Okay, good afternoon, and very warm welcome to IPC's 2020 Capital Markets Day Presentation. My name is Mike Nicholson. I'm the CEO. I'm joined this morning and presenting today is Daniel Fitzgerald, the CEO, Chris Hogue, the Senior Vice President from Canada, and Daniel and Chris will be presenting the operations and the asset overview for each of our countries of operations. We'll pause for a short break, we'll come back, Christophe, the CFO, will run through a detailed financial overview. We'll pass across to Rebecca Gordon, who's our VP of Investor Relations and Corporate Planning, Rebecca will walk through the reserves valuation. At the end of all the presentations, we'll of course, open up for questions.
For those tuned in on the webcast, you can submit your questions online, and we'll also be taking questions from those joining us today in Stockholm. Without further ado, I'm just gonna spend one slide to touch upon the highlights from 2019. We did have our year-end results presentation this morning, really the main focus of this afternoon's presentation is going to be to go through the forward-looking plans for 2020 and beyond. If we start with the 2019 highlights, our full year average production was 46,000 barrels of oil equivalent per day, and that was bang in line with the latest Q3 guidance that we gave.
Likewise, our operating costs of $12.80 per BOE were again right in line with the latest guidance and slightly below the guidance that we gave back in our February Capital Markets Day. Very good delivery on our capital investment program. You're gonna see that last year was the biggest investment program that we've had since IPC was launched, and even bigger than this year's. We were able to execute on all our projects and our drilling operations successfully across all of our countries of operation. We actually delivered that full year capital program $4 million ahead of budget. There's $3 million slipped into 2020 budget. I think one of the most impressive results that we had for the full year was the cash flow generation of the company.
If you look at our operating cash flow, it was a record high for the company, in total $308 million for the full year. That allowed us to generate a free cash flow in a heavy investment year of just under $90 million, which was a greater than 12% free cash flow yield, which is pretty impressive when you benchmark that across some of our peer companies. That free cash flow generation allowed us to reduce our net debt from $277 million down to $232 million. In addition to that includes that year-end net debt number includes a 17 million share buyback, and also the repayment of our working capital facility that we still had outstanding to Lundin Petroleum for $14 million.
As Christophe will show, we've still got material headroom under our existing bank facilities. We finished the year with a net debt to EBITDA of less than 0.8 times, so the balance sheet is really in great shape. We'll go through this in a lot more detail in this afternoon's presentation. Daniel will run through that, but 3 consecutive years of reserve replacement through organic growth, close to 90% from our existing assets. Then when you include the acquisition of the reserves from Granite, up to 173% reserve replacement at the end of last year. A material increase in our contingent resource base, up 30% from year-end 2018.
When we look at our shareholder value, Rebecca will go through in much more detail, but, notwithstanding a lower long-term oil price forecast used by our reserve estimator, we've still been able to increase our net asset value per share by 7% to $3.30. Today, that means we're trading at an above 70% discount to our 2P net asset value. Of course, we think our stock is hugely undervalued. We did announce in our Q3 results that we'd launched our second, actually, our share repurchase program, and today we've acquired a total of around 7.6 million shares, which is around two-thirds of the program that was approved.
Active again on the business development front, our third acquisition in three years was announced in January, the acquisition of Granite Oil Corp., 14 million barrels of 2P reserves, 1,500 barrels of production, and 6 million barrels of contingent resource. When Chris walks through his presentation later, we'll talk about the upside and the plans that we have for that asset as we bring it into IPC. A very strong performance on the HSE front, with no material incidents to report, and I'll talk about our plans to strengthen our sustainability strategy in the years going forward. That was 2019.
If we look, you know, what you're gonna see and hear for the rest of the afternoon, since the 3 acquisitions that IPC has made and the significant investments that we've been making organically, the company now has very, very solid foundation to create significant shareholder value over the next 5 years. What you're gonna see is our production this year, 46,000-50,000 barrels a day, but we feel we can keep production relatively flat at around ±50,000 barrels a day for the next 5 years. That's from just a relatively small part of our organic growth portfolio. We've got now in excess of 1.3 billion barrels of total resources.
If all we do is develop that 300 million barrels of 2P reserves, we can keep that production essentially flat at around 50,000 barrels per day. Of course, that puts the company in a very, very strong position in terms of our cash flow generation. If we look at a more bearish market with oil prices, Brent oil prices of around $55 per barrel, we can still generate free cash flow over the next 5 years of in excess of $500 million, which is a 17% per annum average free cash flow yield. In a more bullish oil price environment, $75 Brent, we can generate free cash flow in excess of $1.3 billion, which is a 44% per annum free cash flow yield.
If we look at, you know, more like mid-cycle prices of around $65 per barrel, we can still generate in excess of $900 million of free cash flow. To put that in context, that's more than IPC's entire enterprise value today. At $65 in five years, we can still be producing around 50,000 barrels a day. We'd have liquidated the enterprise value of the company, and we'll still have 1 billion barrels of undeveloped resources, and that's some pretty phenomenal metrics. Of course, that cash flow, that we have, we can continue to invest in our organic growth opportunities. Stakeholder returns become a priority, and as I mentioned, we did announce our share buyback, which started in the Q3.
Further debt reduction and even dividends going forward become an opportunity for us with that kind of free cash flow generation. We'll definitely still be opportunistic with respect to M&A, but as I'll show you later in the presentation, with our stock trading at $0.70 or $0.30 in the dollar, it becomes increasingly challenging to find an asset that adds as much value to the assets that we own. I would say unless we can find value-accretive acquisitions, then certainly the share buybacks and shareholder returns will be taking a priority. I'm just gonna walk through now the reserves growth, and if you look at the chart on the bottom right-hand side of the page, you can see 2019 was another year of reserves growth.
As I mentioned, organically, we were able to replace just under 90% of our reserve, of our production, from reserve increases from the existing asset base. When we include the acquisition of Granite, we actually had 173% reserve replacement at the year-end 2019. That lifts our 2P reserves now to 300 million barrels of oil equivalent. If I can just draw your attention to the graph on the top right-hand side of the slide. That's now 3 years in succession, where we've had significant reserve replacement, 76% in year 1, more than 100% in 2018, and close to 90% last year.
If you aggregate all of that organic reserve replacement and look at where we started 3 years ago, we only had 29 million barrels. We've been able to in aggregate, we've replaced the entire reserve base that we started life with only 3 years ago. In the meantime, what we've also been able to do is increase the longevity of that reserves base. When we started life with our 29 million barrels of 2P reserves in France, Malaysia, and the Netherlands, the Reserve Life Index was only 8 years. With the 3 acquisitions that we've been able to complete, we've increased the longevity of that reserve life to now 17 years, which really does underpin the long-term cash flow generation of our assets and our business. Contingent resources is an even more impressive story.
If we go back to when we started IPC, we didn't have a single barrel of contingent resource, and through organically working the assets that we inherited from Lundin Petroleum, as well as the three acquisitions that we've made, we've amassed a resource base, a contingent resource base, in excess of 1 billion barrels of oil equivalent. The focus that you're gonna hear when Daniel and Chris go through their presentations, is really to try and start to mature all of those contingent resources through 2020, because this is the feedstock for future reserve replacement. In Canada, you'll hear about our Blackrod project and our Granite Field development. We have 6 million barrels of contingent resource adds from the Granite acquisition.
We've had 3 successful phases of infill drilling in Malaysia. Based upon the recent results, we've booked another million barrels of contingent, there's potentially more upside in the Bertam field. I think following on the successful execution of our Vert-la-Gravelle redevelopment, we've got around 6 to 7 million barrels of contingent resources sitting in similar Triassic Rhaetian reservoirs, of course, we're gonna be spending a lot of our time and attention on those projects. Whilst Blackrod dominates the contingent resource base at close to 1 billion barrels, we've still got 100 million barrels in our other conventional portfolio that will be actively matured through 2020. This next slide shows the phenomenal production growth that we've had.
When we started IPC, we said the idea was to launch a company at the point in the cycle where we felt we could acquire, you know, low decline, high value resource and really position the company to create long-term shareholder value. I think this slide shows just how we've been able to do that. We started in 2017, at the year-end, with 10,000 barrels a day of production for the full year. Suffield was concluded in early 2018, there was a 3 times uplift in our production to 34,000 barrels of oil equivalent per day. Last year, with the inclusion of the BlackPearl acquisition, we're up to 46,000 barrels of oil equivalent per day.
The guidance that we've announced this morning for our full year 2020 production numbers is 46,000-50,000 for the full year. Those numbers assume that the Granite acquisition will complete as we anticipate in March, so fairly soon to complete that acquisition. I think, as I mentioned on the first slide, if you look at just our 300 million barrels of 2P reserves and extrapolate what that means in production terms for the next 5 years, we can broadly keep that production flat at ±50,000 barrels of oil equivalent per day. Really solid foundation for generating a lot of cash flow. Turning to the cash flow now.
When IPC started with our 10,000 barrels a day of production, our operating cash flow was just under $140 million. We didn't give guidance then because we only started, we spun off in April of 2017, there was no full year guidance. In 2018, our first year of cash flow guidance, we told the market somewhere between $160 million and $230 million, we actually generated just under $280 million in operating cash flow. This year, we gave a fairly wide range, you're gonna see the same again in Christophe's forecasts. Down at $50 Brent on the low side to $70 on the high side, we had a range of $160 million-$330 million of cash flow.
In the full year results announced this morning, close to $310 million in operating cash flow. Very close to the high end of that guidance range. As we look forward to 2020, we've put together exactly the same set of forecasts that we gave last year. On the low side, $50 Brent and a $20 Canadian differential, and at the high side, a $70 Brent and a $15 per barrel Canadian differential. You can see that the cash flow forecast ranges from $125 million to $325 million.
I'll come to it later, it's on the next slide, but the capital expenditure program is lower this year and continues to drop in the years ahead, which really increases the free cash flow generation nature of our business. Just to put the $308 million from last year in context, our enterprise value is less than $900 million. The company today is trading at less than a 3 times cash flow, or, as I mentioned, a 12% yield last year. What are we gonna spend this money on? The investment plan for 2020 is again, a fairly active program. I mentioned last year was our peak year of capital investment, at over $180 million.
This year's CapEx is down close to 20%, to $149 million, that does include $3 million of carryover from the 2019 program. It also includes the fact that we're starting up already our development program in Canada on the Ferguson asset, which was acquired from Granite, with a $10 million capital addition there, and Chris will talk about what we're gonna be doing. Really the plan is to continue the development success in France. Another 3 wells coming on, one of our big producing fields in France. You'll see the continued success of our investments on the oil and the gas side, on the Suffield asset. Chris will run through that. Further growth spending on our Onion Lake thermal project.
A new pad's gonna be added, a relatively minimal investment year in Malaysia this year. Again, our capital expenditure program for 2020 is set exactly as we did 12 months ago. It's fully funded at a $60 Brent price, assuming a relatively conservative Canadian differential of $20 per barrel. I think it's really worthwhile mentioning that out of that $150 million of capital expenditure, we operate all our assets close to 100%, so we've got huge discretion. If we did decide that commodity prices were gonna stay low or drop over the next 12 months, more than 50% of that project could be put on hold.
There's a huge amount of discretion to ensure that we continue to live within our means and generate free cash flow. This is the longer-term outlook on our capital program for the next five years. As I've mentioned, 2019 was the highest year of investment at just over $180 million. This is the cash flow forecast that underpins our 300 million barrels of 2P reserves, dropping to $150 million this year. You can see how our CapEx decreases over the next five years. If you look at what that means in terms of five-year average maintenance CapEx per barrel, that's less than $5 per barrel of oil equivalent.
It's a very, very low capital, sustaining capital number to be able to keep that production relatively flat at around 50,000 barrels of oil equivalent per day. That's what really, it's that combination of growing production, very low declines, and low CapEx, that really turns IPC into a free cash flow machine. When we talk about the forecast, the longer term 5-year forecasts, to show, you know, those are anchored in reality. If you look at what we've done over the last 3 years, when we launched IPC, we were producing 10,000 barrels a day, and it was a fairly bearish oil price environment. That's when we made our first big acquisition. Oil price averaged $55 a barrel.
Our capital investment was about $23 million, we still generated in that oil price environment, $100 million of free cash flow, a 26% yield in year one. Year 2, capital was still relatively low. It was $42 million. We had acquired the Suffield asset, we really didn't start the drilling program until the Q4, after we got all the permits in place. It was more a fairly bullish year in terms of oil prices. We were above $70 a barrel. Our production had increased threefold, we were able to generate $203 million in free cash flow, a 38% yield in the first year with that acquisition.
When you look at last year's numbers, in excess of $180 million of investment, you know, in a $64 per barrel oil price environment, we were not only able to fully fund that program, but generate $90 million of free cash flow and a 12% yield. As we look at lifting the company towards that 50,000 barrels a day level, and looking forward over the next 5 years with that investment program, and not a single dollar spent on our contingent resources in a bearish scenario, more than $0.5 billion of free cash flow. In a more bullish scenario, in excess of $1.3 billion of free cash flow, with a yield between 17% and 44% per annum across that oil price spectrum.
As I mentioned in the introduction, at $65 oil, we can liquidate the enterprise value and still be producing roughly 50,000 barrels a day, which is a pretty extraordinary metric. Turning now, before I talk about the valuation, the other side of the equation, I think it's worth touching upon the Canadian supply and egress positions. You know, when the company was launched, and we made our first acquisition in Canada, it was a, it was a very deliberate approach to go into a market that was facing some challenges and some headwinds. We saw a jurisdiction with High quality, low decline assets that, you know, with minimal investment, we could increase production there.
It had been a tough market, years of low oil prices, compounded with a lack of export infrastructure, which had driven differentials in Canada to very wide levels. We saw that as an opportunity to move in, to aggregate a big reserve and resource base, and position the company for a recovery for the medium to long term. If we look at what's happened on this slide, on the right-hand side, we did get a boost from the government last year when enough was enough, and differentials blew out in Canada in late 2018 to an excess of $40 per barrel. The Alberta government said, "We're no longer gonna accept Canadian crudes being sold for less than the fair value." $80 million per day in tax receipts were being lost.
Production was curtailed to start to manage that situation, which is what you can see on the supply chart. As we can see, there was a gap between supply and available export capacity, and that situation has improved. At the beginning of 2018, there was only around 125,000 barrels a day of crude by rail export capacity. Today, there's around 500,000 barrels a day of crude by rail export capacity. When you look at the gap between available egress and Canadian crude supply, there's more than enough rail infrastructure to clear markets, which should set the marginal differential around $17-$18 per barrel.
I think the other thing that, you know, you own infrastructure. There's no new infrastructure coming in place, you're gonna sweat every inch of pipeline capacity. There's been a lot of investment in facility optimization. We've seen existing pipeline capacity increase by around 270,000 barrels a day in 2020. That's forecast to continue to increase over the next couple of years. What that means is, you know, the first big pipeline project, which is the Enbridge Line 3 replacement, that project just had its environmental assessment approved. It was reissued with its certificate of need. The consensus on the street seems to be that pipeline should be in service by around the summer of 2021.
When you look at that, you're now balanced with crude supply and available pipeline capacity, so a much more balanced position than we've seen for a number of years. I think when you look at then the next two big pipeline projects, Trans Mountain, there's been a couple of big positive decisions to give some tailwinds to that project. The first was the challenge by the B.C. province, with the right to transport heavy oil through the province, and the second was the challenge by indigenous groups to say that the consultation had not been sufficient.
Both of those have just been set aside in the past month, and the CEO, last Friday, was saying publicly that he's got a high degree of confidence that that pipeline will be completed by the end of 2022, and that all sections of the pipeline will be under construction by the end of this year. Now, of course, I'm sure there's still gonna be some bumps in the road along the way, but I think when we stand today relative to the summer of 2017, when we were looking our entry into Canada, I think there's no question that the overall situation is far, far more balanced than it was. I think Keystone, given it's a presidential election year, there's likely to be still some uncertainty until we get more certainty about where that election is heading.
I think that feeds through into value. Obviously, there's been depressed valuations, but if you look at the medium to long-term outlook, and you see what IPC has done since we've organically invested in our projects, and we've made our acquisitions. When we started our 2P, net asset value was $543 million, and Rebecca will go through this in more detail. End of 2020, on the latest price decks, which are lower than last year's, we've got an asset value of $2.4 billion. If we take our year-end net debt and assume $60 million from the Granite acquisition, that gives us a net asset value of in excess of $2.1 billion, and that's a 70% discount today.
I think regardless of whether you look at IPC from an operating cash flow multiple, a free cash flow yield, or a value proposition, we look pretty favorable on all of those metrics. This assures those dollar values translated in U.S. dollars per share. When we started life, we were trading at $4. Our NAV was $4.80 per share, and we traded around a 20%, 26% discount to 2P NAV. Over the last three years, with the acquisitions and that organic reserve replacement, you can see there that we've increased our value per share 40% per annum, compound growth rate to $13.30 per share as at the end of 2019.
That's the business, but I think, now, obviously, we've had significant growth, but, you know, you cannot grow a business like this without having a very clear, ESG strategy that goes hand in hand with that growth. You know, we're really strengthening our approach to ESG. We've always invested in our assets to try and minimize the CO2 footprint of our assets. We're making a commitment, and we've got board support to make a commitment to reduce that significantly over the next five years. That's gonna be done through a combination of reducing our operational emissions, and it's also gonna be achieved through carbon offsetting.
If we look at the operational side of things and what we've done in the past with our assets, you know, on the Onion Lake thermal project, that Chris was responsible for. You know, to minimize the CO2 footprint, a huge amount of money was invested in heat recovery and heat recapture to minimize the use of gas in running that project, and that took out about 100,000 tons of CO2 emissions. In our Bertam project in Malaysia, we invested in dual-fuel Wärtsilä power generation equipment, which meant we could recapture the flash gas that was coming off of our oil, and we could use that for power generation to run our ESPs, and that saved about 50,000 tons of CO2 per annum.
You know, really good investments that have reduced our footprint, and of course, our teams will be continually looking and reviewing other areas for potential savings within the existing projects that we have. IPC, if you look at our average CO2 intensity at the end of last year, was around 31 kilograms per barrel of oil equivalent. 80% of our production comes from Canada, and the average CO2 intensity in Canada is around 60 kilograms per BOE. We're already close to 50% lower than where the majority of our production comes from. We're, we're not happy with that, and what we've got is a commitment from our board over the next 5 years, to lower our CO2 intensity down to the global average of 20 kilograms per barrel of oil equivalent.
What we've already done, we've formed a partnership with First Climate, and we're sponsoring a project which will provide 100 megawatts of clean energy, solar power, in Northern India, in the Punjab region, which will deliver power to over 200,000 people from two separate villages. Of course, in India, 80% of power generation comes from coal-fired power, so by supporting this project, means that we can offset 50,000 tons of CO2 emissions. That's the first step in a 5-year journey to get us down into that global average. That concludes my introduction part of the presentation. I'll pass now across to Daniel and Chris, who will go through the operations in a bit more detail. Daniel, over to you.
Thanks, Mike. It's really exciting to be up here today to share with you our guidance for 2020. Not only for the next year ahead, we're also looking at the five years ahead to see what this company can do over the five years with the asset base we have, and the work that each of the regions has done with that asset base. Any good business plan, it starts with those assets, and it starts with the resources we have to underpin what the future looks like. If we go back to when we spun out, and Mike's touched on a few of these points already. We spun out with 29 million barrels of 2P reserves and 0 contingent resources.
Year on year, our teams are focusing on reserve replacement, focusing on undeveloped resources, and ensuring that we continue to grow that resource base. On the right, you can see in every single country of operation, we've managed to replace significant amounts of reserves. Over that period, since inception, which was only three years ago, we've managed to replace 30 million barrels of 2P reserves. In Canada, we've only had the assets one year for the BlackPearl assets and two years for the Suffield assets, and we've replaced nearly 10% of reserves in Canada as well, which is a phenomenal achievement. Chris will touch on some of that as he goes through his part of the presentation. Our focus doesn't just stop on the reserves position, though.
Our teams, day in, day out, are looking at opportunities to mature more resources into the contingent base, and then turn those contingent resources into reserves, and then develop them to put them into production. And really, that mindset and that focus is what underpins what Mike’s touched on in terms of the cash flow generation of the company over the coming 5 years. In the 2P reserves, we have now 300 million barrels of 2P reserves, and that gives us a Reserve Life Index at this production level of over 17 years. So if we just sat here today and produced at the 50,000 level, so around 17 million barrels, just over 17 million barrels a year produced, we have 17 years of a reserve base to continue that.
If you look in the top right of this chart, you can see how much of that resource base is already on production and developed, and how much is in the future still to be developed. You see that 60% of our resource base is already on production and doesn't require further capital to continue that production. One of the strands of our business is to convert the undeveloped reserves into developed and into production. You see there that most of the 2P undeveloped reserves is sitting in the Onion Thermal asset, and that's a program where we have the facilities in place. All we do over the coming 20 years is to put more well potential in the ground and keep production flat on Onion Thermal. When we look at our resource base as a whole, somewhere around 90...
Excluding the Onion Thermal asset, 90% of that resource base is already in production. When we take that forward, and you'll see soon what the CapEx and production profiles look like in the future. When we take that forward with 90% of our assets, excluding Onion Lake, already on production, it underpins the cash flow forecast that Mike's alluded to in the front of this presentation. In the reserve replacement, we hit 89% out of our organic reserve replacement with the assets we already hold. That's replaced 90% of the production we delivered in 2019, and if we add on Granite, we hit 170%. As we roll forward into the five-year plan, that assumes we don't do anything else in terms of reserve replacement.
The 50,000 barrels a day and the $900 million of cash flow at $65 a barrel assumes we do no more in terms of maturing contingent resources into reserves and assumes we don't do anything else on the acquisitional growth side. That's a really strong position to be in as we, as we move into the next 5 years. In the contingent resources, 2 major additions this year in contingent resources. One, we've managed to acquire lands close to our Blackrod property, and that's added just shy of 240 million barrels to our contingent resources, and then we have a small addition through Granite, the acquisition of Granite. On top of that, we also have some more infill opportunities in Malaysia, which has added a small number in, into this.
When we look at this contingent resource base, 100 million of that contingent resource base account is for all of the assets, excluding Blackrod. If we put Blackrod to the side for a minute, we have a third of our 2P resource base sitting as contingent resources, and our teams are constantly looking at opportunities to mature those resources into reserves, and that will continue as we move forwards. We'll spend a little bit of time now on the 2020 guidance, and then we'll move into the longer-term guidance before we step into each of the assets and the projects that we have in each asset. Our production guidance for 2020 is between 46,000 and 50,000 barrels of oil equivalent per day, and that assumes a full year of the Granite production accounted for in that number.
As you can see, this guidance range ramps up towards Q4, that's because a lot of our projects, through the course of 2020, are starting to come on stream in the second part of the year. This year we'll be continuing with the Suffield Oil and Gas development options, opportunities. That'll continue for the full year. We're investing at the moment, drilling's ongoing in Onion Lake for the D prime wells, which will add another just shy of 2,000 barrels a day to our Onion Lake production this year, Chris will touch on that in a little bit more detail. In France, you'll see the Veligreville project is ramping up now, we have Saint Chenil Pedou, which will be drilling in Q2 and on stream towards Q3 and Q4.
If we add all of that together, we see production today ramping up through the course of the year and especially in Q4. The mix of production is similar to what we had through 2018. Sorry, 2019. We have just shy of 20% from the international assets and the remaining 80% from Canada. As we see Granite and Onion Thermal ramping up in Canada, we start to see the mix moving a little bit more towards the oil side rather than the gas side in Suffield. On the operating costs, we're guiding 2020 at $13.70 per barrel, per BOE, sorry, and that's an OpEx that's reduced around 15% since spin-off. We started IPC back in 2017 at around $16 a barrel.
That has the normal provisions in it for maintenance, shutdowns, workovers, downtime, et cetera. The capital program. As Mike touched on before, we start to see now our capital program starting to decrease, and that will continue through the next five years as well. This year, we're guiding a capital program of $149 million, primarily in Canada and a little bit more in France. In Canada, we'll see some of these projects a little bit more in Chris's section and where we're executing on our opportunity set and our 2P reserve position in Canada. In France, we have the completion of the Villeperdue project, sorry, the completion of the Villeperdue project, and the Villeperdue project will spud three development wells in Q2.
In Malaysia, we have the remainder of the 2019 infill program, and we have the A-15 remedial works as well, and that adds up to a $149 total CapEx for 2020. Mike touched on this as well. We're operator in all of these countries, and in almost 99% of the production we have. That gives us great flexibility in terms of defining what our capital program looks like. At this stage, if we decided to pull all of the projects out, more than 50% of this CapEx could disappear, and we have great leverage in all of our countries to do that.
We'll monitor through the course of the year what the commodity price environment looks like, and then we'll decide to maintain, as Mike touched on before, to maintain our CapEx program within our cash generation. Now we look at what the next 5 years looks like. Over the next 5 years, we believe we can maintain our production at or around that 50,000 barrel of oil equivalent per day. Now, the assumptions that go into that is it assumes we only liquidate our 2P reserve position. In Malaysia and France, we have a program in 2020 that completes the infill wells in Malaysia and delivers Villeperdue in France, and it assumes we do no more activity in either of these two countries.
In Canada, we have ongoing developments in Onion Thermal, and that's primarily the sustaining capital and some facilities work on Onion Thermal. We have the ongoing developments in Suffield, in our 2P reserve base, and you've seen what the benefits of doing those over the last few years has been. Chris will show you the decline rates through the Suffield asset. That's really all that underpins that 50,000 barrel of oil equivalent per day guidance. If we're able to add in acquisitions, further organic growth, maturation of contingent resources, then we have the opportunity to be at the upper end of that guidance. If we choose, on the other hand, to take a discretionary view to reduce CapEx and reduce projects, obviously the production will come down, depending on which projects we choose to invest in or not.
When we look holistically at that five-year program from a cash generation perspective, as we dial back the investment program, we see the CapEx coming out, and we see that overall cash position maintained. The projects that we execute in 2023, 2022 even, pay out over a 2 to 3-year window, the CapEx and the cash generation offset each other. Even in a downside environment, what we would do with this business plan is choose to invest less CapEx. However, that cash generation is maintained through that period.
When we bundle all of that together from the reserves position, the big CapEx programs in 2018, 2019, 2020, and the position we have looking forward in terms of our assets, with around 90% of our asset base, 2P reserves, excluding Onion Thermal, on production, we're in a really strong position as a company now with all the levers to pull in terms of investment, cash generation, and production. That's a really strong position to be in. We won't just stop at that 50,000 barrel a day and 2P resource position. All of our teams are consistently looking at opportunities to grow the production base from a contingent resource perspective.
With the acquisition of Granite, with the acquisition of BlackPearl and Suffield, plus the work ongoing in France and Malaysia, our opportunity portfolio continues to grow. We continue to add future projects into this funnel that we're maturing through the decision gates with a choice coming up as to whether we invest or not. We remain in a healthy position as a company with 50,000 barrels a day, 300 million barrels of 2P reserves, significant opportunities in the contingent resource base, and all of the levers to pull in terms of how we deploy our free cash flow generation into these assets. I'll pass over to Chris, who's going to touch a little bit more on Canada before we round out with France and Malaysia. Chris?
Thank you, Dan. Canada. We're 38,000 barrels a day equivalent today in Canada, growing to close to 40,000 throughout this 2020 year. Starting from the north in Alberta, we'll just kind of give you an overview of the asset. Our Blackrod asset, to the furthest to the north, is our largest single contingent resource base. It's about 1 billion barrels of resource at Blackrod. It's a shovel-ready, 80,000 barrel a day project with the regulatory approvals in place, and we've been piloting it for almost 8 years of different shooting seismic, drilling evaluation wells, and actually have 3 well pairs of production pilots into it. We'll talk about that a little bit later. Mooney. Mooney has some running room at Mooney. It's a polymer flood, so it's a viscous water operation and use some soap.
You put some soap in there to scrub the rock as well. Onion Lake is just on the Saskatchewan sides, in the province of Saskatchewan. It's a thermal heavy oil project. There's also some conventional heavy oil there. What's exciting about Onion Lake is the oil produces on primary production, so it's a very good oil quality, very good characteristics. When you add the thermal, add the steam to it, you just improve recoveries drastically to better than 50%. Continuing to move south, in Alberta, we have our Suffield asset, so it's a large asset with both oil pools and gas across it. We continue to have a program there to more than offset the production that we have.
Right to the south, we've heard this, there was a corporate transaction that's underway right now, expected to close early March. That was called the Granite Oil Corp, and that asset's called Ferguson. It's a light oil, high-margin barrel. It's about 29 API oil, so pretty exciting. We don't require any condensate to be able to sell this in the market. We'll start with the Suffield asset specifically. Suffield is made up of a number of different oil pools and then a large gas field. The oil pools, we continue to exploit with a drilling program, year after year, that is doing more than offsetting decline. You can see in the bottom right-hand plot of the oil production, you can see from our drilling program in 2019 starting to come to play now.
You see production again, seeing a lift, and we're continuing. We've already started a drilling program in 2020, with another 20 wells in 2020. You can expect to see more than an offset of decline in the oil pools. On the gas side, similar story. Interesting, it is on the Department of Defense, when you go out there, all the infrastructure is actually below ground, and it has a lid over top of it. These the tanks from the British or the Canadian military can drive right over top and do their battlefield games. You can't even really see any of the assets that's out there. It's quite interesting.
If you go and take a look, you don't even understand there's any assets out there because everything's buried underground, the facilities and the wells. It's a pretty cool operation. That program, there's two types of things that happen there. There's a inventory of wells that you can identify, bypass, pay and perforate it and bring on incremental production. Large inventory of wells that we're able to continue to rework that again, is doing more than offsetting decline. Keeping lots of value to the property. This asset is our Ferguson asset. This is currently the corporate transaction that is underway, expected to close in early March. Key thing about this asset is it is a high-margin, light oil barrel. It's located about 40 kilometers north of the U.S. border. It doesn't require any condensate to sell it.
We're able to push it into the markets without buying condensate. We do see a premium. When we look back at what it received in 19 to all of our other assets, we do see a premium to WCS as a WCS index. We see somewhere around $9 per barrel premium to the WCS index out of this particular asset. Lots of running room in this asset. A little bit about the asset has new drilling targets that are within the existing defined pools. These are new targets that we'll be able to drill, hope to get at least a half a dozen of them drilled and on production before this year is out, is in the current plan. There's also a higher recovery through the repressurization of the existing produced part of the pool. It's been produced for a few years.
First well was in 2012. The pressure has started to come off. There's a repressurization strategy that we plan to do, which will boost recoveries from the existing part of the pool as well. Kind of a two-part development program. The asset isn't very complicated. It's a single reservoir, very homogeneous from one end to the other, so it's really understood and well-defined. Therefore, we feel very confident in the repressurization strategy that we plan to use. Onion Lake Thermal. Large reserve category asset here. It's being developed in two phases. A phase one, you can look on the map, is shown as pads A and pads B from a nomenclature perspective. That was phase one. Phase two were pads C and pads E. Those were, that's four total pads for the second phase.
Pad F was our first sustaining pad that we've drilled and have just started to put on production now. It's just starting to produce in the last few months. The infrastructure in the field allows us to maintain 14,000 barrels of oil per day for the long term. That is the current infrastructure that's in place for 14,000 barrels a day. We're gonna look at a facility expansion, put some more capital in to accelerate the production of the prize that is out there to 16,000 barrels a day. A 2,000 barrel a day incremental production to take it to 16,000 barrels, and then we just continue to drill sustaining pads to maintain 16,000 barrels for the long term. This is the 20-plus year long term.
The D prime pad, which you can see on the plot, up to the left of the plot, that is currently being drilled right now. That was part of our 2020 CapEx program. It's currently being drilled as we speak, and we expect to start steaming it in the mid-half of 2020, and then start seeing production in the latter half of 2020. Expect to exit this year without the conventional production that's produced in the area, approximately about 14,000 barrels a day from this thermal project, exit 2020. Blackrod. We talked about Blackrod, pretty exciting project, 80,000 barrels a day project, shovel-ready, ready to go, build in a few different phases to manage the CapEx at any particular phase.
For 8+ years, we've been piloting wells, piloting production wells, SAGD, conventional production wells. We've been drilling evaluation holes to understand and define the resource, we've been shooting seismic. It's well-defined. We do understand it. It's a project that is ready to move forward. A little bit about the pilots that we've done to really base the results on something very, very true. Well Pair one that you can see on the map, shows it being drilled to the west. The heel-to-toe profile moves from east to west on that particular asset. That was around a 700 meter horizontal well bore from heel to toe. We produced Well Pair one, and it was successful, and we were happy to see the results.
We wanted to continue to push it to see, you know, before this goes commercial, what can we do to further refine the capital required to get this to production? We did a Well Pair two, and Well Pair two is drilled about 950 meters, heel to toe, horizontal, and that's moving from south to north. That's the second bore you can see, moves from south to north, about 950 meters. Again, drilling longer so we can reduce the amount of wells that would be required when a commercial project comes. That well is currently producing now. It's in excess of 900,000 barrels of oil produced, cumulative.
It's on its target to produce and exceed kind of what we have modeled in terms of over 50% recovery in what we expect to see there. Well Pair two will be shut off as we bring on Well Pair three. The facilities are set up to really attack one well at a time. We're currently, Well Pair three was drilled in 2019. We've successfully drilled it to a 1,450-meter length from heel to toe. Again, trying to push the limits to reduce the amount of wells required for a commercial development. It was drilled successfully. We're very happy with it. It's flat. We love the resource that we see, very excited to see this production come on.
We're currently starting to steam this well now, and we expect to be producing it in the second half of 2020. It does have a ramp-up over the next 1 year. It'll exit this year at a healthy rate of about 400 barrels of oil per day, then it'll continue to ramp to about 800 barrels a day in 2021. I'll just summarize. You know, we're 38,000 barrels a day with lots of growth opportunities to work on in Canada. Fair bit of running room with our existing assets to continue to mature resources to reserves and continue to produce the reserves that we have. 2020 is gonna be a fun year. Lots of activity and should be a fun year.
That's it for Canada. Thank you.
A few slides now, just on the international assets before we pause for a quick break. Malaysia, it's fairly simple in terms of the strategy and outlook for Malaysia, and it's do exactly what we've done over the last couple of years with our infill campaigns. We continue to maximize value from the field, and you'll see a little bit more about the northeastern area, where we've just drilled the A20 well. We're opportunistically looking in all regions, whether that's Canada, France, Malaysia, and international, at opportunities to grow the business through organic growth and acquisition. Malaysia's been a really strong cash engine over its time with IPC, and before that, with Lundin as well, and we see consistent value additions and resource additions through the infill programs.
As you can see here, this is the summation of the 3 infill programs we've had over the last couple of years. In the bottom right, you see our pre-drill in the purple color. You see the pre-drill expectation of each of these infill campaigns. In the green bar, you see how much oil we've produced out of each of these infill campaigns, and the blue bar is the remaining reserves. In the first 2 infill campaigns, which was A15 first and then A16, 17, we've now produced more oil than what we had as our pre-drill expectation, and we've got that amount of oil still to go in terms of remaining reserve.
The third phase, we've seen A20 coming on stream in January, which concludes that phase of infill drilling. We see expectations roughly in line at this point, roughly in line with what we had as a pre-drill prognosis. We'll see as A20 beans up and stabilizes and the other wells, how that looks in a year's time once we've had some more production performance out of these infills. On the bottom left, you see the contribution today that about 70% of our production in 2020 is from these infill campaigns. That just shows how powerful they've been at transforming the business in Malaysia. If today we were producing without completing any of those infills, our gross rates would be significantly lower than where they are.
Through the course of the infill drilling this year, we've matured 2 more locations into contingent resources, and we're working those through the course of the year to be able to execute potentially in 2021. This now is where we're focusing our energy in Malaysia or in Bertam, is on this northeastern area, where we have both the A-15 and A-20 wells. A-15, year-on-year, has seen upgrades in its reserve base, and we've seen strong production out of that well, and so we see further potential in this area. If we roll back to the year-end 2018 reserves, the well we had in A-15 sits in the uppermost portion of this reservoir. You see it on the bottom right graph, or the bottom right picture in the 10.1 reservoir.
The A-20 well, at that point in time, was expected to be a twin well in that 10.1 reservoir. What we found with the Bertam five appraisal well is that we have almost virgin pressure and clean oil in the 10.2 reservoir. The A-20 well, we've now successfully completed in that 10.2 reservoir. That's significantly higher reserves than what we expected at year-end 2018. As we move forwards, we've now got one contingent resource location in each of the 10.1 and 10.2 reservoirs. We'll see through the course of 2020 what we want to do with those wells as we move into 2021. A-20 itself, online since mid-January. We're still in a cleanup and stabilization phase, but we've seen promising results from that well.
As we say in the bottom bullet point on A-20, we don't fully understand the structure as we move towards the east and the north of the A-15, A-20 area. What we saw in the A-20 well is, as you move towards the toe of the well, which is the right-hand side of the dotted blue line on the, on the picture in the bottom right, we see the structure starting to flatten. That's really what we need to understand moving forwards is, what does the structure do in that eastern extent? If it continues to flatten, then we have a significantly bigger pool of oil than we originally expected, and so we'll see that through production performance from both A-15 and A-20 through the course of 2020.
As Mike touched on before, A-15, we've had a minor issue with A-15. We've got the drilling rig out there now. It's ongoing. The remedial works on A-15 are ongoing. We expect to have that well back in production early in Q2. If we step quickly into France, again, a simple strategy in France: execute the two projects we have in our plans at this stage and mature future projects. France has been a cash generation machine for both Lundin Petroleum and IPC for many, many years. Over that period, it's had some capital allocated, but not significant amounts of development capital.
We came with a view as IPC to go and target some of the contingent resources we have in France and deploy the latest technology into the Rhaetian reservoirs, which we've seen significantly positive results in the course of 2019. That's really turned our mindset in France around a little bit, where we had a cash-generative, stable business. We've now delivered the second or third best well in the company in the Vert-la-Gravelle field, and that's really changed our mindset in France. We're spending a hell of a lot more time and energy on maturing existing opportunities that sat in contingent resources with the new results of the Vert-la-Gravelle campaign. If we look first at the resource position in France, then we'll touch quickly on Vert-la-Gravelle and Villeperdue.
We have just shy or just above 15 million barrels of contingent resources, which is only a small amount less than the 2P reserves in France. We have a significant opportunity set in contingent resources. As we were standing here last year at the Capital Markets Day, we said we've got two projects to do. One is deploy horizontal wells into Vert-la-Gravelle and the 7 million of Rhaetian resources we have, and take 3D seismic and go and have a look at the Dogger reservoir or limestone reservoir we have in Villeperdue, and that sets us up for a significant running room on that side. When we get to the end of those two projects, we'll reassess this resource base and decide what we do next.
We've finished on the Vert-la-Gravelle. We're moving into execution on Villeperdue, through the course of 2020, the shape of the business in France, I think, will change a little bit based on the results of these two projects. If we step to Vert-la-Gravelle, you can see in the middle part of the diagram, VGR-113. That was the first horizontal well drilled in these Rhaetian reservoirs. Horizontal well technology isn't new for the business. It's been around for many, many years in many, many regions, it's never been deployed in these reservoirs in France.
We successfully executed, through the course of the end of last year, we successfully executed that well. As Mike mentioned, we've seen spot rates of up to 1,500 barrels a day out of a French business or the Paris Basin business that was doing around 2,000 barrels a day through the course of 2018. That's a game changer for the Paris Basin. We've just completed the VGR-109 well. We'll bring that online in the coming weeks as well. Rates will be a little bit lower than 113, given the reservoir quality changes throughout the field, so it's slightly lower quality than 113. Rates will be a little bit lower, but we've proven that uplift with horizontal drilling.
Now we've got a job to do on the rest of the Rhaetian resources to go back and revalidate our development plans with rates of up to 1,500 barrels a day out of these horizontals. One other interesting point we found in Villeperdue project is we have, similar to Malaysia, in Malaysia, we have the 10.1 and the 10.2 reservoir. In this area of the field, we target primarily the B 1 reservoir. However, we do have some production from a secondary reservoir called the D reservoir, and that's in the northern part of the field. All of the wells we drilled, and we drilled pilot holes and took core in these wells, have shown some evidence of a secondary reservoir, which is oil-bearing through that entire structure.
Now we go back to the drawing board on some of the opportunities with Villeperdue project to understand what we need to do to maintain 1,000-1,500 barrels a day out of all of these wells, what we need to do for sweep and injection, and also what further opportunities we have in terms of the secondary reservoir. Moving into Villeperdue, this is another exciting project in France. In 2017, we shot a 3-D seismic program. We've evaluated all of the results, and that's allowed us to high-grade 3 development locations in Villeperdue. What you see on the upper right-hand graph is you see the areas of porosity that we've identified on the seismic, and you can see that in cross-section form underneath it. The real change for Villeperdue is we've moved to...
From a program which was roughly delineated by drilling with well spacing as opposed to any seismic, we've moved into, again, modern technology in Villeperdue, where we're using 3D seismic to identify the best quality zones in the reservoir, which then allows us to optimize the well placement in this field. Through the course of this year, we should see the results of this program in Villeperdue, and that sets us up for understanding the contingent resources beyond Villeperdue in the, in the Paris Basin. We'll have production from Villeperdue West on in Q3 this year and ramping up through the second half of the year. That rounds out the technical part of this presentation just before we move into a break.
Really, the guidance or the discussion from us is a really solid resource and reserve position that sets us up for 50,000 barrels a day for the coming five years, and then an investment program that sits behind just delivering our 2P reserve position. As we move into capital, huge discretion on the capital program to ramp that up or down, depending on commodity prices, choices, and strategic direction for the company, whether that's prioritizing organic growth, returns to shareholders, or M&A. On the reserve and resource position, you've seen through the start of this presentation that we have a 300 million barrel and nearly 1.4 billion BOE when we lump 2C and 2P together.
That sets us up for huge growth across all our areas or regions of the business, and our teams are constantly focusing on maturing contingents into reserves and into production to further extend that 50,000 barrel a day. I think now we'll move into a break for the next short period, and we'll come back at the end of the break. We have 15 minutes of a break, we'll join you back here at 3:20 P.M. Thank you.
Welcome back to our Capital Markets Day presentation. I'm Christophe Nerguararian, CFO, I will now walk you through the financial overview for 2020 budgets, giving you the assumptions we've been using to come with for the operational cash flows and EBITDA projections for 2020. Walking you through the main assumptions, as we talked about before, the production for 2020, we're getting it at 46,000-50,000 barrels of oil equivalent per day, including capital expenditure in 2020 of $150 million for all of our assets, operating costs at $13.7, slightly higher than 2019. Maybe a couple of words on how those assumptions compare to 2019 realized cash flows, production, and investment.
The production guidance is the same as you had noted in 2020 than in 2019. Obviously, we're coming from a different production level, because in Q1 2019, production was 44,000 barrels a day. In Q4 2019, the production was 47,000 barrels a day for. Obviously, we are starting 2020 with much more sail in our winds. so I'm not suggesting this is conservative, but obviously we're starting from a much higher production level entering 2020.
On the CapEx side, the 150 is almost 20% reduction, 15% reduction compared to 2019. Is totally in line with the trend on CapEx, which both Mike and Dan talked about, in that the CapEx is gonna reduce over the next 3 years. In terms of operating costs, all these numbers, as it was hinted before, include the Ferguson assets. Even though the Granite Oil acquisition is only expected to close early March, all those numbers include Granite Oil from the 1st of January this year. The reason why the operating costs are slightly higher is that Granite had a slightly higher OpEx per barrel, that's driving slightly higher up OpEx.
We're expecting also some maintenance costs in 2020 in Malaysia, for instance, which we didn't have in 2019. That's explaining why we're roughly $1 per BOE higher in 2020. I'll show you the seasonality on this OpEx per barrel, and you can see that we're expecting some improvement and a lower OpEx per barrel towards the end of this year. On the basis of those assumptions, we would generate revenues of $27 per BOE and operating cash flows and EBITDA of close to $12 per barrels of oil equivalent.
For those of you who've looked at the presentation this morning or who have the number of our realized cash flows for 2019, you can compare those operating cash flow and EBITDA of $12 per BOE. That compares to $18 realized in 2019, $18 per BOE in 2019. I'm not suggesting that these numbers are necessarily conservative, but I think it's important to draw the parallel between what was achieved in 2019 when you look at our guidance for 2020. The important point, and I think Mike made it very clear, that IPC is about our ability to generate cash flow.
That's been very much the case over the last, the last three years since our inception, and it's even going to grow over the next five years when we maintain production close or above 50,000, and reduce CapEx going forward. IPC will generate free cash flow, will be free cash flow positive in 2020 under our base case scenario. At the same time, we maintain a very good access to our credit facilities. We have, we will have, at any point in time during 2020, in excess of $100 million of access to existing credit lines. At some point in time, $150 million, sometimes a bit less than $150 million. It's also worth noting that these credit lines are not necessarily all optimized.
I mean by that we would probably be able, should we need to increase those facilities, should we look at M&A or accelerating CapEx, even if we are more in the mood, as you understood, of managing and reducing CapEx going forward. In terms of the base case, these are the oil and the gas prices we're using in our base case. We're using the low base and high case, a Brent average of $50, $60, and $70 per barrel in 2020. We're deriving the WTI prices for the low base and high case by applying a 10% discount to the Brent, and then a fixed WTI to WCS differential of $20.
We're using the same as last year, and we'll show you some sensitivities should that differential increase or decrease by $5 per barrel during 2020. It's obviously a hard one to predict. Last year, we started the base case, we showed the base case with a $20 differential. We ended 2019 with -13. It was a very positive year from that perspective in Canada, with very strong realized prices. We started this year at -24, and it's now -18. As we stand, -20 seems a reasonable assumption for our base case. As Mike mentioned, we see positive developments into the main pipeline projects to increase the grease capacity out of Alberta, which should, over time, also reduce and tighten that differential.
Twenty, minus 20, but we'll show you the cash flow impact should that differential increase or decrease by $5. In terms of gas prices, for those of you reading North American press, there's a bit of the gas prices, natural gas prices in North America as a whole, led by the U.S., are a bit soft. We guided and actually achieved in excess of our guidance in 2015, when we were using CAD 2.5 per Mcf. In 2020 for this, for this capital markets, the exercise, we've decided to lower it down to CAD 2.25, but again, we'll give you the cash flow impact should that gas price increase or decrease by CAD 0.25 per Mcf.
I think it's important, again, as I mentioned, this morning when we, when we presented our 2019 results, it's important to distinguish the realized prices between Malaysia, France, and Canada. In, with a, with a Brent price of 60, we are, we're using 65 realized oil prices in Malaysia, so a $5 premium. This is slightly below what we've achieved in 2019, and a bit below also the latest premium, 'cause we were able to sell our latest cargos in Malaysia at a premium of $8. A bit conservative, but we are using 5 here. France is relatively stable. As you can see, we have long-term marketing contracts with French refineries, whereby we're selling on average at Brent minus 1, pretty much in line with our, with our contract there.
In this base case, when you use a Brent of 60 going down to a WTI of 54, as I said, we're using, in our base case, a $20 differential to go down, to move down to the WCS. For Suffield, we assume that the oil would be sold at the exact WCS. In practice, we hope to be able to sell it at maybe WCS plus $1, but in our base case assumption, we're using a flat WCS realized price for Suffield, and a discount of roughly six, sorry, CAD 9 for Onion Lake production. Actually, it's the two are comparable because they are almost the same API at Suffield.
Because we are transporting our oil on pipelines, we need to blend our production with some diluent to make the blend lighter, and so we have to pay for some diluent costs. If you compare post-blending costs, actually, Suffield and Onion Lake almost sell at on parity, so they are not so different. In terms of modeling cash flows going forward, for those of you wanting to check our numbers, that's the assumptions you should be using. It's helpful to see how those this base case compares to what was realized in both 2018 and 2019. Gas prices, the same as I just said, we were using CAD 2.5 in our guidance before.
Actually, the Empress realized price on average in 2019 was almost exactly CAD 2.5. There's a bit of seasonality, because the gas prices tend to be higher in the cold months of the winter, both in Q1 and Q4 every year. Couple comments on this graph. One is that it's volatile, as you can see. The second point is that Suffield gas production is sold on the Alberta/Saskatchewan border at a price point called Empress. We're realizing the Empress gas price, which is in blue here above the AECO. The Alberta gas price benchmark is the AECO. We're selling at or above AECO all the time, because Empress is equal to or higher than AECO all the time.
A bit softer as we talk. Gas prices are just below $2 now, because it's been a bit warmer than usual this winter over the last few weeks in Canada. We're constructive on the second half of this year and believe that gas prices will improve over time. $2.25 seems a reasonable base case as we stand. Looking at the margin net back, on a dollar-per-barrel basis, as I just mentioned in our base case, with production guidance between 46,000-50,000 barrels a day, we'll be generating revenues of $27 per barrels of oil equivalents.
That would compare to the 33 we achieved in 2019. As I mentioned, you can see that the cost of operations are $0.5 per BOE higher than what was realized in 2019. I just mentioned why. Leading to operating cost of $13.7, some cost of blending. I just talked about the blending cost, which refer to the cost of buying diluent to blend into our Villeperdue oil production before we put it on our pipe, to sell it to the Montana refiners in the north, in the north of the Montana State, in the U.S., leading to a cash margin netback of $12.
The range for this cash margin from our low to our high end, in terms of oil prices, is really $7-$17 per BOE, compared to 19 achieved last year. I wanted to draw your attention and to give some explanations around why the OpEx per barrel were a bit higher on average, but as you can see, we have a bit more maintenance in the Q2. As you can see, and as we project production to increase throughout the year, as we are drilling wells in pretty much all of our countries, with the exception of Malaysia, we intend to increase production level. Maintenance should be lower in Q3 and then in Q4.
If you look at our projection, we expect the OpEx per barrel to come back down to in between $12 and $13 per BOE, which is in line with what was achieved in 2019. We're not talking about a permanent increase in OpEx per barrel. It's a transition into the Q4. Looking at the operating cash flow net back and EBITDA, it's essentially the same. As a reminder, the definition of operating cash flow is revenues, less OpEx, less cash taxes, while EBITDA is revenues less OpEx, less G&A. G&A and cash taxes, in this case, being essentially the same.
You have the same netback for operating cash flow and EBITDA at close to $12 per barrel, again, compared to 18 achieved in 2019. In terms of the profit and loss, our business is not so much driven by the net results, but still interesting to look at what the netbacks would be in terms of net results. $1.5 per BOE in our base case, and that is the result of netting off the cash margin or depletion and depreciation costs. Exploration costs, as you can see, they are virtually. We don't expect to do much, to spend much money at all on exploration.
G&A, as we showed this morning, that for 2019, our G&A had been $12 million for, in absolute terms, for the year. It's not dissimilar for 2020, and it's fairly low, at less than $1 per BOE for the G&A. Financial items, obviously, in a lower oil price environment, would keep debt outstanding at a higher level, so the cost of financing would be a bit higher. They remain below $2 per BOE in all cases. It's interesting to note that the depletion and depreciation rate is 8.7 in our case, and is above the CapEx we intend to spend in 2020.
Effectively, we maintain or increase production by spending less than the volume of depletion and depreciation. I think it tells you that our CapEx are quite effective from the point of view of being able to maintain and prepare for the future, maintain production and prepare for the future. I told you I would give you the range and the sensitivities around what's the impact of a change of ±$5 per barrel for the WTI, WCS differential. I said, our base case is -$20. We realized -$13 in 2019.
Should the differential improved or increased by $5, the impact on both, on all of revenues, operating cash flow, and EBITDA would be $1.8 per BOE. Up or down, whether it increases or decreases by $5, that's the cash flow impact. That would be the same impact at 50 or 7, in the two, in the low and high-end cases, when we're using Brent prices of 50 or 70. What matters is really that change in the differential. The same, I mean, the same concept applies to the gas prices.
Should they move up or down by 25 Canadian cents per Mcf, the difference on total revenues, operating cash flow, and EBITDA is approximately $0.35, rounded up at $0.4 per BOE. This slide is important, and I know it's important to focus on not only operating cash flow, but as well, obviously, free cash flow. What's left for not only repaying debt, but also allocating back capital to shareholders. As I said on my first slide, IPC with $150 million of CapEx would be free cash flow positive in our base case.
If you look at this, at this table and look at the low case, at $50 Brent, it looks like we would be, we would have a negative free cash flow. I want to draw your attention, because that's a very important point. Both Mike and Dan very clearly stated, before that more than half of the $150 million of CapEx are totally discretionary and are still cancellable as we speak and will remain cancellable for the next couple of months. What I mean by that is, if you would halve the development cost here, even at $50 Brent price, we would remain free cash flow positive.
Being the operator of all our assets, which we control, and we can decide and dictate the pace of investment, is critical for us because we can really adjust to the oil and gas price environment. That's what we are ready to do should the oil and gas prices go further down. Lots of flexibility, free cash flow positive, with a view to maintain or increase production and get ready for the next five years of free cash flow, but an ability to change and reduce CapEx should we decide to in the next few weeks. That's really the point I want to leave you this, to leave you with. Thank you. Rebecca?
Thanks, Christophe. You know you're on the home stretch when you're on reserves evaluation. Last section, Mike will take some questions. In terms of reserves evaluation, what I want us to do is give you a bit of background about how we come to some of the numbers that we've got sitting in the presentation. We give you a lot of information about net present values. We give you a lot of numbers. This really gives you a bit of an idea of how we get to those numbers. First of all, the technical profiles, which Dan has taken you through a bit of our five-year forecast on our technical profiles. Essentially what we use is reserves auditor approved, 2P profiles. Our numbers for 2P include our 300 million barrels of 2P.
They generate production profiles, operating cost profiles, and investment profiles at an asset level. We aggregate them up to the company level. What we do is apply the fiscal terms for each country. There's a lot of detail in fiscal terms, so what we tend to do is give a big presentation, which will show you all of the royalty structures and the tax structures by country and by asset, which will be available on the website towards the end of today. There are two points that I wanted to make on the fiscal terms. The first of all is that in Canada, we have a lot in tax balances, so we have around $1 billion that's sitting in tax balances that we can apply against our tax in Canada.
That essentially means that the Sproule price deck, we won't be paying tax for 4 years in Canada. The second point is that conveniently, in 2 countries, the tax rate is moving down, and it's moving down towards a blended tax rate of 25%. Essentially, in Malaysia, we pay 25%. In France, we're moving from 28% to 25%, and that's in the next 2 years. Because the Alberta provincial tax rate has moved down, within the next 3 years, we'll be at 25% blended rate in Canada as well, which makes it easy for both myself and you. Okay, what do we do? We then put this through an economic model, and we use the reserves auditors approved price decks, which are issued in January each year.
You can see from this slide that the year-end 2019 price deck for Sproule is about $4 a barrel less in the long term. This is quite important because this shows how we can retain value when you've got a 5.5% decrease in the entire curve for the life of the assets. If we go down to what that means in terms of our long-term Canadian pricing, the Western Canadian Select is sitting at about $45 a barrel in 2020. I think what's really important here is if you look at the realized price in 2018, this is the realized price when you had the Keystone outage, you had the blowouts of differentials that went up to $40-$50 USD. There was no normalized differential situation in 2018.
The government came in with apportionment. You can see what a normalized price in Canada is in 2019, when we achieved $44 a barrel. Okay. There is also the $5 a barrel decrease in the long term on the Western Canadian Select oil price, right? It's coming straight from Brent and straight down to the bottom line also in Canada. On the Empress gas price, actually, between 2017 and 2018, there was a $0.50 in MMBtu decrease in the entire curve. Between 2019 and 2018, it's remained pretty constant, but this is after a decrease of 17% the year before. Okay. We get to net asset value and how we calculate this. Again, technical profiles are reserves profiles. These are all reserve auditor approved.
I think what you can see here is, proportionately, International, which is sitting at $478. If I can remind you that in previous years, it sat at $530 and then down to $520. You're not seeing big decreases, even though we're distributing cash flow from these assets on either International, which still sits at $480, despite the price decrease, or Canada, which now sits at $1.7 billion, plus Granite. You've actually got what is an increase in NPV across the 2 years, so $2.4 billion. We've got our net debt, which comes in at $291 million, and you get to a net asset value of $2.1 billion. When you look at the numbers, Dan's got 60% in PPDP, so this is value.
In terms of value, we've got 64% that sits in the developed portion of our assets, and that's an increase from last year of 60%. What you can see is that we're converting value into the developed portion, the producing portion of our portfolio. The net asset value changes from 2017 to 2020. Basically, what you see here is the increase, fourfold, of our portfolio between 2017 and 2020. This is notwithstanding banking $390 million worth of cash in that period. It's an extraordinary four-time increase in value while you're producing cash from the assets. The other thing that I wanna point out is, it's not on the slide as such, but the NPV10 value of these assets is $1.9 billion.
It's 10% below the amount that you've got there. Sorry, the net asset value, $1.9 billion. What that means is you've got a lot of cash flows sitting up front in your assets, and Dan's demonstrated this through the technical profiles. You can see you reach 50,000 for the next sort of 5 years. We've got a very low sustaining CapEx number, and we've got operating costs that are pretty much fixed across the portfolio, and that leads to that huge cash generation that Mike has shown in his slides. Okay, I took you through it very quickly. There you go. Yeah, as I mentioned, and it's quite important, the fiscal terms will be published on the website, but of course, give us a call if you need more information or more modeling expertise to help out with your modeling.
All right, Mike will do the closing remarks, and then we'll all get up for questions.
Okay. Thank you. Thank you, Rebecca, and thanks for everyone's patience and attention. Just down now to the final two slides of the presentation. I think the first slide is a look back of what's happened with IPC over the past three years. If we go back to when we spun the company out in April 2017, we had back then 113.5 million shares outstanding. As we've mentioned, we've agreed three acquisitions in the last three years or so. Only one of those transactions has involved using paper, which was last year's acquisition of Black Pearl. We added close to 76 million to the share count as part of that acquisition.
We've also been very active in terms of our share buyback. In early 2017, after we launched the company, we did a big share buyback, 25 and a half million shares. Since the announcement in our Q3 results of the new share buyback for this year in 2020, we've bought back another 7.6 million shares. If you look at where we started our journey and where we've come to today, with only 38% dilution, we've added 5 times production, 10 times reserves, adding 9 years of longevity to our reserve life, in excess of 1 billion barrels of contingent resource, more than doubled our cash flow generation, and added $1 and a half billion in NAV. That's what we've done in the last 3 years.
The final slide is coming back to the first slide that I showed in my presentation, which is, I think we've got a phenomenal foundation now to really create significant long-term value for our shareholders. We've been very active on the acquisition front. We've got a solid resource base to develop. You've heard that we can keep production broadly flat at around 50,000 barrels a day for the next five years, and that really does turn IPC into a free cash flow machine, generating between $500 million and up to $1.3 billion of free cash flow, between $55 and $75 Brent, and effectively liquidating the entire enterprise value of the company at only $65 a barrel, when we'll still be producing around 50,000, and we'll still have 1 billion barrels of undeveloped resource.
That really does put the company in a phenomenal position to continue developing our organic growth strategy and converting contingent resources into reserves. Big focus will be on stakeholder returns and further debt reduction, share buybacks, and even potentially dividends when we look at that forward-looking cash flow generation potential. Of course, we will still be opportunistic with respect to further M&A. I think you'll all agree when you see Rebecca's presentation on value and where we're trading today, it only makes sense for us to do further M&A if it's gonna add value relative to the value of our own assets that we know and understand better than anyone else. I think the focus will be more on stakeholder returns than perhaps we've seen on M&A in these past 3 years.
That concludes the presentation. Thank you for everyone's patience, and I think we can now open up for some questions. We can take questions from those in the room for the presentation today, or you can send in your questions via the Internet and the email. If I can just ask the presenters to come and join me, and we'll get started shortly.
Yep, we'll start with the audience questions.
Yes, Bob.
Thank you. Rebecca, does your forecast, does that include the maximization of your Normal Course Issuer Bid in those numbers?
Does that include the maximum share repurchases in your debt projections that you said?
In the five-year cash flows?
Mm-hmm.
Yes, it does.
Okay.
The maximum that we have at the moment ongoing, Bob.
Okay.
Thanks, David Round, BMO. Can I start on the capital allocation slide? I'm principally thinking about the 2C excluding Blackrod, I'm wondering if you can give a sense of a capital scenario there or a CapEx scenario there. Because, you know, it feels like under a lot of scenarios, you still have quite a lot left for shareholder returns. Just trying to get a sense of how significant they could be, at least in your base case assumption at the moment. Secondly, just, you know, on those organic opportunities, obviously, there will be a, you know, a pipeline, and they'll all have different rankings. I'm just wondering if you can remind us what your hurdle rate is at the moment for new sanctions. Is that increasing in the current environment?
You know, in a scenario, in a few years' time, when you're sat on a huge net cash position, you know, how do you think about that hurdle rate at that point? Just steadily, just on Onion Lake, you know, you're talking about increasing capacity. Now, again, is there a scenario where you could effectively just double capacity? You know, you've got the resource there. What does that look-? You know, because there's a lot of talk in the media, reserves being trapped, et cetera, et cetera. Could you go out, double your capacity, double your infrastructure capacity, just produce that out in half the time, or do your returns erode quite quickly?
Okay, let me try and answer all of those, if I can remember. I'm gonna start with the last one first, with the recency effect. I think on, as Chris mentioned in his presentation on Onion Thermal, and in our, in our base plan, in our 2P reserves. What we're assuming is that we can lift capacity from 14,000 barrels a day to 16,000 barrels a day. That's baked into all of those numbers. Now, theoretically, yes, it's possible we could increase that to 20 or 22,000 barrels a day of capacity and accelerate that production profile. It's really a time value of money question then. You're bringing forward that finite 2P reserve base for an incremental facility investment CapEx.
I think as you start to get beyond, you know, that 16,000 barrels a day plus capacity, then it becomes difficult to justify, you know, such an aggressive approach as to add 20%-30% to your production capacity. I think what we have right now in our base plan of growing to 16,000 barrels a day is highly supportable. I think going beyond that, it starts to become more challenging. Clearly, if you're in a higher oil price environment, then that's something that we could come back and relook at. I think when, on your question about the non-Blackrod contingent resources, so around 100 million barrels that we have there. The near-term focus is gonna be on 2 things. In Malaysia, Daniel, you know, presented the 15 A, 20 area.
I think if those, if those work, those will always be the first projects that will get our funding, because they're very quick payback. The breakevens are typically around $30 per barrel, or less, so your paybacks are typically in the 6-12 month range, and the breakevens are around the $30 per barrel level. If we were to bring some of that into our development plans, what you would actually see, it would actually add to our free cash flow generation, as opposed to subtracting from that. The very short cycle, low breakevens would, you know, could certainly be accelerated into that 5-year window. I think when you look at In France, there's around 16 million barrels of the 100 million barrels, sits in our French contingent resource, and about half of that is in the Triassic Rhaetian reservoirs.
You know, that's not something that we can execute the full development of that. That's gonna take a couple of years to start to mature. I think what we're gonna want to do is see the long-term performance of Vert-la-Gravelle, start to mature the top 4 opportunities, which we're working on through 2020. I would say it would be a relatively slow ramp-up in addition to what we have. Of course, with the increase in cash flow generation that we're seeing out of the French business, then we can start to use those cashes. The breakevens in France are kind of between $35-$40 a barrel, so you're still getting a 10% rate of return around those oil prices.
It still does make sense to invest in those projects, it's just being a little bit cautious on the timing and how quickly. Don't expect all 8 million barrels to be developed in the next 3-4 years, I would say. The other contingent resources are really coming from the Canadian business. You know, I think we've got around in excess of 100 wells in the Suffield conventional oil pools that sit behind those contingent resources. We've still got quite a deep inventory of development locations in our 2P. Again, my sense is don't expect a big acceleration of those Canadian contingent, because we'll still be working through the 2P reserves.
We are, for example, this year, there's a couple of wells in that Suffield oil drilling program that are actually targeting 2 to 3 locations that sit in our contingent. Really, the strategy is a low-risk approach to start to try and mature some of that contingent resource and see what the productivity is from those. The breakevens of the Suffield oil drilling, I think is around $20-$23 per barrel USD. Again, still making good returns at these oil prices.
I think the only other one on the contingent resources is we don't have.
... apart from Blackrod, we don't have a major project to execute, which requires significant $100 million of CapEx, et cetera. The pace of this is we can do a one, two, three, or five-well program in France, the same in Canada. We can be very selective about when and how we choose to execute these projects.
Any other questions from the audience? John, go ahead.
Thanks. Johan Spetz, Pareto Securities. A couple of questions on my end. I'll take them one by one. Firstly, thinking about the longer term production guidance that you provided now of being able to stay close to 50,000 BOE per day for the next 5 years. How do you see the dynamic within that aggregate number, if you look at the different countries? I'm guessing Canada would probably be contributing a bit more over time, whereas some of the others would be declining a bit. Could you talk a bit about the dynamic there?
Yeah, I think that's right. I mean, direction, as Chris mentioned in his presentation, you know, the plans for Blackrod Thermal, which is one of the biggest producers, is gonna lift by around 2,000 barrels a day this year, and then you've got another 2,000 barrels a day in that, in that long-term forecast. With the steady investment program, the monies that we spent last year on our end-to-end project, which we're drilling all the injection wells and now all the alkaline surfactant polymer flood wells are receiving injections. The money's been spent there, but that's over the next 2 years is gonna add about 1,250 barrels a day of incremental production.
Think of Suffield Oil steadily growing, a bit of a bump from end to end, and those capacity enhancements from Onion Thermal. You're right, you're gonna see growth on the oil side. We'll be trying to keep the gas production as flat as possible. In Malaysia, there's no further drilling in our 2P numbers. Malaysia will start to naturally decline. You'll see some growth in France from the Vert-la-Gravelle phase one. We have the 3-well program that's coming in Vaupillon West in the second half of this year, which should start to normalize French production rates. We'll be looking at further potential phases in France. Those tend to sit more in the contingent category. Marginal decline on the international assets, offset by increasing from oil production in Canada.
Right. Going to Blackrod briefly, what's your latest thinking there in terms of a development plan at some point? Would you prefer to do it alone or bring in a partner? How's the latest thinking there?
Yeah, I think... I mean, so Black, and Chris can jump in if I say anything untowards here. To me, like, Blackrod's all about optionality for a higher oil price environment.
Mm-hmm.
Minimal investment. Last year, we spent $5 million on the third well pair that Chris talked about. As Chris mentioned, the idea there was to increase the length of that horizontal section, use the latest drilling equipment, you know, steam flow control devices, to get costs down and really get the development costs and the break even down. The previous numbers for that project were around $55 per barrel, WTI break even. If through the piloting and using that latest technology, we can get that break even down as low as possible, perhaps even as close to $50 per barrel or below. That's the current oil price, we're not gonna be sanctioning that project. Would we wanna take it on 100%? I think it would be a challenge for us.
You know, should markets improve and then the years and years of underinvestment, that people and then growth doesn't become a dirty word anymore.
Mm-hmm.
You know, Chris has mentioned all the approvals are in place. We've got the environmental permits, the construction permits, the drilling permits. We've got a phase one project pre-cooked and ready to go at 20,000 barrels a day. If suddenly there's an improvement in market conditions, and you've got a project that's that mature, there's not that many people can say we've got that resource base that can be brought into production within a 2-year period. For us, it's really all about spending small dollars now to get a huge resource base ready to go, that we could then look to bring in a partner or potentially sell down a portion. I think as we stand today, taking that on 100%, it would perhaps be a bit of a challenge.
Right. Thanks.
Is there something wrong there?
Final one from me. Just going to France quickly. Vert-la-Gravelle , you've had some promising results there from the horizontal drilling. Would you be prepared to put sort of a timeline on further drilling there going forward in 2020, 2021, when you might see some more of those wells coming in?
Yeah. You want to take that one, Daniel?
At the third best well in the company, it's gonna be as soon as we're ready. I think it changes the game fundamentally for France, having a 1,000 barrel a day wells. It also means all of the work we've done on the, this contingent resource base is back to square one, again, because we've got to go and design the water flood for the fields and go and redesign the offtake rates and check facilities, et cetera. I think it's that work needs to conclude, and then we'll look to mature the next opportunity in France.
Thanks.
Okay. Are there any others from the audience? Yep.
Can you explain a little bit more about the operational issues at A15 in Malaysia?
When we were drilling the A20 well, which was the final well, as part of the three well program. What we saw was we started to lose productivity from the A15 wells. We're still early in the investigation, but what we think is the most likely scenario, which we haven't encountered before, we've drilled close to 20 wells in the whole Bertam field. We think we may have seen some drilling fluids go from the A20 well through natural fractures into the A15 well, which has caused us to lose productivity. As a result, the ESP, which is a dual ESP, is no longer working. What we've decided to do, and actually it's thankful, we've got a rig on location.
It's one of our highest rate wells. We're going to do a small sidetrack and put in a new dual ESP. The ESPs has been there for more than four years, they do have a certain design life. It's an opportunity for us to take a low-risk solution to sidetrack and put in a brand-new ESP, which will increase the longevity of that well. That was the issue there.
Thank you.
Okay.
Hello, Giulio Antonello from Auriga Partners. A few questions. I guess the first easier one is the ESG, the project in India. I was just wondering if you had an idea of the CapEx on that that was on for IPC.
Yes.
Of that 100 megawatt solar plant.
Yes. We're not. Just to be very clear, we're not actually.
Okay
in the CapEx of that project. it's purely a carbon offsetting project. First Climate, who we're working with there, they validate all of the CO2 emissions. effectively, what we're doing is by providing funding to that project this year, it's around $80,000-$100,000. it's effectively, if you like, a subsidy to allow that project to go forward, that otherwise wouldn't have done and would have been displaced with coal-fired power generation. The commitment as we move from, you know, from the 50,000 barrels a day reduction to the world average over the next five years, should amount to around $1 million of investment over that five-year period to get to that average.
Okay.
At today's prices for carbon offsetting.
Okay. I feel better. Another question is: seeing that going forward, of course, the company it's looking to become more and more Canadian, I was wondering if you can give me a sense of how that OpEx per barrel, which I was of the feeling that the OpEx per OE equivalent would be higher in Canada than France, and Malaysia, than the blended of French and Malaysia. If you could give me a feeling of how that moves going forward, ball park?
Yeah. Within those numbers, the guidance that we're seeing for this year doesn't change materials. It's fairly flat at 2020 levels for the next 5 years.
Okay. It means that there is no significant-
There's no significant change from the 2020 levels.
Between, the 2.
No.
Okay. That's, that's important. The last one, I guess, is maybe a softer item, which I know you don't have a crystal ball, but given current prices of oil, now, like $54, and the spread, WCS is north of $20.
17, yeah.
Seventeen.
Yeah.
What's your feeling? I mean, I know it's a straight question, but the $149 million CapEx, if we stay like this, in the, say, the midst of this, the virus here for a couple of months, I know that you are flexible, but these are not things that you can just press a button, stop, or press a button and start. What's any comment on that?
I think I hope we explained that, you know, more than 50% of the capital program.
Yeah
is discretionary. We have got the ability, certainly, to dial back the projects now. Of course, the phasing of that 50%, where we're more committed now, Chris and the team, they're, you know, they're drilling the expansion pad right now in Onion Lake Thermal, for example. That's in the 50% that's committed.
Okay.
you know, we're doing the Malaysian remediation work, that's firm, we have a rig on contract in, for the Vaupillon West development. We've got a lot of the long lead equipment already in place, we haven't started drilling that project. What you're really looking at is the conventional drilling program and the gas optimization program. The Vaupillon West development program are the areas where you've got much more discretion. Of course, we're gonna be monitoring that. I think we won't be taking any dramatic decisions in the Q1, because the, you know, the CapEx that's committed so far is really a first half-type CapEx.
Come the end of the Q1, we can look to see whether or not we want to scale back on some of that second half CapEx to live.
You would decide after Q2 if prices are still like this...
Q1
We are gonna see less than that 150-
After Q1, we'll be watching that.
Mark.
Yeah, correct.
There's very few of our contracts are long-term contracts. We have the ability to turn off spend fairly easily.
Okay
at the push of a button.
Is that true also? I noted that you know, you have this blue curve of CapEx going to 2024. Is this true in your projections also to 2024, or? It's only true about the $150 million for this year, this capability to hold back.
Yeah.
I would assume that in the year where you do a lot less-
Yeah
looks like 2023, that might be a little bit more rigid.
Yeah.
Maybe I'm wrong.
Yeah.
Mm-hmm.
Time we got on the Onion Lake pads coming on stream. The curve is broadly what we have in the reserves.
Mm-hmm.
The reason for that is that we have drilling on Suffield for the next few years, and then, of course, everything really depends on Onion Lake and when you put your pads on stream. You tend to have a bit more CapEx in those years.
Okay.
Yeah.
What then you are saying is that.
Discretion
in a situation of
With full discretion.
Can live.
oil, you could.
Yeah
stop and use the money.
Would have an impact on production, obviously, but.
We can say to cancel those projects.
And
Tracks in place for any of that work at this stage.
Okay.
None of that is, or very little of that is committed.
I think just to come back and Richard, you maybe didn't really pick up the point that Dan made in his presentation. If we decided to switch that off, all that CapEx, clearly you can't sustain 50,000, so you would see production drift down to the lower end of that forecast. Because you're taking the CapEx out, it's not gonna materially impact those free cash flow generation forecasts. It means some of that would get deferred into the later years, but it's not gonna materially alter that.
Okay
... cash generation profile.
Lastly, to make us feel better, it seems again that your use of cash, you know, there's a good scenario where you're going to make a lot of free cash flow and a bad scenario where you have the optionality to hold back on CapEx. How do you perceive, of course, the stock market prices are an important element, your, you know, your attitude towards the buyback in this range is. Can you comment on that?
Yeah, I mean, I think even in the, in the bearish scenario, if we see $55 oil for the next five years and our stock stays at these levels, we've got, you know, we can repay our debt and still buy back more than $200 million of our stock. I'll do that all day long at those levels.
Okay, that's what I wanted to hear. Thanks.
Just curious about what's the current spare capacity in the Bertam FPSO?
Yes, no, so we have no capacity strengths in the Bertam FPSO. Even with the new wells that we're bringing on stream, and in fact, one of the things that we're looking to do during the shutdown in the Q2 is to do some further debottlenecking, so that further down the field, we can actually increase the liquid handling capacity.
Is that asset fully depreciated by now?
Not quite fully depreciated. Is there what? $18 million today.
Sixty is-
$60 million is.
On the balance sheet.
It was $118 million on day one.
So two-
yeah, it's down to around 60 now. Yeah.
Given that you expect a flat production, just going back to the question, the gentleman over there. In terms of what you can do, are you considering dividends as well, or is this mainly debt repayment, keeping the buyback to the maximum that you're allowed?
I think.
Just accumulating cash or?
I mean, in the $65 scenario, we've repaid the debt, which is just under $300 million, we've got the capacity to do share buybacks and dividends. I think obviously it will depend at the time on where the stock is trading and whether it makes more sense to continue with the buyback or to return money in the form of a dividend. I think when you look at that longer term outcome, we've certainly got the flexibility to do both.
What's the current cost of the debt?
About-
Below 5%.
Yeah.
Five?
Five.
Perfect. Thanks.
Okay, I think that's it from the audience. We do have a few web questions. If they've been asked before by the audience, then I won't be asking them now. Dan, how do you see Malaysian operations during this decade, and do you think there'll be any new exploration success?
Malaysia, I think on the operational side, we have had and will continue to have good operational performance from our teams in Malaysia. They've done a phenomenal job delivering operational uptime at greater than 99% since day one, since 2015 in the field startup. As we roll through 2020, we'll spend a bit more time understanding that northeastern area of Bertam and understanding the potential, and then we have up to 2 wells in the contingent resources in that area. We're always actively looking in the basin in Malaysia as well. As we touched on in the 5-year guidance, over time, Malaysia will decline as the opportunity set decreases. We continue to have discussions with Petronas and our partner, Carigali, around opportunities in Malaysia, and we will continue to do so because we have a great team.
The ability to put more barrels behind this team is one we're actively looking at.
Okay.
As Mike says on this slide, though, it competes with the other two options here in terms of M&A stakeholder returns and organic growth.
Okay, thanks, Dan. Chris, what do we need to see from the pilot, technically, to bring Blackrod development sanction into view?
The Well Pair two pilot has actually confirmed commercial rates from a technical success at Well Pair two now. It all we're doing now is really Well Pair three is, what can we do to improve on that initial CapEx required to start up phase one, which would lower the overall breakevens? It's just continuing, the pilot is continuing to give us learnings on how to deploy phase one more cost effectively or more efficient. Well Pair two has confirmed that technically, we have a resource that can be commercially produced.
Okay. Thanks, Chris. Christophe, when it comes to screening for possible future acquisitions, some elements are critical for you, like operatorship, development upside, break-even level. Can you shed some light on which geographical areas you tend to find interesting, and do you have preference onshore, offshore?
Yeah, no, we don't, well, we have a very long shopping list. We would prefer oil. We would prefer to be the operator. I think coming back to one of the previous questions about the cost of debt, we like this low cost of debt. I don't say that too loud to our bankers, but it's reasonably cheap source of funding, obviously. As a consequence, in terms of geographies, we feel comfortable. We don't like to be range bound and to be only able to go to Malaysia or to Canada. We can go, obviously, to other countries, as I think we've disclosed before now. Some of the regions where...
Countries where we wouldn't go are typically countries or regions where the commercial banks would not support us, because then that makes the cost of moving there, of an acquisition there, to be fully supported by equity, and that makes it more expensive for us if we can't have banks supporting either the acquisition or the acquisition and development potential there. That's one of the, that's one of the limitations we set ourselves.
Okay. Just one more question on Blackrod, which is about when the decision will get made about development sanction. Mike?
Well, I think Chris has said, we'll see the results of the pilot work through the remainder of this year. We've also taken all the technical work in-house, so we've built our own geological model and dynamic reservoir simulation model. I think it's gonna be important to tie what we're seeing below the ground to the latest in-house modeling work, before we want to do that. I think it becomes much more important to look at the overall pricing environment and whether or not it makes sense to perhaps either sell down or bring in a partner. The great thing is, there's no time clock ticking, which causes us to rush to retain the license, to keep that resource base.
We're going to continually work on the option value of that asset.
Okay, just one more technical question on the share buyback. Christophe, do you have regulatory restrictions and have to wait until November 2020, or are you allowed to start earlier on a new share buyback to take advantage of?
Well, we can currently we can only buy back up to 11.5 million shares. We're constrained by that. Should we want to do another one, we'd have to do that under another legal scheme in Canada. We could do that. Once we've completed 11.5, we can do more. That would have to be under the form of a prospectus. We'd have to go to the market, set a price, and say that we're willing to buy up to a certain number of shares at a certain price. It would be a different setup, but we can do more if we want to.
That was the structure. We did the tender offer in 2017, when we bought back the 25 and a half million shares.
Okay. Last question. We do have a lot of questions about share buybacks and discounts to NAV. I guess it's sort of encapsulated in, Mike, do you have a preference between share buybacks and dividends, and whether you would take either or both of these options this year?
I think, I mean, I think in the short term, when you see the stock trading at such a big discount, it makes more sense to focus on share buybacks. Obviously, as the free cash flow generation accelerates into next year, we can only make that decision at that point in time, when we can see where the stock's trading and what's the best allocation of capital. You know, hopefully, we'll be doing both.
Okay. All right, that's it for internet questions. No more questions from the room. Mike, did you want to close?
Yeah, I'd just like to thank everyone for tuning in today. Thanks for all our guests in the room here in Stockholm, for participating and your questions, and for everyone that was tuned in the website. Thank you very much indeed.
Yeah. Thank you.