Very good morning to everybody, and welcome to IPC's first quarter results and operations update presentation. My name is Mike Nicholson. I'm the CEO of IPC. I'm also joined this morning by Christophe Nerguararian, who's the CFO, and Rebecca Gordon, who's our VP of Corporate Planning and Investor Relations. I'll begin in the usual fashion by walking through the operations update, and then I'll pass across to Christophe, and he'll walk through the financial numbers for the first quarter. At the end of the presentation, we'll open up and you'll have the ability to ask questions, and we'll take those from the participants joining from the conference call or from the questions that are submitted online. To get started, the Q1 highlights. It's been a very strong first quarter for IPC.
For the first time in two years, we've seen synchronized strong Brent prices, very tight differentials, strong gas prices, and exceptionally high uptime performance, which has led to very strong production. Just to put things in context before we start the presentation, the last time we had this kind of first-quarter production and free cash flow delivery was Q1 of 2019, and the stock was trading at SEK 50 a share, and today we're trading close to SEK 30 a share. I think there's still some seriously huge upside for IPC investors. Let's get into the highlights for the first quarter. Our Q1 average net production was just under 44,000 barrels of oil equivalent per day, and that was above our high-end guidance.
As a result of that, I will get into more details in the presentation, but we certainly feel confident to say that we are trending towards the upside of our full-year guidance. First quarter operating costs of $14.40 a barrel were exactly in line with guidance, and we retain the full-year guidance numbers that we gave in our Capital Markets Day. In terms of our organic growth program, still very limited capital expenditure programs of $37 million for the full year. As we mentioned in our February CMD presentation, we do still have some execution flexibility in Q4 to add some infill drilling at either our Onion Lake Thermal project in Canada or our Bertam project in Malaysia. I will come back and just recap on those details. In terms of cash flow generation, it was an exceptionally strong quarter for IPC.
Our first quarter operating cash flow was just under $70 million, and a free cash flow generation of $49 million. In just one quarter, that represents approximately 10% of the company's market capitalization. Of course, all that free cash flow was used to reduce our debt levels. Net debt at the end of the first quarter stood at $286 million. Of course, that's indeed had an impact on our leverage ratios with our net debt to EBITDA leverage ratio dropping to 1.8x for the last 12 months. If you annualize the first quarter EBITDA, we will be down at close to 1.1x . Our balance sheet's starting to get in extremely strong condition.
In terms of business development activity, as we mentioned in February, we are pleased to conclude the acquisition of the remaining 25% interest in our Bertam field in Malaysia. There was no upfront consideration to acquire that interest. Still a very strong performance on the ESG front. No operational impacts as a result of COVID, no material safety incidents, and we have secured through our partnership with First Climate the carbon offsets that we need on our five-year journey, and to reduce our net emissions intensity by 50% by the end of 2025. Really good start to 2021. Getting now into a little bit more details on our production numbers. As I mentioned, first quarter production was 43,700 barrels of oil equivalent per day. If you look at the chart on this slide, you can see the Capital Markets Day high and low range.
Across the quarter, we were above that high-end range for most of that period. As really as a result in Canada, a very high uptime and strong reservoir performance. Particularly during February and March, there was a shorter, sharper winter in Canada, which meant we weren't impacted by the freeze-offs on our Canadian gas production as much as we've seen in previous years. A nice combination of events to drive a good, strong production performance in Canada. Likewise, internationally, our Malaysian business, the Bertam FPSO, continued to have exceptionally high operating uptime of 100% during the first quarter. Again, you're going to see continued strong, good performance on all of our core producing assets in our French business. Really everything operational excellence delivered by all of our teams on the ground. A great job done by everyone there.
What does that mean in terms of our full-year guidance? Just to recap, in our Capital Markets Day presentation, we'd announced a guidance range of 41,000-43,000 barrels of oil equivalent per day. That did include the step-up in our working interest in our Bertam Field in Malaysia to 100% from the April 10th, 2021. The investment program that embarked in the first quarter and was largely targeted at production increases on our Onion Lake Thermal Pad D', which is going to see a steady ramp-up in production during the second half. The fact that we're seeing those production adds in the second half, combined with an above high-end guidance performance in Q1, leads us to feel confident to state that we expect our full year numbers to be up towards the high end of that 43,000 barrels of oil equivalent per day guidance range.
The investment strategy that we announced back in February is unchanged. It's still focused on a very limited CapEx budget for 2021, focused on maximizing our free cash flow generation. That budget is $37 million. As we said then, quite a significant drop from the 2020 expenditure levels, which was cut back significantly, down 55% from last year. As I mentioned on the previous slide, the key capital spend for this year is on our Onion Lake Thermal project. I'll come back to give you an update on progress there. We do have that flexibility, should we choose to do so, to add some additional infill drilling at Onion Lake Thermal in the fourth quarter or to drill an additional infill well in our Malaysian Bertam field.
In terms of the free cash flow breakeven of the 2021 expenditure program, fully funded below $40 per barrel with a differential of $2 for the WTI and $13 for the WCS. Given that today Brent prices are closer to $70 per barrel and differentials are similar to those levels, you're going to see some pretty phenomenal free cash flow generation, and I'll get back to where that stands in the context of our full-year numbers in the next couple of slides. Before we talk about the cash flow generation, I think it is important to touch upon the improvements that we're seeing in the fundamentals for Canadian crude differentials. We've talked about this slide over a number of years, and what we've seen in Canada, certainly for more than the last five years, was that production was running ahead of available egress capacity.
With the progress and the construction progress that we're seeing on Enbridge Line 3, which is now 60% complete, also the ongoing construction of Trans Mountain pipeline, that pipeline due to come into service late 2022, early 2023, means that for the first time in more than five years, we've got more than enough egress capacity. We're starting to see that play out in terms of the fundamentals that support Canadian crude price differentials. If you look at forward markets for 2022 and 2023, we're seeing WCS differential trade at below $13 per barrel in levels that we haven't seen for quite some time. Of course, IPC, with the three acquisitions that we've made in Canada over these last three years, has positioned itself extremely well to take advantage of those improving pricing dynamics.
If we now look at the operating cash flow guidance, as I mentioned in the highlights, our first quarter operating cash flow was $68 million. That was based on $61 per barrel average Brent prices with WTI differentials averaging $3 and Canadian WCS differentials averaging $12.50 per barrel. Below the high-end Brent price forecast. If you look at that relative to the $65 forecast, we were guiding operating cash flow of somewhere between $210 million-$220 million. Notwithstanding the fact that Brent prices were actually below that $65 per barrel high case, we generated close to 1/3 of that full-year OCF guidance. That was really a result of the stronger production performance, higher gas prices, and tighter differentials. 2021 off to a great start.
In terms of our capital expenditure during the first quarter, it was exactly in line with guidance, $12 million, which was close to 1/3 of our $37 million in capital expenditure budget. How does that feed through into our free cash flow generation? As I mentioned, with $61 Brent and less than $13 diffs, we had an exceptional free cash flow generation of $49 million during the first quarter. Again, if you look at that high-end guidance of $65 that we were forecasting, we were looking at a range for the full year of somewhere between $148 million-$155 million. In the first quarter alone, we've generated close to 1/3 of that high-end free cash flow guidance.
With forward-looking Brent prices closer to $70 today and still seeing very tight crude differentials around $13 per barrel and a strong production performance, if oil prices stay at these levels, then we can expect IPC to generate well in excess of that high-end guidance that we've already announced. That really ties back to the long-term free cash flow guidance that we gave back in February. We showed that if you look at the five-year business plan for IPC, we can keep production essentially flat at 45,000 barrels per day with an average capital investment maintenance CapEx of $4.50 per barrel. Between $55-$65 Brent long-term oil prices generates somewhere between $600 million-$900 million of free cash flow. If you look at the quarterly average, that would be around $45 million of free cash flow per quarter.
Production is lower than that five-year average that we're guiding for Q1, and we're already close to $50 million. You can see that these long-term free cash flow guidance numbers are absolutely anchored in reality. Great cash flow numbers and exceptional free cash flow yields. If you also look at IPC through the valuation metric, I think you can also say it's an extremely undervalued 2P reserve base that we have. Our year-end 2020 2P net asset value was around $1.3 billion. That 2P reserve base is calculated using oil prices which are significantly lower than where we stand today. We're looking at $48 per barrel for this year, long-term prices don't get to $57 per barrel until 2025.
On those pricing assumptions, if you look at the share price of SEK 20.3 a share at the end of March, at the end of the first quarter, we're trading at about a 61% discount to that SEK 70 per share 2P net asset value on a conservative price take. That does not include a single dollar of value assigned to the 1 billion barrels of contingent resources that we have in the portfolio. Now a few slides on each of the key operating areas, starting in Canada first. If we turn to our Suffield oil asset. Very strong and steady production performance through the first quarter. If you look at the chart on the bottom right-hand side of the screen, you can see we've been producing in excess of 8,000 barrels of oil equivalent per day during the first quarter.
That's at levels above first quarter 2016 levels. One of the key factors that's driving that strong performance is the N2N enhanced oil recovery project that we sanctioned two years ago. It was always going to be a slow burn and a slow ramp-up. That project is performing ahead of schedule. If you look at the chart on the top right-hand side of the slide, you can see the red line was our investment case, and the hard blue line is our production actuals. You can see the ramp-up in production is running well ahead of expectation. No further major capital activities are planned on the Suffield property on the oil side for the remainder of 2021. We do have a deep inventory of additional infill drilling locations, and we can restart that program extremely quickly.
Huge amount of discretion with respect to how quickly we want to restart drilling on our Suffield oil property. On the gas side, Suffield Gas, really good cash flows in Q1. Christophe will show the gas price numbers in his presentation. The focus there has been unchanged for the last couple of years. It's manage the natural declines with very low cost optimization activity. There's no major capital expenditures planned for the first quarter. What you can see from the chart on the bottom right-hand side of this slide is that we've got a very active gas swabbing program. We've been ramping that up since we took over operatorship in 2018, and we expect those optimization activity levels from 2020 to continue into 2021.
If you look at the production performance on the bottom right-hand side of this slide, we did see a dip in February with the cold weather. As you can see, our current production, our spot production, is back up to around 100 million standard cubic feet per day. Very steady low declines on the Suffield gas property there. Turning to Onion Lake Thermal, again, from the chart on the bottom of this slide, you can see again a very stable production performance. The biggest project that we have going on there this year, which started in the first quarter, is the completion of the Pad D' tie-in works. We've gone into the turnaround at the beginning of this month. Project is going very well. It's on schedule, it's on budget, and we expect to start steaming up at the end of this month.
What we should see is a steady and gradual ramp-up in production through the second half of 2021, which should see production adds by the year end of in excess of 1,500 barrels of oil equivalent per day. That's why we guided in our February Capital Markets Day guidance that we expected to exit 2021 above the high end of that 43,000 barrels per day range. I did mention we've got some flexibility about some further activities that we could take at any point in time. There's five infill wells have been identified. You can see it's right in the heart of the property.
If you look at the yellow box on the map on the right-hand side of this slide and the blow-up picture, which shows five separate infill drilling locations that we think can drain additional oil that's not been accessed from the current wells that we have drilled from those existing well pads. All the facilities are in place. The surface locations can be drilled from existing well pads. There's essentially no facilities or CapEx. Really just well drilling CapEx. Of course, as a result of that, we see some pretty stellar economics. You can look at breakevens of $20 per barrel WCS when WCS prices are currently above $50 a barrel. Assuming $55 Brent, you're getting your payback in less than one year. Of course, with an extra $15 on the oil price, that payback time accelerates materially.
The capital expenditure is around $7 million to move forward with those projects. We're not making any decisions right now. If we see in the second half recovery, a more fundamentally based recovery in market balances with demand recovering and matching supply, then it's certainly something that we could move forward with in the fourth quarter if we chose to do so. Ferguson property, which was the acquisition of Granite back in late 2019. Again, we hit the pause button on our investment plans there. We'd originally planned a six-well drilling program last year before market prices collapsed. Current focus is on gas injection and repressurizing via some well conversions. Certainly, as we move into next year, if we see continued strong commodity prices, this would be one of the projects that we want to get going again, at least with a six-well program.
We've got the potential to more than double production with the well locations that we have already identified on this property. On the conventional oil side in Canada, John Lake and Onion Lake Primary are back online. Real focus there is on minimizing our operating costs. We're producing today above 1,000 barrels a day from those properties. As a result of the strong Canadian crude prices, we've taken a decision to look to restart production on our mini asset. That's got the potential to add 500 barrels a day during the second half of 2021. Again, that's another reason why we feel confident to state that full year production should be trending towards the upper end of that 43,000 BOE per day guidance range.
On Blackrod, we continue with our pilot program, the third well pair of the 1.4km horizontal well pair that we drilled last year. The early production results continue to be very positive indeed. If you look at the chart on the bottom left-hand side of the slide, you can see that our initial production rates are running ahead of expectation. The temperature and performance across the entire horizontal section of the well are performing extremely well indeed. This is really important for us because, of course, that can impact the overall economics. That was the reason that we decided to move forward with this project. If we can drain a larger pool of oil from a smaller number of well pads, less infrastructure, less construction, reduced environmental footprint, and that should feed into lower break-even costs.
Not a project for today, but some really good work, and we're getting some really good confirmation on those results and should we see continued high oil prices to mature the subsurface on this project. Turning now to our Bertam field in Malaysia. Just continues to astound us every single quarter since this field was put on stream in 2015. We've had uptime above 99%, and that continued through Q1 of 2021. The big news, as I mentioned in the highlights, was that we added an additional 25% working interest from our partner, PETRONAS Carigali, effective from the April 10th, 2021 of this year. PETRONAS chose to withdraw late last year. As a result, there was zero upfront consideration, and we managed to agree a small assumption of some residual decommissioning liabilities of $1 million. Extremely pleased to have acquired that additional production.
Net to IPC, that adds just in excess of 1,250 barrels of oil per day from the April 10th, 2021. There is still some additional upside on the Bertam field. If we look at the potential to sidetrack our A15 well, we have within our $37 million capital expenditure budget for this year, part of that includes an allowance for long lead items for ESP pumps and for the casing equipment that we'd need to drill that well. There's schedule flexibility. Again, should we choose to do so, we could still move forward with drilling this well in the fourth quarter of this year. Rate potential now that we have 100% interest, if that comes on stream, it would be an add of 1,500 barrels per day.
When you're looking at just Onion Lake Thermal and Bertam, those two projects alone could add above 3,000 barrels a day to our exit rate. Quite a nice little bit of growth in those two projects alone. Again, if you look at the economics on the bottom left-hand side of this slide, it's an extremely robust project. Breakeven's around $35 per barrel. Again, at $55 per barrel, you're getting your money back in around one year. Of course, at $70 a barrel, it's going to be much quicker than that. The additional capital that we would need to invest if we chose to move forward with that project would be $22 million. Finally, turning to the French business. Again, very strong production from all of our fields in France.
VGR-113, which was the redevelopment that we put in place back in 2019, continues to outperform. If I can ask you to look at the chart on the top right-hand side of this slide, you can see the dark blue spiky lines is the actual production performance that we've had from VGR-5. The bump that you can see in January 2021 was when we took the decision to convert our VGR-5 water producer into a water injector. That's important because that now provides pressure support to VGR-113. You can see there's very little decline in production from 113. One of the reasons is we just haven't seen any water breakthrough so far from this well. Our simulation model was expecting water to start to break through in the third quarter of last year, and we still haven't seen any water yet.
That's certainly above expectation and is feeding into the strong performance of the French business. We touched upon before about Total's decision to close the Grandpuits refinery, which was the refinery that we sold our Paris Basin production to. We're now going to be exporting our crude into the refinery in Le Havre, and we've now signed a new five-year contract with Total that sees us through until the end of 2026. As a result, we've locked in that net cost increase that we'd previously guided towards, of an increase of around $5 per barrel relative to the Grandpuits sales option. Turning now to our sustainability and ESG strategy. Still have to be extremely vigilant with respect to our COVID operating protocols across all of our sites in Malaysia, in Canada, and in France.
I think our teams have really done a tremendous job at keeping our people safe and not having any operational interruptions at any of our sites. Tremendous job by the teams on the ground there. As we mentioned in our Capital Markets Day presentation, IPC has made a commitment to reduce our net emissions intensity by 50% at the end of 2025. That target is to be achieved by continued reduction in our operational emissions and also investing in carbon offsets. In line with our partnership that we formed with First Climate, we've been in a position to secure more than double the offsets that we had in 2020. Going from 50,000 tons to 100,000 tons to offset the 2020 emissions. That will be updated in our 2021 sustainability report.
We're moving forward with strengthening our non-financial disclosure reporting. We plan to publish our sustainability report towards the end of this year. We've just concluded a full company-wide materiality assessment. The reason for doing that is so that we can get our sustainability report to be fully GRI compliant this year. Again, a lot of good work going on from our teams across all of the areas of operation in IPC on the ESG front. That concludes my part of the presentation. It's been a great first quarter, and I'll pass you across to Christophe, and he'll walk you through the numbers in more detail. Christophe, across to you.
Thank you Mike. Good morning to everyone. Indeed, a pleasure to be here. What a change from last year. As Mike mentioned, the combination of a very strong operational performance in a much higher oil price and gas price environment means indeed a very good quarter. With Brent on average in excess of $61 for the first quarter and operating costs in line at $14.4 per barrels of oil equivalent, it translated into a very healthy $68 million for operating cash flow and $66 million of EBITDA for that single quarter, translating in turn to a $27 million net profit. The net debt was reduced by $35 million. Most of the free cash flow, and I'll give you the breakdown, essentially was used to reduce that debt.
As we guided previously at our Capital Markets Day in early February, this year is very light on CapEx, very focused on cash flow generation, with that cash flow dedicated to debt reduction. Already from a year-end leverage ratio of 3x , we've been able to deleverage considerably in this first quarter. On the trailing 12 months rolling basis, our leverage has come off from 3x- 1.8x . On an annualized basis, our leverage is much closer to 1x , actually. We're confident that by the end of this year, we should be indeed, on an annual basis, with the leverage at or below 1x . In terms of realized oil prices, the offtake and the liftings were a bit lumpy in Malaysia and France.
We had a strong realized price with a strong cargo in Malaysia in February and another cargo in Aquitaine in France. We had realized prices, which averaged more than $3.5 per barrel on top of the average Brent for the first quarter. Interestingly, in Canada, we've seen despite a much improved Brent and WTI average level in this first quarter, we've seen that the differential between the WTI and the WCS have remained very tight. This is important because obviously, most of our oil production in Canada is sold off that WCS. In terms of premium or discount for Suffield and Onion Lake assets, you can see that the Suffield here realized price was just shy of the WCS of $45 per barrel. More importantly, you can see a much improved, $2 improved netback at Onion Lake Thermal.
This is really driven by the fact that we are sitting now roughly half of our Onion Lake Thermal production blended. We are buying condensate. You can see on our accounts slightly higher condensate cost purchased to blend into our own production, which we then are able to sell at the WCS specification. We've narrowed the gap and are able to sell closer to WCS for 50% of our production at Onion Lake Thermal. Gas prices have improved significantly as well. There was a wave of cold in February, as everyone knows, in North America. The gas prices totally spiked at that moment in time. We were partially hedged, so we didn't fully capture that spike. Still, it's the second-best quarter in terms of realized gas price for our business in Canada.
We sold on average at just above C$3.1 per Mcf, which is exceptional. We also have, I talk to it again at the end of those few slides, but we also built up a very strong hedging on the gas, which should see our average realized gas price just shy of C$3 per Mcf for half of the remaining production this year. Good gas prices in Q1 and well positioned to continue to benefit from a strong gas price going forward. I like this slide particularly because we've turned the corner of 2020, so we are no longer comparing 2020 to the previous year. Obviously, when you see that, it's obvious that 2020 was a very low year and that 2021, starting with this first quarter, has seen exceptional performance where we generated $68 million and $66 million.
dollars of operating cash flow and EBITDA, respectively, as I mentioned before. I think more importantly, this is both ahead of most analyst consensus and as well as our own budget. Really, a good performance, which we hope and do everything we can to continue to deliver. In terms of operating costs, no change to our guidance. The OpEx per barrel of oil equivalent this first quarter was at $14.4 per barrel. We maintain our guidance. We expect to see increased operating costs in the second quarter on the back of a reduced production from the maintenance and turnaround work at both our FPSO in Malaysia and Onion Lake thermal. Overall, we should deliver OpEx per barrel for the year, roughly at the level of our first quarter.
Interesting to look at netback, especially if you look at this in comparison to what we guided previously early February at our Capital Markets Day, because the EBITDA and operating cash flow per barrel are actually $3.5 higher than what we guided in our high case. We've really delivered a good performance. Obviously, given that some of our OpEx are fixed, our increased revenues translate into a much increased EBITDA and operating cash flow. Which itself translates into a much stronger free cash flow compared to our previous guidance. I'll come back to that right now by showing you the breakdown of debt reduction during that first quarter, starting from the $68 million of operating cash flow. The free cash flow generation, so free cash flow for the first quarter, was actually 49, just shy of $50 million.
All of the available cash after the change in working capital was allocated to debt reduction. We reduced our net debt by just in excess of $35 million. We had a change in working capital of $30 million, which was driven by increased activity, increased oil prices, and higher oil inventories, resulting into this increased working cap quarter from the end of last year to this quarter. Generally, you've seen that I talked to the fact that OpEx were in line with expectations. The other main costs, our G&A and finance costs, are under control, flat quarter-over-quarter and in line with expectations. Not much to report other than the costs are under control in our business. Now, the financial results, you can see that the cash margin, given a very low G&A, very low cash taxes.
Our cash margin, which is really revenues less OpEx, is at the same level almost as our EBITDA and operating cash flow at $69 million, translating to gross profit of $38 million and very good net profit for the quarter at $27 million. Our balance sheet, the total size of our balance sheet is relatively flat quarter-on-quarter. The points to note is obviously the debt reduction on the liability side. Generally because there was more activity in Q1 than Q4, we have more payables, but with increased oil prices, we also have more receivables. Finally, given that we only had one lifting in Malaysia, we had a growing oil inventory at the end of March on our balance sheets, generating this positive change in working capital.
We consumed some of the free cash flow as part of our increased working cap, which may unfold over the next months and quarters. The final point is to shed some light around our hedging position. We're in a position where roughly 50% of our Canadian oil production is hedged, as well as 25% for the second half. On average, we managed to lock in a $45 per barrel WCS, which is once again higher than our best case and our high case from our Capital Markets Day. They're very happy with that level, even if today it is actually even higher at closer to $50 WCS.
On the gas side, as I hinted before, we have a mix of forward sales contracts and financial hedges, which translate into the fact that for this second quarter we're in, next quarter, we're roughly 50% hedged and at CAD 2.9 per Mcf. Again, we should be ahead of our previous guidance. Overall, a very good quarter. We've locked in some hedges. Production performance is very good. We're looking forward to some other good performance over the next three quarters this year. Thank you very much, and I will let Mike conclude.
Thank you very much, Christophe, some really phenomenal financial numbers there. Just to recap on the first quarter performance. It's been one of the best quarters that we've seen in more than two years. The last time we had this kind of production levels and free cash flow generation was the first quarter of 2019, when oil prices were averaging around $63 per barrel. As I mentioned, the IPC stock price was closer to SEK 30 a share this morning. When we look at the outlook in terms of the production performance, good gas prices, strong absolute crude prices and tight differentials, we've really got everything in tailwinds running in synchronization. Let's just recap on the highlights for the first quarter. A production of 43,700 barrels of oil equivalent per day above the high-end guidance.
With the good production we've seen through April, with the uplift in our Malaysian interest and with D Prime and Mini coming on stream in the second half, we expect full year production to be towards the top end of that guidance range. Good continued delivery on the OpEx in line with guidance in the first quarter and no changes made to the full year numbers. Organic growth CapEx remains limited, delivering very strong free cash flow at $37 million. We do have some optionality at Onion Lake Thermal in Canada and in Malaysia for the fourth quarter, if we continue to see us running above that high-end guidance that we gave in excess of $150 million of free cash flow. Cash flow for the first quarter was above the high-end guidance at just under $70 million.
The first quarter free cash flow generation was an exceptional $49 million, which represents in one quarter only close to 10% of IPC's market cap at the end of the first quarter. The balance sheet's in much better position than it was last year during the pandemic. Quarter end net debt is $286 million. We're seeing the power of that free cash flow on the deleveraging. At the end of December, our net debt to EBITDA ratio was 3x , and already by the end of the first quarter, that's dropped to 1.8x . If you annualize our Q1 EBITDA, we'll be down at close to 1.1x . Again, the balance sheet's now in really good shape. Good performance on the BD front. We were able to conclude the acquisition of a 25% interest in our Bertam field in Malaysia for no consideration.
That adds from the April 10th, 2021, 1,250 barrels a day of extra production. It's a bit like picking up an infill well without having to pay for the CapEx to drill it. On the ESG side as well, no material safety incidents, no interruptions to any of our operational sites. As I mentioned, we've secured the carbon offset credits that we need in 2021 to offset our 2020 emission reductions target. I think it's been a very solid performance, and congratulations to the whole IPC team that have been a part of delivering this performance. That concludes the presentation part. I guess we can turn over now to open up for some Q&A. Christophe.
Thank you. If you do wish to ask a question, please press zero one on your telephone keypad. If you wish to withdraw your question, you may do so by pressing zero two. There will be a brief pause while questions are being registered. The first question comes from the line of Teodor Nilsen from SpareBank 1 Markets. Please go ahead. Your line is open.
Good morning, congrats on the impressive results for Q1. I have three questions, actually. First, on guidance. Mike, you said that you likely will come in the upper end of the current guidance. I just wonder how sensitive is that statement to oil and gas prices? Let's say that, okay, we'll see $50 oil price and not close to $70 through the remaining of the year. Would you still expect to end up in the upper end of the guided range? Second question is on the emission reduction. You're talking about 50% reduction by 2025, and that will come from both operational initiatives and also some other offsetting initiatives. I just wonder, is it possible to be more specific and also maybe share some thoughts around the costs and investments required for those 50% reduction? My final question is on the pecking order for cash flow.
Of course, net debt is coming rapidly down now. How do you think around dividends versus M&A, and when should we expect the dividend? That's all.
Okay, yeah. The first question on the cash flow guidance, let me just refer back to the slide to give you a bit of direction there, Teodor. If we look at the full year numbers that we gave in our guidance, you can see on average, you're looking at between a $10 increase in Brent crude prices, at $55 per barrel, we're assuming around $100 million of free cash flow. At $65, we're looking around $150. One can see for every $10 per barrel, you're looking at about a $50 million increase. Of course, that's on a full year basis, you would need to adjust that for the period of the year that's remaining.
Christophe showed at Capital Markets Day in his presentation that the impact of a $5 per barrel tightening of the Canadian crude price differential would translate into about a $30 million uplift in free cash flow as well. If you look at that high-end guidance that we gave at $65 of around $150 million, it assumed WTI differentials of four and a WCS differential of 17. You had a $21 discount from your $65 per barrel price forecast. We were looking at WCS prices of $44 per barrel in that upside scenario, and Canadian crude prices today are trading around $53- $54. I think all the information is there in the net backs to be able to extrapolate that.
If you're looking at $65 plus today and $30 differentials with the beat in Q1, we should be looking at well in excess of that high-end guidance. Your second question was on the ESG and the carbon offset projects. You talked about the numbers in the projects. Far in terms of operational reductions that we've seen from our assets, we've seen about 100,000 tons. That's been split between our project, our Bertam project in Malaysia, where we invested in dual-fuel power generation, which allowed us to use the flash gas of the separators to generate power to run our pumps, as opposed to using diesel. In Canada, it was the investment in the heat recovery units that reduces the amount of gas that we need to run our facilities.
If you look at the offsets that we've secured relative to the operational emissions reductions for this year, it's about 100,000 tons each. The particular project that we've partnered with for last year and for this year's credits is a solar power project. It's a 100-megawatt project in the northern region of Punjab. It's credits that are generated by greening up the grid in northern India. Without that project going ahead, it's about 70% of India's energy production comes from coal-fired power generation. By moving forward with this solar project, that generates carbon credits, which we are purchasing through our partnership with First Climate. The cost of those is all embedded in our operating cost guide forecast. On your third question with respect to priority for the free cash flow generation.
I think right now, as you've seen, all the free cash flow that we're generating is going towards debt reduction. During our Capital Markets Day presentation, we were asked about buybacks, which is your question. We said the last time that we launched a buyback program was when our leverage ratio was below 1x . I think we reported this morning a big step forward towards that deleveraging. On a last 12-month basis, we're 1.8x . Our sense is we want to be pretty cautious because we have to recognize that the recovery that we've seen in oil prices has been really at the feet of OPEC and Saudi Arabia in particular. We've still got a significant amount of supply that's been withheld from the market. We would like to see the continued rollout of the vaccination program.
We'd like to see a fundamental recovery in demand in the second half. If we see continued strong oil prices, that will see us deleverage. You're going to see stock levels move back to much more fundamentally balanced levels. I think if we've got that combination of things would then start to make us feel much more confident about relaunching a buyback program. I think that covers all your questions, Teodor.
Yes. That actually my first question. My question was more on the volume sensitivity and not on the cash flow, but I can reach out to Rebecca later on.
Okay, thank you.
Okay, thank you.
Thanks.
Thank you. Just a reminder that if you would like to ask a question, please press zero one on your telephone keypad. We have no further questions from the audio line, so I will pass back for any online questions.
Okay, thank you. Actually, we had a lot of online questions on dividends and buybacks. I think you've answered that, Mike, so we'll avoid those ones. Mike, question on Onion Lake. How much production shutt-in do you expect during the ramp up of Pad D'? How much incremental production thereafter when Pad D' comes online?
To give some general guidance, the way the team in Canada have planned the shutdown is gradually across the full month of May. There are two trains in Onion Lake Thermal. We've got a couple of days at the beginning of the month where we had a full shutdown, then for the remainder of the month, there's going to be one train down for approximately half the month, another train down for the second half. Typically, Onion Thermal is producing around 10,000-11,000 barrels per day, we expect a reduction in production just for that particular month of around 4,000 barrels a day on average across the month of May.
In terms of the adds from Pad D', we expect, as I mentioned in the presentation, a slow ramp up, but we should be seeing in excess of 1,500 barrels a day of additional production adds from Pad D' towards the end of this year.
Thanks. A question on hedging for Christophe.
Yep.
What is the hedging strategy going forward with respect to Canadian oil? We have another question here from a different investor, which is, when will you stop hedging Canadian production? Will it be with Enbridge Line 3 online?
Yeah, no, it's a good question. Obviously coming from where we're coming with 2020 back in our mind, we were happy to be able to lock in some of our Canadian oil production at above the high end of our range. Mike mentioned before the high end for WCS prices, in our budget was 44. We've managed to hedge above that level at 45, 50% in the second quarter, 25% of our Canadian oil production in the second half of this year. There's always some reason to ensure minimum cash going forward to deleverage, to prepare the balance sheet in case we want to do a bit more CapEx, to have a solid balance sheet in case we find some M&A opportunities. It's really about managing the unexpected. We don't have a formal policy. We don't have bank hedging covenants as we speak.
Given that WCS can be hedged for the second half of this year right now at $ 50 on average, we will continue to discuss and appreciate if we want to lock in a bit more for the second half of this year, because WCS at $50 is a very high level, obviously more than 10% above where we guided in the high end of the range. Just to comment on the last part of the question, I think it's a very fair point to note, as Mike explained before, that we're almost there with Line 3, which is expected to come on stream by the end of this year. Trans Mountain and the extension of Trans Mountain is also progressing very well. All of this should stabilize going forward, the WTI, WCS differential. Bodes very well for IPC business overall and in Canada in particular.
We'll reevaluate what we want to do in terms of hedging for 2022. Definitely, if you look at the last two years, 2019, 2020, and this first quarter, on average, the WTI, WCS differential has been between 12 and 13 on average over those periods. Really good sign for our business.
Okay, thanks, Christophe. Mike, regarding the additional growth opportunities, first question is there any threshold oil price level you want to see over a sustained period of time in order for you to formally add these to the CapEx program?
No, we haven't set an absolute target. Obviously, the interaction between Brent prices and continued strong differentials will help. If we are still trending towards the high-end guidance or even above that with tighter differentials, that certainly puts us on very solid footing to look to move forward with those. I think what's going to be important is the outlook into 2022. Because if we make these additional investments, it's going to have a limited impact on our 2021 numbers. If it can add entry level production capacity for 2022, and as I said, we've seen that solid recovery in demand and inventory levels rebalance. I think it's more how that forward outlook is into 2022 transpires before we decide to do anything more firm on those optional projects.
Okay, thank you. Second question on the well drilling candidates. Why are you looking for M&A when you have those returns on your internal well drilling candidates? If you want to grow, where can you find better returns?
If you look at those two projects alone.
We're talking about $30 million of incremental investment. If you're looking at tight differentials and free cash flow potential, as I mentioned, in excess of $180 million, if you add in the tight differential upside on our high case, I don't think we're limited by looking at further M&A by a $30 million investment addition program. I think we've got the financial capacity to do both.
Okay. A question on M&A again. Are you involved in any current M&A processes in Malaysia and is that a focus area for M&A?
We don't comment on particular specific jurisdictions. I think a general comment is for sure we've seen an uptick in M&A activity, particularly relative to 2020. We're always actively engaged in screening a number of opportunities and, like most of the time since IPC was spun off back in 2017, we have ongoing, a number of opportunities that we are engaged in. It's just part and parcel of what we do on a month-to-month basis.
Okay. In terms of operations and the netbacks we're seeing from onshore Canada, what are we seeing from producers in neighboring properties? Are we seeing the same sort of benefits or is it a mixed bag then?
I think in general across the Canadian energy space, of course, absolute prices and crude differentials and gas prices impact all producers alike. I think what you're going to see in the first quarter is across the whole Canadian energy space, a fundamental improvement in their free cash flow generation. It's not isolated to IPC, but I think the fact that we bought into that whole story, at a point where differentials were distressed and valuations were extremely low, I think we've got a phenomenal platform to create a huge amount of value for our shareholders.
Okay, thank you. One more for Christophe. Just a question on the long-term leverage ratio.
Well, again, 3x at the end of last year is not in absolute terms an issue, but for the oil industry, for the upstream, it's a bit high. We feel definitely much more comfortable today. We don't have a set leverage level that we want to achieve. Typically, if by year-end we are at or below 1x , it opens the door to considering buybacks, as Mike mentioned before. That needs to be weighed against some very good payback and very good high return projects that we may consider as the additional CapEx we could spend in Canada or Malaysia. Of course, we want to continue to deleverage from where we are, and we expect that to naturally happen in the next two, three quarters.
Christophe. Mike, one last question from the webcast. Will you be positioned in a couple of years to develop Blackrod on your own or will you need to bring in a partner?
I think it's too early to answer that question right now. All the work that has gone on right now by our team in country is to really mature the whole kind of subsurface and development concept on Blackrod, by moving forward with the 3rd well pair and using the latest technology. Much longer horizontal drilling, using latest flow control devices, as we said, to try and reduce the construction and drilling footprint and environmental footprint and get those breakeven costs down. We're going to be in a very good position. I think the one thing about that project that sets it apart from other growth projects is that we have all the environmental permits and the construction permits in place.
If we choose to move forward with the first phase development of the 180 million barrels out of the billion barrels of contingent resource, we can do so without any further approval. That's obviously very attractive to partners. Whether we choose to move forward ourselves or to bring in a partner, I think a project of that size and scale, it would be more prudent to dilute our interest. No decisions have been made in that respect thus far.
Yes. Thanks, Mike. I believe we have one more question on the line. Operator, could you set up for that?
Thank you. Yes, we have one more question from James Hosie from Barclays. Please go ahead. Your line is open.
Hi. Good morning. Thanks for taking the question. I was just wondering on your debt facilities and whether any of the facilities have restrictions on your ability to resume shareholder returns. Is there a list of priorities in terms of which facilities you'd be looking to pay down first through this year?
Yeah. Thank you, James. Well, yeah, as you know, you have all sorts of governance and limitations in debt facilities. There are provisions which in certain cases allow you, including driven by leverage, which allow us to return capital to shareholders. That's embedded in the credit facilities we have. If we can, and as much as possible, we like to obviously reduce and repay our most expensive credit lines. As much as possible, that's what we would do and focus on. Generally, especially in Canada, where some of the finance costs are driven by leverage, we should also see, especially in the second half of this year when the leverage really materializes, some reduction in the cost of debt.
Okay. Thanks very much.
Okay. Operator, no more hands?
Thank you. We have no further questions. I will pass back for any closing comments.
Okay. Thank you very much, operator. Thanks, everyone, for taking the time to tune in this morning. I think it's been an exceptionally strong performance by IPC during the first quarter, and we look forward to that continuing and then reporting in early August for our second quarter results. Thank you very much indeed, everybody.