The numbers look very attractive. On a non-risk basis, we're looking at an NPV8 of around $860 million for that phase one development. If you look at the break-even price, it's around $50 per barrel WTI.
If you look at the recent Rystad study, which quantified the breakevens for all of the greenfield projects that you have, including Middle East, including deep water, including shelf and Canadian oil sands, this sits just a couple of dollars per barrel above the average of all of those projects. Screens extremely favorably. What's next for Blackrod? You're gonna see we plan to spend around $4 million on FEED studies to mature the project through 2022. We're gonna continue the pilot, and the positive thing is that actually the cash flow from the pilot at these oil prices will more than fully fund those FEED studies.
Very low dollars to start to continue to further crystallize the value of this significant contingent resource base. My final slide goes hand in hand with the growth that the company's had, as it's extremely important to have a very clear ESG strategy. If we start first with the health and safety performance of the company, it's been exceptional. We didn't have any material incidents at all through 2021. We've retained all the COVID operating protocols that we've had in place, and our teams have done an extraordinary job to have no interruptions as a result of COVID through all of 2020 and all of 2021.
If you look at our climate strategy, we've made a commitment to reduce our net emissions intensity by 50% through the end of 2025 from our baseline in 2019 of 40 kilograms per barrel to 20 kilograms per BOE by the end of 2025. You can see from the chart on the bottom of this slide that we're already well on track with that with respect to our net intensity reductions through 2020. We did publish, alongside our second quarter results, our second sustainability report. It's fully GRI compliant. There's a lot of incredible projects that are ongoing across all of our organization. I would encourage all of our stakeholders to take a good read and see the excellent work that's been done by all of our teams across all of our units within IPC.
That concludes my part of the presentation. I'll pass across now to William Lundin, who's the Chief Operating Officer, and he'll walk through the 2022 outlook before we get into more details on the assets. Will, over to you.
Thanks, Mike, and I'm thrilled to be providing some more color on the operational side of the business today. In the upcoming slides, we're gonna spend a little bit more time on the resource highlights, as well as explain strategically what we set out to achieve through our 2022 guidance. Chris and I will get into more detail within each of the operated regions. The growth story continues for IPC. Notwithstanding 2020, the company has managed to increase its resource position every year since spinoff from Lundin Energy back in 2017, and this has been accomplished through a combination of organic growth and high-quality asset acquisitions. As Mike touched on, we had material reserve replacement across all operated regions with a collective proved plus probable reserve replacement ratio of greater than 90%. Our contingent resources also grew by nearly 30%.
When you combine the 2P plus 2C volumes together, it represents greater than 2,000% replacement for the group, which is really a testament to the quality of the assets and the technical personnel that exists within the company. A core strategy within IPC is to deliver operational excellence and to maximize the value of its resource base. We do this by working with the assets and working with the teams to define the life cycle plans for each asset, whereby in the short term, we're looking to optimize existing production, and in the long term, we're identifying and maturing contingent resources and undeveloped reserves to ultimately get them developed and put into production in the most effective and efficient way possible.
That's exactly what the teams have delivered through time, whether that's from the international assets that IPC acquired or within the Canadian business, as can be seen on the cumulative production and reserves plots on the right-hand side of the slide. It's also important to note that no reserve replacement is assumed within any of the valuation or cash flow projections shown today, which is a really strong position to be in as a company with greater than 1.4 billion barrels of contingent resources and a motivated team to see those resources matured into reserves. Our 2P year-end 2021 reserves position stands at 270 million barrels of oil equivalent. That's only 2 million barrels less than the prior year's volumes, despite producing 16 million barrels of oil equivalent throughout the course of 2021.
The driver of that replacement mainly stems from a combination of good field performance and technical improvements. With reference to the reconciliation table, in Canada, the bulk of the reserve replacement came from Onion Lake Thermal and Suffield, which collectively contributed around 8 million barrels of oil equivalent. At Onion Lake Thermal, technical work was performed where the well logs were reinterpreted across the developed area, and that revealed larger oil in place with which led to greater than 4 million barrels of 2P reserve replacement for Onion Lake Thermal. In Suffield, we had really good performance from the oil and gas side, and especially from the N2N enhanced oil recovery project. In aggregate, that added just shy of 4 million barrels of oil equivalent in 2P additions from the Suffield property.
The rest of the reserve replacement in Canada came from a pretty even distribution across Ferguson, Moonie, and the conventional assets. In Malaysia, we acquired an incremental 25% working interest, and we also had really good field performance from the wells there, specifically from A20. In France, we also matured contingent resources into reserves associated with the Dommartin-Lettrée field. We had great field performance from the VGR field as well. That added 3 million barrels of 2P reserve additions relating to our international Brent-linked assets. Whether it's 1P, 2P, or 3P reserves, 60% of those volumes are within the developed category. Our 2P reserves life index is 16 years, and that's based on our midpoint production guidance. After five years of production, we'll still have greater than two-thirds of our 2P reserves.
Within that timeframe, we could more than liquidate our enterprise value, as Mike was discussing earlier in this presentation. Our contingent resources are 1.41 billion barrels of oil equivalent. For every barrel of 2P reserves, we're more than 5x covered on contingent resources. The growth that we saw in the contingent resources over the past year mainly came from Canada at the Blackrod project, where there was comprehensive technical work undertaken that resulted in increase in recovery factors for the property, as well as extension of the booked volumes to the south. We also had contingent resource additions come into play in Malaysia, where we booked the PSC extension volumes and also identified a couple extra infill wells.
In France, we had a slight reduction in our contingent resources, and that was the result of our Dommartin-Lettrée field development opportunity being matured to reserves, really following through on our organic growth strategy. In 2021, we had excellent production performance, and that came on the back end of a relatively light investment program. That really showcases the low decline nature of the assets that we have within the IPC portfolio. Those themes that underpin the strong performance are reflected into our 2022 production guidance of 46,000-48,000 barrels of oil equivalent per day. If we achieve the midpoint guidance, that will be a record-setting production level for IPC, which couldn't come at a better time in this piping hot commodity pricing environment.
The production forecast that we've put out, pardon me, the production that we've achieved historically has always been within guidance or better than guidance since inception, and we're confident to repeat this going forward based on the diligent forecasting process carried out with operations and our production and reservoir engineers. The investment plan this year targets production growth across all operated regions, and specifically, the capital activity in Bertam in Malaysia and Ferguson in Canada will contribute to production growth in 2022, and the rest of the investments will have more of an impact going into 2023.
I do wanna point out, you can see there's a slight dip in the Q1 production guidance for 2022, and that's really the result of a couple things, which is, one, from Canada, where there's extremely cold winters there, which mainly affects some of our Suffield gas production, but that does come back through flush production when weather warms up. There's also some production downtime associated with the ongoing drilling activity in Malaysia. Our production mix is two-thirds weighted towards oil, with about 49% of our crude coming from Canada and 18% coming from the international assets in France and Malaysia. The rest of the production mix is natural gas coming from Suffield. Our operating expenditure guidance per barrel of oil equivalent for 2022 is $15.20, which is largely in line with where the 2021 level settled at.
Our operating expenditure guidance is representative of all costs from wellhead to sales point, and it does include normal provisions for items such as maintenance and workovers, and the downtime associated with that is taken into consideration. We don't have any major turnarounds scheduled this year across any of the assets, but there are some minor process shutdowns scheduled in Bertam, and that's mainly due to the rig move and some standard inspection work. Christophe, within the financial overview section, will showcase the evolution of our operating costs per BOE on a quarterly basis. Strong cost discipline is really core to the business here, and we have a really good understanding and control of the base operating costs, and we have minimal discretionary spend allocated to each of the assets.
If prices were to dip, we know exactly what needs to be done to minimize our variable expenditure, which really keeps us resilient through the volatile pricing periods that this industry can have. Development capital, I'll spend a little bit of time here, and then Chris and I will go into more detail on each of the projects within the country overview sections. Our capital expenditure guidance is $127 million, and that includes decommissioning expenditure. This is a measured investment program targeting production growth across all operated regions. In Canada, we have developments planned in Onion Lake Thermal, which will primarily consist of early works for the next sustaining pad, L, as well as drilling of a couple additional infill wells there.
In Ferguson, we're very excited to get that development activity underway, which will bring immediate production growth at the back end of this year. There's also infill drilling going on within the Suffield oil property. The big focus for the company is at Blackrod, where we'll look to mature our commercial development concept through a front-end engineering design study. The spend in France is mainly allocated towards the Villeperdue West development project. In Malaysia, there's some carryover for the A15 sidetrack drilling and pump upsizing program. This development capital and budget is fully funded by cash flow generated from the business. By being operator at the vast majority of the assets that we have, we have the autonomy to modulate some of the investment as needed, depending on the commodity and pricing environment.
At this point in time, if 50% of the capital could be removed, and alternatively, there's a mature set of projects that we have in inventory that we could decide to add in, and some of those will be shown in the upcoming slide. This is really the opportunity set that exists within IPC, and it's the feedstock for organic growth. Some of those opportunities listed in the future opportunities section are execution ready, and we'll continue working across all operated regions to further define and identify projects across those assets. It's really how the technical side of our business works, where the corporate and the asset teams are working together to mature these growth opportunities in accordance with our value process policy. What that does, it really ensures a robust and a predictable outcome. That business model, it ensures maximum value creation.
It also is scalable, and it's something that we use as a tool when we're looking at business development opportunities, whereby if there's an asset or a company of interest, we're looking at the projects contained within that vehicle and see how they rank against our projects contained within the IPC portfolio, and they must be competitive relative to that. Five-year outlook, we're targeting 47,000 barrels of oil equivalent per day for the next five years with a low sustaining capital cost of less than $5 per barrel of oil equivalent. This is just based on our 2P reserve position. The reason for the low sustaining capital cost is really a result of the majority of our assets having existing infrastructure with excess processing capacity in place.
To mature those undeveloped reserves largely consists of putting more well stock into the ground and tying in to the existing facilities. That creates really robust opportunities, and it also, you know, results in us having a great platform for material free cash flow generation. Within the five-year horizon in Canada, the spend is largely geared towards Onion Lake Thermal, which will consist of producer and injector pad development, as well as some facility works. There's some ongoing activity in the Suffield gas property, as well as oil drilling across Suffield Oil, Ferguson, and Moonie. Within the international business, we have ongoing developments in Villeperdue West for France, as well as the DML development. In Malaysia, it only assumes we execute the A15 sidetrack drilling opportunity as well as the ESP upgrade.
There's no further activity beyond that, and that's really what underpins the 47,000 barrels of oil equivalent per day projection. Now, because we're operator, as I had mentioned, we have the ability to modulate the investment, and depending on the commodity pricing environment, that is exactly what we'll do because the primary focus for the company is to really generate an optimal amount of free cash flow. With that being said, I will transition to Chris to go through the Canada section. Thank you.
Thank you, Will. Let's take a look at Canada. Canada is 80% of our production, 70% of our operating costs, and 65% of our capital spending in 2022. Our assets consist of shallow natural gas, light oil, medium oil, and heavy oil. On the map you can see on the slide, they're located in three core assets in Southern Alberta, in Mid-Central Western Saskatchewan, which is right on the Alberta-Saskatchewan border, and then again in Northern Alberta, where we have our Blackrod SAGD development. Let's dive into a few assets here. We'll go with the Onion Lake thermal first. So Onion Lake thermal is a world-class thermal heavy oil development. We have 140 million 2P reserves in the development currently. The plot on the bottom left shows the asset has been built in two phases.
In 2016, we kicked off with phase one, and in 2018, phase two was kicked off with the production approaching our facility capacity of approximately 14,000 barrels a day. In 2021, you can see the development maps on the right-hand side. You can see the drainage patterns associated with our phase one and phase two. In 2021, we added the D- pad. You can see the top left of that map. That pad is online and producing as expected. We also did an infill program of five infill wells that are also online and ramping up as expected currently as well. In 2022, we're gonna focus on a sustaining pad, which we call our L pad that you'll see the top right hand of those development drainage boxes.
That pad is a large pad, 9 SAGD well producers, and it will be a sustaining pad, so it'll bring wells on as required to maintain production at our facility capacity of approximately 14,000 barrels a day. Sustainability is also, you know, a big focus when it comes to our Onion Lake thermal project across all assets. Onion Lake thermal project has some ability to capture and really reduce emissions. We've looked at a waste heat project that we're able to capture some heat out of our disposal water and return that back into the process to preheat some boiler feed water to create steam, which is overall going to reduce our emissions through our 2022 year. Also a lot of little jewels of opportunities in there.
We have a few other infill projects that we're continuing to mature and we'll drill a couple of those wells throughout 2022 as well as part of our capital budget. Again, all sustaining type production to keep it flat for many years. Suffield is a large, profitable producing asset. It's mature, has great historical production, it has natural gas, and it has, you know, medium to heavy oil located on it. The previous operator never gave it the attention. It wasn't non-core. It was a core. It was not a core property for the previous operator. When IPC acquired it, started to give it some love and attention, we were able to start working projects through optimization.
You can see in the plot in the top and the bottom left that we have replaced 30 million barrels oil equivalent of production. Let's get specifically into the natural gas asset within Suffield. The two plots on the right-hand side of the slide we'll focus on. The bottom right is a fairly lengthy, in years, production plot associated with Suffield natural gas. You can see prior to IPC's acquisition, it was on a decline of 9% or 10%. Once IPC started giving it again that love and attention, you can see the profile has really flattened out. Since then it's on an average about 4% declines, with some of the years, the beginning years being, you know, really flat. Why is that? How is that happening? Well, there's a large well stock there. The shallow natural gas.
When gas is being produced, it brings in a little bit of mud, a little bit of water. You need to continue to work these wells to remove that water and mud from the well bores to avoid the gas being snuffed out and keep the well gas production online. You can see since 2017, some of that optimization activity being, you know, gas swabs are one of our largest manufacturing process type of maintenance. You can see we've doubled the amount of activity in the field, which directly impacts the amount of production and gas that we can keep running at that facility. Again, all this is done without drilling a well. This is all done through hard work, the teams focusing on optimization and good preventative maintenance.
On the left plot, you can see the oil production associated with Suffield, the Suffield asset. Again, a before and after picture of the asset not getting much attention, and then the asset getting some focus. You can see that not only did it offset decline, in fact, it's increased in production since our focus on that asset. That's done through upsizing artificial lift throughout the existing well stock, debottlenecking facilities throughout the field. Also maturing, identifying and drilling certain drilling inventory that's there in the pools and infilling in some of our enhanced oil recovery pools, like Will mentioned earlier, like N2N. Very, very impressive results. We're operating today around 8,000 barrels a day, and we have lots of future inventory to maintain that. We'll move ourself to Ferguson. Ferguson is our southern-most southern Alberta asset.
It was bought in early 2020, just as price was collapsing. This jewel or gem of an asset has kind of been waiting for us to get after a development. Well, we're ready to get at it now, so we are commencing a drilling program on this asset in the coming months. We have a 13-well program planned. The following years, there's also a 10-15 well program of inventory for the next few years afterwards as well. You'll see this asset more than double in production in the next year to year and a half. Very exciting, very clean asset. It's a light oil asset. We don't use condensate to be able to move it to sales market.
It has a very low OpEx, very, very high net back property, a great clean little operation, very excited to have it in our portfolio. Our conventional and Moonie assets are described here. We'll start with Moonie. Moonie is an ASP flood, very similar to some of the enhanced oil ASP floods that we have in Suffield, so there's some synergies that we capture between the two properties. This you can see on the map is one of our northern Alberta properties. It is only really being developed in what we call phase one of our Moonie property. Phase two has not been touched with the enhanced oil recovery techniques that we're using. We're looking at advancing into phase two in 2022, and more than tripling the production associated with that field.
The conventional assets, which are more located around, I guess, our flagship, one of our flagship properties being Onion Lake Thermal. We have the synergies of using infrastructure, our teams, and just being active in that area to operate these conventional assets that continue to give us inventory of drilling opportunities and reactivations that should contribute approximately 1,000 barrels a day to our 2022 production guidance. Blackrod. We've heard lots about Blackrod today. I'll dig into it with a little more depth. Blackrod, a very large SAGD development. It's our largest organic growth opportunity that we have. It is 80,000-barrel-a-day approved development today. We've been operating a pilot for close to 10 years now. The pilot has had three iterations of well pairs, well pair 1, 2, and 3.
Lots of learnings have happened from those well pairs. We drill them longer. We went from 700 meters all the way to 1,400-meter well length now. What does this do? All those learnings allows us to, again, optimize, you know, the number of pads we're gonna have to drill, the number of wells, roads, pipelines that we need to put in to manage the commercial development, capital cost metrics to ensure we're the top quartile SAGD project. The well pair 3, you can see in the bottom right plot there, is producing at over 800 barrels a day today. We've locked in a commercial design for drilling, for completions, for startup, for operating to maximize the potential of that well bore and use it as part of a commercial design. You can see the progression.
We also have the well pair two, was also a very successful well pair, on that same plot, showing the difference in well pair two and well pair three by taking into account our lessons learned, including well length, including operability, including startup. All those types of lessons are incorporated in that to make us very confident around our ability to take this commercially and do it successfully. Blackrod, through the maturation of well pair three, again, the longer well lengths, the resource assessment work that we've done to really look at recovery factor, to understand how the pilot has performed, we've been able to solidify approximately 1.3 billion 2C resources associated with this asset. An amazingly large resource.
Phase one, you can see, is approximately 200 million barrels of 2C resource, and that's where we're gonna focus. Our 20,000 barrel a day with an expansion to 30,000 barrels a day development plan in 2022. We'll be spending some small prudent dollars on keeping this asset hot and ready in terms of being part of our portfolio if at some time we wanna move this organic development forward. That's it for Canada, so I'll pass it back to Will, and thanks for your time.
Thank you, Chris. Now I'll spend some time on the international assets before transitioning to Christophe to go through the financial overview. Our lone offshore asset within IPC is in Malaysia, and the asset is located in shallow waters of about 70 meters in water depth. The reservoirs contain 37-degree API oil which we produce through our wellhead platform onto a spread moored FPSO. You can see this in the image on the slide there. That picture was recently taken and also includes the Gunnlod jackup rig which we contracted for our ongoing A15 sidetrack drilling and pump upgrade program. The strategy for Malaysia is quite straightforward. It's to sustain a high level of operational excellence by maintaining high uptime.
It's also to deliver our investment program as per plan and to mature organic growth opportunities, so we can really unlock the full value potential of this asset. The Malaysian business has really been a model of excellence when it comes to running an offshore asset. The teams have managed to achieve close to 100% uptime, excluding planned maintenance and planned outages since coming on stream every single year. That great facility performance is complemented by really strong reservoir performance where there's been a significant uplift of recoverable resources over time. When we look at the production plot on the slide, we now have 100% working interest within Bertam as of April of last year. We forecast spot production rates in 2022 to return to near net 2019 production levels, which is really impressive.
This asset continues to exceed expectations with cumulative production and current 2P reserves well in excess of the 3P levels booked at PDO time back in 2012. With this strong performance and the track record of success, as well with us owning the FPSO and associated infrastructure, and with there being a material amounts of oil to be recovered past the current production sharing contract deadline in 2025, there's really a compelling case to extend the PSC here. We'll continue to work with the teams on this throughout the course of 2022. Bertam development. The A15 sidetrack, we are targeting the K10.1 formation within the northeast region of the field. Drilling is currently underway. We recently landed the production casing which penetrated the K10.1 reservoir in line with prognosis.
We still have to drill the lateral portion of this well, as well as do the completions. We expect first oil to come sometime by the end of Q1. The infill programs that have been executed in Bertam have been hugely successful. We've actually produced more to date than the pre-drill expectations, and there's still plenty more oil production to come from those wells. Following the completion of A15, that same drilling rig will be used to upsize three ESPs as well as execute one well workover. You can see on the graphic in light blue where the three ESP replacements will take place. It's a very straightforward execution plan here, where we're simply retrieving the upper completions and installing a new Schlumberger ESP. What this does, it doesn't only increase the rate potential, but it's also a form of proactive maintenance.
With the FPSO processing capacity upgrade that was successfully installed last year, that ensures that we can maximize production rates going forward from this field. The economics for this capital activity are really, really strong. There's around a 1-year payback and a $20 break even, and that's based on a $55 Brent price. With our next cargo lifting, we've secured a $5.50 premium, so this is gonna really pay out in a rapid timeframe. Our subsurface teams will continue to mature the infill locations that are booked within our contingent resources based on the results of this program. In France, we have a 100% working interest within the Paris Basin and 50% working interest and non-operatorship within the Aquitaine Basin. You can see the license packages on the slide there.
These assets contain light oil as well, of around 36-degree API. The strategy here is to maintain efficient operations which the teams have delivered year on year. It's also to commence the Villeperdue West development to continue maturing our organic growth opportunities. These are really shallow decline assets that we have here, and when you combine that with the recent development and optimization activity, you can see on the production plot, we've completely offset those declines. The majority of our production does come from the Paris Basin. Of our 2P reserves, 85% of them are within the developed and producing category. What that does, that ensures stable cash flow generation going forward for the foreseeable future.
The teams in France have been there for a significant period of time, and it's really a benefit to have that historical knowledge and expertise, and we'll continue working with the teams to mature our organic growth development opportunities, and especially located within our contingent resource volumes. The most recent development that was undertaken by the company in France was within Vert-la-Gravelle, and that delivered a hugely successful result. As you can see on the production graph, the VGR-113 well is continuing to exceed expectations. This well still has a 99% oil cut after being online for over two years. It's something truthfully that we didn't anticipate, but we'll take that any day of the week. We're very happy and pleased with the results thus far, and we're looking to replicate the success that we've had there at another field called Villeperdue.
With Villeperdue, it's one of the main producing fields that we have within the Paris Basin. There's a lot of development upside, and we're looking to exploit that through a multi-horizontal step-out well drilling program. These formations within Villeperdue are different than those that are contained within Vert-la-Gravelle. In Villeperdue, it's Dogger carbonate reservoir at the Jurassic level, and there's two producing intervals known as the R1 and the R2, and we're targeting the R2. There's reservoir quality extension towards the west, and there's potentially a very large unswept area there that we're targeting, and this is substantiated through 3D seismic as well as data gathered from existing well control within that field. These three horizontal wells will be drilled from existing well pads, and it'll provide greater than 500 barrels of oil per day to the French business.
We're really excited about this light oil opportunity. The drilling team was recently assembled, and upon a success case, there could be a lot more further upside potential within the western flanks of the field. In summary, we're in a phenomenal position as a company, targeting record production this year with a robust business plan that underpins flat production rates for the next 5 years. This is only based on our 2P reserves. With greater than 1.4 billion of contingent resources and a proven track record of reserve replacement, there's a ton of upside to outperform. It doesn't just stop there. It's within our DNA to execute value-accretive acquisitions, and we continue to be opportunistic to grow through M&A.
With a strong balance sheet, with a war chest of cash, and with material cash flow being generated from our operations, we're in a really great spot to grow organically and inorganically all while making shareholder distributions. With that, it's a perfect time to transition to our CFO, Christophe Nerguararian. Thank you.
Good afternoon, thank you, Will, for that great presentation on our operations. Moving on to the financial overview, and starting before I give you all the netbacks at different oil prices, looking at the assumptions. Actually, that slide took us quite a bit of time. We wanted to show different scenarios, obviously, and the oil price has been very volatile, obviously, increasing a lot over the last few months. We wanted to first show you a case at $55, just to evidence we are absolutely fully funded at that low level. A base case at $70, which is pretty much in line, exactly in line, with the actuals in 2021.
A high case at $85, which is pretty much where we stand right now because obviously the spot price of the Brent is around $90-$92, but there's a steep backwardation, and we're losing $8 approximately on the forward curve between now and the end of the year. That high case at $85 is pretty much in line, spot in line with where we could almost hedge the oil price, the Brent oil price for this year. At $100 because there's more and more literature and analysts forecast about a three-digit oil price.
Now in terms of differential, we remain in line with actuals from 2021, so we're using a $3 discount from Brent to WTI and another $13 discount from WTI down to WCS. That puts us, as I said, pretty much $1 apart from where we were in 2021. That's for the oil. We'll show you on a netback basis the impact of all these cases onto the group's cash flow for 2022 based on the production guidance which was described before. If you move to the gas, it seems a random number, but of course, as you know, there's a pretty significant seasonality in gas prices in everywhere but especially in Canada, in North America.
We're taking into account the seasonality. We have the winter quarters Q1 and Q4 in 2022 at CAD 3.5 per Mcf and CAD 2.75 for the summer months. We'll show you the impact of running sensitivities of ±$5 per barrel on the WTI, WCS differential, and the same for CAD 0.50 per Mcf, up or down on gas prices. The result is that based on our production guidance of 46,000-48,000 barrels of oil equivalent per day, with a capital program excluding abandonment cost of $121 million and operating costs pretty much in line flat from last year at $15.2 per BOE.
That translates into realized prices, so revenues of, on a net back basis, so at $45.4 per BOE, which itself translates into $21-$21.5 per BOE net back for EBITDA and operating cash flow and $12 per BOE of free cash flow for 2022. This is the base case, so using a $70 Brent price. Now looking at how we look at realized prices across our portfolio of assets. So with a $70 Brent, we're anticipating to sell our Malaysian crude at a premium of around $3 above Brent price in 2022. It's more like $2.5, which is conservative, but we've already had a book to sell in March, $5 above the Brent price.
In France, we're selling pretty much exactly on parity with the Brent. As I mentioned, with a $3 discount to get to the WTI of $67 in our base case and $54 for WCS. We've made the assumption, which is totally in line with the previous year, that we'll be selling our Suffield oil production at around a $1 discount to the WCS, which is the heavy oil benchmark Canadian price. Onion Lake exactly on parity with WCS. That is the result of what we've seen and heard before that we're blending from the next few days or weeks. We're gonna blend 100% of Onion Lake production giving it the exact specs of the WCS, where we'll be selling on WCS or LLB, which is $0.20 premium over WCS.
Looking at the gas, we realized a gas price of CAD 3.7 per Mcf last year. Even if the market is still very supportive and constructive, we took a slightly more conservative view for 2022 to set our budget. We have our AECO, as I was referencing, including that seasonality between the winter and summer days in 2022 of CAD 3.13 per Mcf. Because we're selling at a so-called Empress price, which is literally on the Alberta-Saskatchewan border, our realized price is around CAD 0.10, CAD 0.11 higher. We're using 3.24 for the forecast this year. Now in terms of cash margin netback, which really are revenues less operating costs.
You can see that in our base case with a $45 per BOE realized price, we would generate a cash margin net back of close to $22. One point two dollar better than in 2021. That is the results despite almost the exact same oil prices slightly below. This is the result of a higher content of oil in our oil and gas product mix. We're going to produce a bit more oil proportionally compared to 2021 and also more, at least the guidance is 1,000-3,000 barrels a day higher in our guidance compared to 2021.
In terms of the previous slides, the revenues, those revenues forecast include some of the hedges we have put in place in the beginning of this year. Just to be clear, we have no hedging covenants. I'll come back to that. We don't have any more bank facilities imposing any hedge covenants. We have left all of our French and Malaysian Brent oil-linked production unhedged, fully exposed to current prices, which is obviously great given what the spot prices are. In Canada, we've done two things, one on the oil, one on the gas. We've decided to hedge the WTI, WCS differential at $13 per barrel for the March to December period. On average, we've hedged 60% of our oil, Canadian oil sales for the remainder of this year.
13 is actually the exact average we witnessed over the last three years in 2019, 2020 and 2021. But you can see on the graph that that differential has been quite volatile. We just wanted to provide our business and our investors or shareholders with a clear view that this $13 was gonna be flat for at least 60% of our production. On the gas side, we've hedged some of our gas production, roughly 25% in Q1, 35% in Q2 and Q3. We've left the winter, which is traditionally stronger unhedged so far, but we reserve the right to do more. For Q1, what you can see on this slide is the AECO hedge, but as I mentioned before, we're sitting on an Empress basis.
Actually when you combine the two, we're expecting that this 25% hedge will translate into a CAD 4.6 per Mcf realized price in Q1, and CAD 4 per Mcf in Q2 and Q3. That was for the revenues. Just to mention that those were including the hedges in place. Now, on the cost side, you can see that because production is going to increase over the year, and because we have some OpEx, some specific project of workovers in Malaysia for the Bertam field, as well mentioned before, the costs are a bit higher during Q1 while the production is a bit lower.
You can see this in this graph that operating costs per barrel are going to reduce over time this year to actually go down to pretty close to $14 per BOE. $1 below the annual guidance and also $1 below our 2021 realized average OpEx per barrel. Now what does it mean in terms of operating cash flow netbacks and EBITDA? Well, in our base case, we would be again pretty much in line, slightly better again, thanks to a bit more oil production in our product mix in 2022. We would be generating an operating cash flow of $21.5 per BOE or $21 for EBITDA netbacks in our base case.
You can see that when the Brent increases by 15 $ per barrel, the impact on operating cash flow netbacks or EBITDA netback is around $8 per barrel. When oil prices move up or down 15 $, the impact on operating cash flow netback is around $8. In terms of the profit netback, I think on this slide, I just want to mention that, interestingly, we have more depletion and depreciation that we're going to spend on CapEx in dollar terms or on a dollar per BOE basis. That shows how efficient we are in our CapEx spending because we're going to maintain, actually increase our production year on year while we spend less than our depreciation.
Now, in terms of cash spending, you can see that our G&A are essentially flat, under control. It's a bit conservative here, but around $0.7-$0.8 per BOE. Financial costs, despite the fact that we are de-leveraging very fast, because we've issued bonds, which are slightly more costly than the bank facilities we had in place, our financial items are gonna be around $2 per BOE. I'll come back to that. The taxes you see here are not the cash taxes. They include deferred tax and I'll come back to that. In our base case, net results of $8 per barrel, in line with 2021, despite slightly higher financial costs.
In the actual current scenario, which is closer to the high case, a net profit of closer to $15 per BOE. Looking at the sensitivities now on our operating cash flow or EBITDA, you can see that because we've hedged 60% of that WTI, WCS differential, even if that differential was to move ± $5 per barrel, the impact on the operating cash flow netback is only $1.3 per BOE. That's the case in all scenarios. This is for the base case, but that would be the same in all scenarios. $1.3 per BOE translates into a ±$22 million.
The impact of a $5 move of this differential is quite limited, thanks to the hedging program we've put in place. Same thing here on the gas. Should gas prices move up or down by CAD 0.50 per Mcf, the impact on operating cash flow at EBITDA on a net back basis would be 0.4 $ per BOE or around $7 million. Now this slide is of great interest obviously, because now we're talking free cash flow. You see the cash available for investment and how it translates when we've spent the CapEx into the free cash flow. Just one small note.
You can see that the CapEx here on the dollar per BOE basis is reducing with higher oil prices. That is just the result of the fact that, as part of the CapEx here, we include our appraisal activity. Essentially the third well pair, which we're testing on Blackrod. This well pair generates positive operating cash flow. The CapEx reduces when oil prices increases. Not the development CapEx, but development CapEx plus our appraisal. Long story short, when the Brent price increased by $15 per barrel, our free cash flow per barrel increases roughly by $8 per BOE. You see here the result.
We could go in a very high case up to $27 per BOE of free cash flow. Finally, I touched upon or I gave a hint that our finance cost will be slightly higher in 2022 compared to 2021. That's the result of what we've decided to do on our balance sheets. We've issued bonds a few days ago, $300 million of unsecured 5-year bonds at 7.25%. We use those proceeds to fully repay and cancel our two previous revolving bank facilities. We had no pressure to do that. We just wanted to take a longer term view and solidify further the balance sheet and be ready to move should we find an exciting M&A opportunities.
Just to be complete on our new capital structure, we also have put in place a two-year revolving credit facility with our main Canadian banking partners of CAD 75 million, which is essentially unused. Thank you very much. From here, I will leave you in the good hands of Rebecca.
Thank you, Christophe. Welcome to the final section of our presentation today. I'll be going through the assumptions behind our reserves valuation and giving you some split of the assets in terms of value. For this final section, I'd like to start with some of the assumptions behind our $2.5 billion worth of NPV8. Really, one of the most important assumptions here is the long-term Brent price forecast. As you can see, in last year's reserves evaluation, we had our reserves audit to price deck, which started at actually $48 in 2021, and then moved to what effectively is a $55 long-term oil price.
This year, we've seen an increase, which is related to the increase in oil prices over the past year, which has gone to a $70 barrel effective medium term forecast with $75 a barrel in 2022. What we've seen with these forecasts is that traditionally, the oil price is running ahead of these forecasts because as you can see with the spot price of around $90, what we have is about a 30% increase over the $75 a barrel in 2022. Actually almost a 100% increase over what was forecast to be the Brent oil price in 2022 at the beginning of last year. If we now look at what that means for our Canadian price forecast, you can see again, a big increase in where the spot price is sitting versus the forecast.
We've seen an increase relative to the year-end of 2020 from $38 a barrel of Western Canadian Select in 2022 to $61 a barrel. We've also seen a big increase in our Empress gas price, but only in the short-term. From CAD 3.30 per Mcf, it's moved now to CAD 4.40. This is a short-term movement related to the gas price this year that Christophe's already talked about. In the long term, it reverts back to this CAD 3.50 per Mcf. Again, a spot price that sits at around CAD 5.25 at the moment. When we move from pricing, which is one aspect of our reserves evaluation, we then add another component, which is our reserves price forecast.
Which then go into a valuation, which we publish at the end of each year as part of our regulations to do with being listed in Canada. This NPV is extremely important because it encompasses not only our technical profiles at different reserves categories, but also what happens at different price decks and how this value has changed over time. If we look at 2020, first of all, which was around $70 a barrel in this sort of medium term forecast, very similar to where we are today. We had a $2.4 billion NPV. We had $300 million of debt at the time, which led to a $2.1 billion net asset value.
Of course, in 2021, we moved to the extremely penalizing forecast, which was $48 Brent in 2021, moving to a $55 a barrel long term, and the net asset value dropped to $1.3 billion, still with around $300 million of debt. If we now look forward, and given we've got reserves replacement of 91% this year, which Will has outlined in his presentation at an increase in price, what we've seen is, first of all, from 2021 to 2022, if we run our new technical profiles at last year's price deck, we still have an increase from $1.3 billion to $1.4 billion net asset value. That's a combination of these thing, of these two things. It's an increase in our reserves levels as we spoke about previously.
It's the quality of our projects, and it's the decrease in debt, which came from $321 million to $95 million. Then we move from the $55 a barrel long-term oil price to what is the current reserves report forecast, which sits at $70 a barrel. This then moves from $1.5 billion to $2.5 billion with a $2.4 billion net asset value. If we then look at this is a little bit more detail than we usually give, but we really wanted to emphasize the increase in value that we've seen and also what it means at different reserve categories compared to our enterprise value of $1.1 billion.
Now, Mike has spoken about our enterprise value versus our 2P NPV8. And what we've seen is that we've got a 58% discount to net asset value, which is an extreme discount. Even when we look at reserve categories such as PDP, which is basically if we do no investment programs, such that was outlined today by Chris Hogue and Will as part of their presentations. If we just let the assets run down, then we still have an NPV8 PDP of $1.1 billion. A part of that is to do with the technical strength of our assets. It's also to do with the fact that we have $1 billion US dollars worth of tax balances in Canada, which we can use against our taxable income there.
It's to do with the fact that with that long-term oil price forecast, we can still retain this value even at a PDP level. Going to a 1P level, we still have $1.7 billion worth of value, and then there's our NPV8 at 2P of $2.5 billion. Of that, 60% is in the developed portion of our portfolio. If we then look at how to split this 2P NPV8 in terms of SEK per share, you can see that compared to our current SEK per share oil price, Onion Lake Thermal is almost SEK 69 per share. That is actually more than our current oil price. That represents around 49% of that NPV8 2P value of the SEK 148 per share that we can see on the left-hand side there.
Malaysia and France still have a healthy SEK 19 per share worth of value. Then the other Canadian assets combine to make up the rest of our portfolio. I hope this shows you the value of our portfolio. We do have fiscal terms available on our website. They've been posted today. They'll show you all of the tax balances and how to calculate in more detail if you want to look at modeling out our assets. Now I'd like to pass on to Mike Nicholson for the conclusion, and then we'll go to questions. Thank you. Mike?
Okay, Rebecca, thank you very much for your presentation. Also thank you to Will, to Chris, and also to Christophe for their presentations. I think we've given a huge amount of detail, and I hope you'll all agree that IPC has had a tremendous 2021, but also is well positioned to continue to lift the company to new heights. Just as a recap, in the 2022 highlights, we're lifting our production forecast this year to 46,000-48,000 barrels of oil equivalent per day. We're still maintaining good cost discipline. The OpEx per barrel is still relatively low at just over $15 per BOE.
We've got a balanced CapEx program that you've heard from both Will and Chris that's attacking growth on all of our core assets in Canada, in Malaysia, and in France. $127 million program for 2022. That still, with the strong commodity price environment, allows us to generate significant free cash flow. The program is fully funded down to below $50 per barrel. As you look at commodity prices going from $55 up to $95 per barrel, we're looking at a range in operating cash flow from the low side down to $222 million, up to $635 million at the high side of that forecast.
In terms of the free cash flow generation, you're looking at $60 million on the low side and up to $480 million on the high side. That represents close to 45%-46% free cash flow yield at close to current oil prices. Simply phenomenal. We haven't got, as you've heard in Christophe's presentation, any benchmark hedges in for the Brent or the WTI. We've felt it's prudent to lock in 60% of our WCS exposure, and we've been able to do that at good prices of $13 per barrel, which as you've seen from Christophe's presentation is great by historical standards.
We've also locked in a material proportion of our gas for this year, given the strength we've seen in North American natural gas prices hedging 30% of our production at a very favorable CAD 3.70 per Mcf. The balance sheet starts 2022 in great shape, given the good performance from last year. Net debt is down at $94 million. If we look at the cash flow generation at the high end of our forecast, where current oil prices stand, we should be net debt free sometime in the second quarter. The leverage is also very low at around 0.3x net debt to EBITDA.
Phenomenal reserve replacement ratio in a low CapEx year in 2021, above 90%, keeping our reserves flat at essentially 270 million barrels of oil equivalent with a 16-year reserve life. A low decline quality 2P reserve base. Material uplift from the great work that we've seen in Canada by our Blackrod team, adding 300 million barrels of oil and lifting our contingent resource base up to now in excess of 1.4 billion barrels of oil equivalent. When we take the 2P reserve book. As you've heard from Will and from Chris, you've seen year after year, we are able to find more oil and increase the size of the fields that we own and operate. If we assume a static reserve position and not a single dollar value attached to that material contingent resource base.
Using our latest reserve auditors price deck, as Rebecca has shown, which is anchored off a $70 long-term real price from 2024. You see IPC's 2P share value stands today at SEK 143 a share. We're currently trading at a close to 58% discount to that 2P net asset value with a material upside in the resource base of the company. Finally, well on track with our sustainability strategy, with our commitment to reduce the net emissions intensity by 50% through the end of 2025. That's the short-term performance. As we look ahead over the next five years, I think IPC has never had such a bright future. We're lifting the long-term five-year forecast of our production now up to 47,000 barrels of oil equivalent per day.
Between oil prices of $65 per barrel on the low side and $95 per barrel on the high side, we expect to generate aggregate free cash flow over the five-year period of in excess of $900 million in the low side, which is an 18% free cash flow yield, well above industry averages at higher prices. In the high side environment, in the more bullish scenario, in excess of $1.8 billion or a 36% per annum annual free cash flow yield. That really provides an amazing platform to continue to grow the company, to continue to add value for all of our stakeholders, whether that be in the form of returning capital to our shareholders in the form of further M&A. You've seen that's in our DNA.
You've seen the $1.7 billion of value that we've created in our first five years, but also the work that the team in Canada have done in maturing our significant contingent resource base. I think the company is in great shape to generate a lot more value in the next five years. That concludes the presentation part. Enough time for us talking. I think we can pass across now. Rebecca will moderate the Q&A session. Reba, right across to you.
Yep, maybe we start with the questions from. Yeah. What's going on here? Can you hear us from the operator?
Yes, thank you. If you you do wish to ask a question, please press zero one on your telephone keypad. If you wish to withdrawal your question, you may do so by pressing zero two to cancel. Our first question comes from the line of James Hosie from Barclays. Please go ahead.
Hi there. Good afternoon. Just a couple of questions from me. First, on your shareholder returns plans going forward, should we be expecting you to be announcing some forward returns on a quarterly basis through this year? Just on the Blackrod project, just wondering if you could give us a timescale for when you may be looking to commit to that capital expenditure of just over half a billion dollars and the timeframe to getting up to the 20,000-30,000 barrels a day phase one production.
Yeah, James, let me take those questions. Yeah, I think with what we've said with the capital returns framework, for the time being, obviously we did announce the share repurchase program that commenced back in December of last year. If we assume an average set per share repurchase price of between, say, SEK 60 and SEK 80 a share, that's around $65 million-$85 million this year in potential share repurchases. I think we've got enough time to continue with the plans that we have in place. It's likely to be later in the year before we announce any additions to the current program that we have in place.
The details in the MD&A, what we said in terms of the potential timing to first oil is in the range of 5-6 years. Really the immediate priority, as Chris mentioned in his presentation, is spending the small dollars right now. We're moving forward with the FEED studies, which is around $4 million in investment, and that allows us to define much better the costs and the execution schedule and to start to move the project forward to the next stage.
Okay. Of that, the spend up to first production of $540 million, would that potentially start getting spent through 2023 and 2024, or does it come later than that?
Yeah, I mean, the majority, you would start potentially, James, in 2023, but the majority would be 2024 and beyond.
Okay. Thank you very much.
We have one more question from the line of Mark Wilson from Jefferies. Please go ahead.
Yeah, good afternoon, and hello again. Very clear presentation. I'm just wondering, the 47,000 barrels of oil a day potentially suggests like there may be some upside risk to that. As an example, and maybe to be specifically, Onion Lake thermal, you spoke about that producing at 14,000 capacity, but the slide shows it at about 12,000 capacity. Could you just speak to the upside potential maybe against those longer term areas and, for instance, on Onion Lake, is there latent capacity yet to be added?
Yeah, it's a very good question, Mark, and the short answer is yes, and it really depends on how much capital we decide to allocate to facility expansion. As Chris set out in his presentation, we've currently got around 14,000 barrels a day of capacity. We've obviously invested in the D- pad ramp up last year, and the 5-well infill program, and Chris highlighted that there's another couple of infill wells to come this year. That should start to push us up towards that 14,000 barrels a day facility capacity. We're obviously gonna be starting with the investment on the next sustaining pad, which is L- pad. We won't see much production from that this year.
Again, as we move into 2023, that should give us the flexibility to stay much closer towards that 14,000 barrels a day capacity limit. Then it's a decision on do we allocate more capital to expand the facilities further? Of course, we've got the potential to add up to another, you know, 2,000-3,000 barrels a day of facility capacity. That's currently baked into our long-term reserve forecast. The short answer is there is room to look to expand Onion Lake thermal by another 2,000-3,000 barrels a day within the five-year window that we're talking about.
Okay. That's very clear. Two, how do you balance the view of further M&A versus the investment into Blackrod should the FEED program be successful in giving you a commercial path there?
I mean, I think the short answer, Mark, is we can do both. If you look at the cash flow numbers, you know, between $75 and $95 Brent, we're gonna be generating $1.3 -$1.8 billion in free cash flow. With the bond issue, we've got $200 million sitting on the books right now. You know, you're looking at $1.4 -$2 billion of cash available to the company. We're certainly able to look to continue to add value accretive acquisitions through M&A, and should we choose to do so, move forward with the Blackrod. For the time being, the focus is very much the small dollars to continue to mature the Blackrod contingent resource base.
As you've seen from the numbers today, starting to crystallize some of that option value.
Okay, thank you. I'll turn it over.
Thanks, Mark.
Just as a final reminder, if you do wish to ask a question, please press zero one on your telephone keypad now. As there seems to be no further questions, I'll hand it back to the speakers.
Thanks, operator. We do have a few questions on the web here, so I'll just direct these through. Perhaps, Mike, you could take this first one. Are there any specific reasons why IPC production couldn't grow at a faster pace? Technical, labor force limitations, infrastructure. Could you give an estimate of maximum production capacity?
That's a very interesting question. I mean, if you go back pre-COVID, back to 2019, our long-term business plan, we were looking at actually being able to sustain production up towards 50,000 barrels per day. If we decided that we really wanted to ramp up our capital program and deploy more rigs into the field, we can, with the flexibility that we have and the discretion as we operate all of our assets 100%, we could ramp production up faster. What we've seen as we've looked to stress test the portfolio, a more measured approach where you're spreading your investments over a longer period of time actually allows you to do two positive things.
One is you generate just as much free cash flow within the five-year window, and the second thing is you lower your free cash flow breakeven. I think if there's been any lesson learned through the last down cycle, the kind of unchecked growth and spending every single dollar of free cash flow, I just don't think flies any longer for investors. We've taken a lot of time to listen to our shareholders. It's really a much more measured approach that allows us to still achieve and maximize the free cash flow generation while still adding value for our shareholders.
Okay. Thanks, Mike. Perhaps just a follow-on question for you here, Mike. Could you please explain the higher CO2 emissions cost burden starting in 2025, and how much will this account for in a full year?
On the CO2 emissions. Yes. If we look at the average CO2 cost, which is underpinned in all of our 2P NAV valuations, in Canada, the CO2 tax starts at a baseline of CAD 50 per ton, and it increases to CAD 170 per ton through to 2030. What that translates through into in terms of a weighted average dollar per BOE, at CAD 50 per ton, it's around CAD 0.30 per barrel, rising to around CAD 1.30 per barrel by 2030. In U.S. dollar terms, at its maximum, around $1 per BOE across our entire Canadian business.
Okay. Thank you, Mike. Christophe, perhaps you can take this one. We're starting to see inflationary pressures all over natural gas, basic materials and possibly wages. Do you have any estimate on how higher natural gas prices would impact overall OpEx?
Well, I cannot give you an exact dollar amount of increase in the gas price and how much that would translate to into an increased OpEx per barrel. Now, what I can say is that if you look back over the period 2018-2020, our OpEx per barrel were closer to between $12 and $13. Now we're guiding that we're gonna be between $15 and $16. That takes into account already this revised guidance for the next five years on OpEx per BOE, takes into account higher gas prices and the higher cost of energy altogether. Now, this being said, what may look like a negative is actually a positive for IPC because we're producing more gas than we're consuming gas for operations or even consuming energy.
Net-net increased gas prices are positive to our business and will increase netbacks. We're roughly producing 100 million scf a day and consuming 30 million scf. Still 70 million scf a day net.
Okay. Thank you very much, Christophe. Mike, perhaps you could take this one. Got a question on what the IRR is for Phase 1 on Blackrod. Also, are we looking for a partner in the asset, and is the bond issuance intended to fund Phase 1 development?
The bond issue is not intended to fund Phase 1 development of Blackrod. I think there's still a lot more work to do, and we're, you know, using the FEED studies to pin down the cost estimates through 2022. We haven't disclosed the IRR for the project at this stage. The last part of the question, sorry, Reb, was?
Are we intending to take a partner?
A partner. Yeah, I mean, I think it's always. You know, we operate all of our assets 100%, but those are assets that are in production. You know, I think we're in the fortunate position that, you know, should the market conditions prevail, we can still go to the market and test if there's appetite to farm the project down. If we like the valuation that we see, we can always bring a partner in, but we're not obliged to do so. I think we certainly wouldn't rule out bringing a partner in. We're seeing the positive development on the egress position and tight differentials. We've seen the break-even for the project come down on the back of the successful results of well pair 3, as Chris has alluded to, and we're seeing much stronger benchmark prices.
I think all the market conditions are starting to turn in our favor. I think it would make sense to test the market, but we don't necessarily have to take a partner.
Okay. Thanks, Mike. Christophe, perhaps this one for you as well. There's still an enormous gap between the current share price and NAV per share, expressed in a free cash flow yield. Statistically, this is more attractive from the valuation standpoint than IPC's peers. If this gap persists, would management consider a tender offer to cancel bigger blocks of shares on top of the normal course issuer bid program?
I can't agree more with the statement at the beginning. We're trying to explain all the reasons why, which justify this gap. Hopefully the market will naturally come and help us bridge that gap. I think it's a matter of delivering quarter after quarter what we are showing today. I think this morning we posted very good quarterly results, which are the proof that our ability to generate that free cash flow is there. We've announced this afternoon our capital allocation plan to frame the distribution we want to put in place from this year back to shareholders. Now, we already have this NCIB program in place.
We've executed roughly 20% of it, so still quite a long way to go. Now, I can't say in the longer term, at this stage, we have no intention to do such a drastic move. We need to wait and see how the market reacts from where we are. We're very well progressed in terms of production, in terms of investment. The costs are under control, so we're in a good place to deliver the cash flows that we've shown, especially in our high case around 85. Let's see how the share price bridges that gap before we take a drastic measure.
Maybe just one follow-up from Christophe's point. We have done both in our history. We did do a tender offer back in 2017 and in 2019. As Christophe says, last year's program have been under the normal course issuer bid rule. I think all of those tools remain in place.
Okay. Thanks, Christophe, Mike. Chris, do you have any estimate on how higher basic materials that we have today, the cost of higher basic materials could impact Blackrod CapEx and OpEx, and so the overall economics of the project?
Great question. As industry heats up, that is always a concern and something we need to monitor and watch. At this point, we factored in just some normal escalation that we need to deal with, but it will not be an addition to where we land at the end of a FEED study. We'll take into account how markets are doing for those basic type of materials or supplies. Always watching that, and it comes into the front-end engineering study.
Okay. Thank you very much, Chris. Will, should we consider IPC active in the Malaysia offshore market? Are we looking to grow inorganically in Southeast Asia?
Yeah, absolutely. We're looking to grow, you know, everywhere, whether it be in Malaysia or in Canada or any opportunity globally, even in France. You know, we have an opportunistic approach to looking at growing the business inorganically. If we're able to do that, where we have expertise and a team in place and good relationships with the regulators and everything already established, that's something really that we can anchor off. However, any acquisition that we're gonna execute, it really has to be accretive to the portfolio, and that's the number one factor that comes into account when looking at opportunities within M&A.
Thanks very much, Will. Mike, just a more general question on M&A in terms of geographic location. Do you have anything to add on geographic location, given the bonds on the book?
Yeah, I mean, I think if you look at what we've done in the first five years, we've always preferred the jurisdictions that are low risk, that the commercial banks will follow and will be prepared to lend and provide acquisition financing. I think if you look at, as Will kind of alluded to in his previous answer, the success of the Lundin family and any of the group companies that are listed is. It more starts with the quality of the asset. We always tend to cast a wide geographical net. It makes sense for us, obviously, to focus on further acquisitions in the area where we have the expertise and the teams on the ground.
If we can find the right opportunity, and we can do so without too much dilution, then we do obviously consider new potential jurisdictions.
Thanks, Mike. We have a couple of questions with this theme. What kind of deal is it possible to make in a world with Brent over 90 and Western Canadian Select close to 70, close to 80, with companies generating a lot of cash and de-leveraging? Where can you find a better deal than buying back your shares?
Yeah. That's the $100 Brent question. So I think, like, obviously, people, you know, are not assuming, you know, $70, $80, $90 a barrel in their long-term economics, and there is still some quite steep backwardation. I think our experience of dealing with the majors is, you know, people are prepared to look at lower long-term oil price assumptions, which I think is different in previous cycles. There's no question that the banks are being more conservative in their lending practices. I think if you like that wall of capital that's available to fund acquisitions is actually a good thing because it's gonna at least keep a lid on the amount of capital that's available for upfront considerations.
I think people are just gonna have to be more creative and look at, certainly in the early part of the life of an asset, is to share some of the upside through continuing oil price payments so that if you're above that longer term price, then there's a share mechanism between the seller and the buyer to reduce the spread between the bid and the ask.
Okay. Thanks very much, Mike. Will, perhaps you could take this one. Apart from Bertam, where are the sort of next couple of assets where you have to invest more to maintain current production rates, so the least remaining inventory of new potential wells?
It's a good question, and I would say, you know, it's pretty even distribution across all our asset base with respect to having to invest some dollars to get the production to increase. Decline rates are really low across all the assets that we have. I think it's something that it's hard to comment on exactly because it's pretty an equal distribution across the assets that we have in terms of maintaining those production levels at where they're at.
Thanks, Will. Christophe, how does gas-related cash flow fit into your framework to return the 40% of cash flow above $55 Brent? I think that's proportion of gas-related cash flow.
Yeah. Well, I guess a third of our production is roughly coming from the gas and a sixth of our revenues are coming from gas. Yeah, the cash flow is anywhere between that third and the sixth. We don't give too many details on cash flows. I must confess, in the first place, we didn't go after the Suffield acquisition for the gas part, and it's proven extremely lucrative. While we were using a $2.53 gas price when we were considering that acquisition, it's obviously much higher, the gas prices today.
It will considerably help into the cash flow mix. Now, in terms of, still the bulk of the cash flow is coming from the oil production, so we've set that condition at above $55. I think the comparable $55 is probably around CAD 3 per Mcf now. Above that will contribute to returning cash to shareholders.
Okay. Thanks very much, Christophe. Mike, just another short question. There's been a lot of rumors lately about a merger with Africa Oil. How do you see their assets? Can you comment?
Yeah, I can't comment. There are no discussions ongoing with Africa Oil at this point in time.
Okay. Short question. I think the last question here. Another question on how much production realistically would make sense in terms of acquisitions, Mike? What kind of free cash flow in comparison to your current assets would be enough to get you to pull the trigger?
I think it's too tricky to put a production target. Because all barrels, of course, aren't created equally. I mean, if you know, obviously if you look in say Norway, where you have a higher marginal tax rate, around 78% relative to some of the jurisdictions that we're in Canada, where you're in the mid-twenties, around 30% in France. We focus more on the value proposition and the cash flow generation potential of the targets. It's always dangerous to give yourself specific production targets. I think as both Will and I have alluded to, it always starts with what's the quality of the asset and the subsurface, the expertise that our team can bring, how can we unlock the value, and is that gonna be material and accretive to our shareholders?
That's the grounding principle, and that's the one that's served not only IPC, but all the other companies within the Lundin Group in creating huge amounts of value for all their shareholders.
Okay. Thanks very much, Mike. I think most of the other questions have been answered through the discussions that we've just had. That will finish up with the web questions. I don't believe there's any more from the telephone.
Okay. Well, thank you first to my colleagues. To Rebecca, to Chris, to Christophe, and to Will for their presentations. Thank you much. Thank you very much to all of you for tuning in this afternoon. I hope you agree that the company has delivered some phenomenal results last year. I think this year's gonna be even better, and the five years and further beyond is an incredible platform to generate a lot more value in the next five years. Thank you for your support and we look forward to presenting the Q1 results.
Thank you.
Thank you.
Thanks everyone.