Thank you all for standing by, ladies and gentlemen. Welcome to today's year-end 2020 results. I would now like to hand the call over to our speaker, CEO Mr. Mike Nicholson.
Thank you very much, Moderator, and a very good morning to everybody, and welcome to IPC's Year-end Results and Operations Update Presentation. My name is Mike Nicholson. I'm the CEO. I'm also joined this morning by Christophe Nerguararian, the CFO, and Rebecca Gordon, who's our VP of Investor Relations and Corporate Planning. I'll begin in the usual fashion by giving a walkthrough and the highlights of the fourth quarter and full-year performance. I'll then pass across to Christophe, who will walk through the financial numbers for Q4 and for the full year. And then at the end of both of our presentations, we'll, of course, have the opportunity to have a Q&A session. And you can send your questions in via the web link, or those participants joining in the conference call can also take questions.
It will be a relatively short presentation this morning, really just focused on the backward-looking 2020 results. So if I can ask, we've got a long presentation this afternoon that's Capital Markets Day forecasts and our 2021 and beyond long-term forecasts. So if any questions this morning can be reserved to the 2021 numbers, and you'll have the opportunity to talk Capital Markets Day forecasts this afternoon. So turning now to the 2020 highlights, and starting with production, our fourth quarter average net production was actually just under 45,000 barrels of oil equivalent per day, and that was an improvement slightly ahead of what we were expecting. We're about 7% up on our third quarter numbers, and I'll come back to that.
But we saw continued good recovery on some of the Canadian oil production that we'd shut in predominantly at Onion Lake Thermal and at Suffield. That gave us a full-year average production in excess of 42,000 barrels of oil equivalent per day, and that was in line with the latest guidance that we gave in our third quarter presentation. Continued very good delivery on the low-cost reset that we had on our operating costs for the full year and for our fourth quarter results. Our average operating costs were just marginally under $12 per BOE, and that was also in line with the latest guidance that we gave during our third quarter presentation.
I think one of the most impressive things that we were able to do through 2020 when we were hit with the COVID crisis and the collapse in oil demand and profound price weakness at the end of the first quarter, we moved extremely quickly to completely reset our capital expenditure and growth plans for the full year. Originally, we'd expected to invest in excess of $160 million, and we moved swiftly to cut that by more than 50% relative Capital Markets Day guidance, and our full-year outturn was just over $80 million, and that really set us in good stead to start to maximize our ability to generate free cash flow, and what was a pretty challenging year, and if you look at the cash flow numbers, our full-year operating cash flow was just under $120 million.
And as a result of those business reset decisions that we took, curtailing production, cutting CapEx, cutting OpEx, and then progressively layering hedges and ramping production back up as oil prices recovered, meant that for the full year, we were actually able to generate a positive free cash flow of just below $9 million, $10 million, sorry. Our fourth quarter cash flow was reflecting the recovery in both our oil production and also in oil prices, and we were able to generate $46 million of operating cash flow, an impressive free cash flow generation of $29 million. And you'll hear this afternoon that's expected to continue into 2021 and the years ahead. Strong position on the liquidity front. Net debt stood at just over $320 million, and we still got significant liquidity headroom under our existing banking facilities.
Proved reserves at year-end stood at just over 270 million barrels, and we still have one of the key features of IPC's reserve base, a very long-life, low-decline, highly developed reserve base, so 18 years of reserve life and significantly in excess of 1.1 billion barrels of contingent resources. On the ESG side, very pleased that we had no incidents, particularly given the pandemic situation that we faced during 2020. We put in very stringent operating protocols. Our teams adapted their working practices to deal with the restrictions that we faced, and we didn't have at any of our operating sites any shutdowns or curtailments, and we didn't have any serious incidents through the full year, and I think that was a huge credit to all of our operating teams on the ground.
As part of our continued ESG journey, we issued our first sustainability report during the third quarter, and we reinforced our commitment to our emissions reduction strategy, which is set to see our net carbon intensity reduce by 50% over a five-year period to 20 kg per BOE, and I'm pleased to report that we were able to offset 50,000 tons of CO2 through the course of 2020, in addition to the operational efficiencies that we've invested in our producing assets. Turning now, a little bit more detail on the production side. As I mentioned, our fourth quarter production numbers of just under 45,000 barrels of oil equivalent had been running slightly above forecast.
You can see, if you look at the chart on the right-hand side of the page, where we took action in late March to start curtailing our Canadian oil production in response to low prices and price levels dropping below break-even, but as the situation started to improve through May and June, we layered in some hedges, and we took the decision to ramp that production back up to pre-curtailment levels, and I think when you look at the far right-hand side of the chart, you can see that our exit rate was averaging around 44,000-45,000 barrels of oil equivalent per day, so really good performance at Suffield and Onion Lake Thermal and much faster ramp-up than we'd anticipated. Steady performance at our Suffield gas asset.
On the international side, we had phenomenal continued high uptime performance on our Bertam FPSO, on average 100%, just below 100% for the full year, and a steady performance across all of our assets in France, contributing to that recovery in production through the second half. This next slide just shows how our guidance has changed through what was quite a turbulent year. When prices collapsed in the first quarter, we gave our market guidance of 30,000-37,000 barrels of oil equivalent per day. At the bottom end of that range, we were looking at shutting in all of our Canadian oil production with anticipation of weak prices running through the remainder of the year. At the high end of the guidance of 37, we'd been assuming that the 50% curtailment that we'd put in place would continue for the rest of the year.
Thankfully, prices did improve. That gave us the confidence to start to ramp production up from the second quarter. We did put in place a number of hedges to support the restart of Onion Lake Thermal and Suffield. We re-guided the market in our second quarter presentation that we expected to produce somewhere between 37,000 to 40,000 barrels of oil equivalent per day. During the third quarter, as a result of faster than anticipated ramp-up at those two core projects, we increased our guidance further to in excess of 41,000 barrels of oil equivalent per day. As I mentioned, the higher-than-expected forecast production in Q4 of just under 45,000 meant that our actual full-year production was just above 42,000 barrels of oil equivalent per day.
So obviously, quite a turbulent year, but I think our teams did a phenomenal job in first optimizing the production through the low oil pricing environment and also bringing it back up when conditions improved. This next slide just shows how that feeds through into our cash flow generation and our free cash flow across the quarters. As I mentioned, of course, we did half our CapEx budget to just over $82 million. And our operating cash flow for the full year was just under $120 million. Now, we did guide at the beginning of 2020, this time last year, that we expected to generate somewhere between $125 million and $325 million of operating cash flow. Of course, at that time, no one was expecting the global pandemic.
And I think the fact that oil prices averaged for the full year $42 per barrel, it was still impressive that we're very close to generating similar cash flow levels to the $50 forecast that we set out 12 months ago. And if you look at the chart on the right-hand side of the page, you can really see the actions of the business reset and how they delivered exactly what we set out to achieve. Q1 was a front-end loaded growth profile, significant capital investment, and we had negative free cash flow of $43 million. But when we moved very swiftly at the end of the first quarter to curtail all of our forward-looking investment programs and some of our production, we were already able to achieve free cash flow neutrality in the second quarter.
And as I mentioned, as we progressively brought back on our oil production and prices recovered, you can see the trend in free cash flow generation increasing through the second half. We generated $23 million in the third quarter and $29 million in the fourth quarter. And that really allowed us for the full year to generate that positive free cash flow of just under $10 million . We'll turn now and just go into a little bit more detail on the assets. I think it's important to draw your attention to the recovery. Chris, this afternoon, we'll go into a bit more detail. But I think if you look on the left-hand side of this chart, on the gas side, we've seen very steady performance of our Suffield gas asset.
It was one of the most active years of gas swabbing that we conducted, close to 11,000 swabs for the full year. That really allowed us to keep offset natural declines and keep that production relatively stable at around 100,000 standard cubic feet per day. Looking on the right-hand side of the chart and the Canadian Suffield oil production, you can see how we took that swift action to curtail our oil production during the low oil pricing window. I think you can see now that as we exited 2020, we'd actually been producing at rates back above 8,000 barrels per day. That's in excess of where we were in late 2019. We're actually achieving rates that we haven't seen since 2016.
Good recovery in the base wells, but we're also seeing a better-than-expected performance from our end-to-end enhanced oil recovery goal, which has been ramping up ahead of expectations. We'll have a little bit more to say about that this afternoon when Chris goes through his presentation. Really good performance on both the gas and the oil side at Suffield through 2020. Turning now to Onion Lake Thermal. Again, we've seen strong reservoir performance as we've brought back on stream the single train that we'd shut down during the first quarter in response to the low pricing. You can see we're back producing at levels between 10,000-11,000 barrels per day. We took the decision in a favorable weather window to just finalize the drilling activity on our D-Prime. During the second half, we completed five producers, 14 steam injectors.
That was originally planned to come on stream in 2020, but as a result of the shutdown and the pause in all investment activity, that's now been deferred to 2021, and we're strongly positioned to start tying in those wells in the second quarter and ramping up production in the second half, and again, Chris will provide a bit more color this afternoon Capital Markets Day presentation. Turning to Malaysia now, I think there's been another phenomenal year on the operations side, notwithstanding the pandemic, and our uptime performance was close to 100%, and you can see we've started to see slightly shallowing of the decline, with gross production averaging just under 6,000 barrels a day as we exit 2020. From April of this year, we will be acquiring an additional 25% interest from Petronas Carigali.
One of the things that we'll be looking to do, it won't be in our firm budget, but we still have the potential to proceed with the sidetrack of our A15 well, which has production potential in excess of 1,500 barrels a day. Still looking forward to some upside growth potential in our Malaysian assets. Will, again, this afternoon, will provide more color on the Malaysian business Capital Markets Day presentation. Final slide for me in France. As you can see from the production chart on the bottom left of the slide, stable production from all of our major producing fields. We did take the decision, of course, to pause the three-well development program on our Villeperdue West field. That still remains on hold, pending stable recovery in crude prices.
Total, we did announce in the second quarter that they were discontinuing crude refining operations at the Grandpuits facility in the Paris Basin. We have got a contract in place that runs through till the end of 2021. We're having good discussions with Total about future transportation and sales options. And what we expect in the longer term is a net increase of around $5 per barrel to truck or barge our crude from the Paris Basin to the refinery in Le Havre. So that concludes my part of the presentation. I'll pass across now to Christophe, who will walk you through the financial numbers.
Thank you, Mike. Good morning to everyone. Happy to walk you through the financial highlights for this quarter. Very happy to report that this fourth quarter has been the strongest in 2020 from a financial perspective.
We've seen good cash flows being generated in this fourth quarter. It seems to be on the upward trend, with 2021 starting on a very strong footing as well. In Q4, as I said, it was the highest quarter in terms of cash flows. We produced just shy of 45,000 barrels of oil equivalent per day. The full year was in excess of 42,000, as we guided before, ahead of 41,000 for the full year. The OpEx per barrel were firmly maintained under control and just below the low end of our guidance. We guided initially that we would have $12-$13 per BOE of operating cost. We averaged both for that fourth quarter and on an annual basis, we averaged $11.9 per BOE, which is a very good performance for the full year.
EBITDA and operating cash flows in the fourth quarter were respectively $46 million and $43 million, and $109 million and $119 million respectively for the full year. The net result was negative as we took a post-tax impairment in France of $54 million. That was the result of a much lower price deck used by our reserves auditors as lower by more than $17 per barrel in the long term. So mostly driven by a low price deck to assess the value of our assets in France and to a lesser extent by the additional $5 per barrel of additional transportation cost just mentioned by Mike. When you look at the realized oil prices throughout 2020, it's pretty easy to understand why the fourth quarter has been our strongest quarter in 2020. You can see that it was mainly driven by very good realized prices in Canada.
Strangely enough, the WTI was lower than the first quarter, for instance, but the WCS was much higher. So we benefited from a very tight WTI/WCS differential in Canada of less than $10, when in the first quarter, for instance, it was in excess of $20. So a recovering Brent and WTI in the fourth quarter, but more importantly, a very tight diff in Canada. Now, in terms of how we've been selling and realizing oil prices against benchmark, you can see that our premium in Malaysia is recovering progressively. We were at plus $3 on top of the Brent. In France, it's been improving as well as a result of the fact that we're selling on the pricing of the following month.
So in October, November, December, we've been selling on the average prices of November, December, and January, which were on the upward trend as well, which explains why we've been able to sell on average at a higher price than the Brent in France, when usually our contract is Brent minus $1. In Canada, as I said, very good, the highest WCS for the whole quarter. Although today, as we speak, it's already in excess of $45 still for 2020. That was the highest realized price. And you can see that, interestingly, at Onion Lake, our realized prices have improved. If you compare the first half, 2020, to the second half, 2020, we've gone from WCS minus $ 7 to WCS minus $3-$ 4. And that's a result of the fact that we're blending roughly.
We're using condensate to blend into our Onion Lake production to sell 50% of our production at the WCS specs, which is a lighter crude than the one we're actually producing. So that helps us sell a portion of Onion Lake production at the WCS. It's roughly 50/50 between the blend proportion that is blended and unblended. If you look at the realized gas prices, very good gas prices as well in this fourth quarter, which is usually the case. There is some seasonality in Canadian gas prices, and with colder temperatures, gas prices tend to move higher up. Now, the other important point is that, on average, since the end of 2019, because the logistical issues that Alberta was facing have been resolved, you can see that there's virtually no more difference in between AECO and Empress, which is where we're selling our gas.
So we're selling virtually at the AECO gas price from late 2019. Interesting to note that as well, in a similar fashion as currently, oil prices are much higher than even Q4. Gas prices are as well projected to be higher on average in 2021. We'll touch upon that this afternoon when we go through our Capital Markets Day. Moving on, on the operating cash flow and EBITDA, it's obvious that 2020 was a challenging year when you look at this graph and compare 2020 to the financial performance in 2019. But actually, I find it highly interesting because it shows the huge potential that our portfolio of assets have to generate significantly higher cash flows than what we've been doing in 2020. So we still managed to generate positive free cash flow in 2020, as Mike mentioned before.
But you can see that there is considerable upside in a higher oil price environment with our portfolio of assets. And moving on to the operating cash flow and EBITDA for the fourth quarter, whereas for the full year, the 2020 cash flows were roughly 35%-38% of what we generated in 2019. It's close to 55%-60% for the fourth quarter. So you see that we were performing much better in Q4, and we're on an upward trend, as I mentioned, and expecting to generate even more in the first quarter. On the operating cash flow, operating costs, sorry, front, as I mentioned, we've spent tremendous efforts and resources into controlling and maintaining low OpEx in 2020. That was not a given, provided that some portion of our operating costs are fixed.
Or we thought they were fixed, but we actually managed to reduce even our fixed costs in this challenging year, delivering a very low OPEX per barrel of oil equivalent below our guidance at $11.9 per BOE on average for the full year. In terms of netback, very happy to report as well that our operating cash flow and EBITDA per barrel of oil equivalent have considerably improved. Fourth quarter is $11.2 per BOE of operating cash flow per barrel compared to $8 on average, and just above $10 per BOE for EBITDA on average for the full year. Now, if you compare that to 2019, we had a level of $18 per BOE. So there's still considerable upside to those numbers, as I mentioned before.
And certainly, in the current oil price environment, we should be able to further increase significantly our netbacks, both in terms of operating cash flow or EBITDA per BOE. Looking at the cash flows and net debt throughout 2020, so even though it was a very challenging year, arguably one of the most challenging years ever for the oil industry and for the world economy in general, we generated enough operating cash flow in 2020 to fund all of our OpEx, decommissioning, G&A cost, financial items. The net debt only increased marginally because of the depreciation of the dollar. So we had some FX moves driven by a weakening of the dollar against our main local currencies, Euro, Canadian dollar, or Malaysian ringgit, and a negative change in working capital. With the exception of that FX change and change in working capital, our net debt would have been flat.
So we had $321 million of net debt at the end of 2020. With our EBITDA just shy of $110 million, we're actually at a leverage net debt to EBITDA level just below, virtually at three times. Now, if you would look at an annualized fourth quarter EBITDA, the leverage would be below two times already. So in terms of free cash flow generation and deleveraging, we're very well positioned to improve and solidify further our balance sheets going into 2021. Looking at the G&A and financial items, obviously, as you'd expect, G&A were flat to reducing in 2020 and were kept fairly low at $0.8 per BOE in 2020.
In terms of net financial items, you can see that interest expenses, if you would compare those in the fourth quarter, they've increased slightly compared to the third quarter, and that is a result of marginally increasing financial costs and margins resulting from the refinancing and the extension of the maturity we negotiated with all our banking partners in the middle of the summer. So that's the only point to note. There's a non-cash FX gain, which results, as I just mentioned, from the weakening of the dollar against Canadian dollar. It's a non-cash element and doesn't really have any impact on our cash flows.
Looking at the financial results, we had a solid cash margin of $120 million, and really our net result for the year was negative, mainly driven by the impairment, the French impairment we talked about, which, again, was assessed in the context of a much reduced price deck used by our reserves auditors. It's interesting to note that currently, the oil price is $12 in excess of what that price deck is for 2021, and it's actually higher. Today's price deck is higher than the long-term oil price used to assess the value of our French assets. That impairment is driven by low oil prices, and that was a conservative move, and we're fine with that, but just wanted to give some element of context why it was so significant. Looking at the balance sheet, size of balance sheet is essentially the same.
I think it's worth noting the reduction in both current assets and current liabilities driven by the reduction in receivables because at the end of 2020, oil prices were lower than oil prices at the end of 2019. So receivables are lower. Similarly, for different reasons, liabilities were lower because we had virtually no trading activity in our business at the end of 2020 when we had quite a bit going on in Malaysia at the end of 2019. As a consequence, payables were as well much lower at the end of this year, at the end of 2020. Just a point to note, the financial liabilities, so our debt increased by roughly $55 million, and that was mostly driven, if you compare the end of 2019 to the end of 2020, that was mostly driven by our Ferguson or Granite acquisition, which was fully debt financed.
There was no dilution to shareholders used for that acquisition. And just to summarize on the financial hedging we have in place, to simplify those charts, it's easier to say that we have hedged 2,500 barrels a day of Canadian production for the first six months of 2021 at the WCS price of approximately $28-$29 per barrel. And that was essentially driven by a bank covenant from a very small facility for Granite. And the additional hedges we may have to put in place in the future are a fraction of that on the oil side. On the gas side, very happy to report that we've been able to lock in some of the very strong gas prices we've seen on the market lately.
Looking into 2021, the combination of financial hedges and forward sales, we've been able to lock in around CAD 3 per MCF for 50% of our production and for the first nine months of 2021. For the first nine months, 50% of our gas production will average a realized price of CAD 3 per MCF. That would be the highest realized price that we've witnessed since we took over the Suffield assets from Cenovus in early 2018. That was my part on the financial highlights for this fourth quarter. Very happy to hand the mic back to Mike to conclude.
Okay. Yeah. Thank you. Thank you very much, Christophe. Just to recap on the highlights for 2020, I think we've finished the year in a very, very strong position, and it sets the company up extremely well as we move into 2021.
As I mentioned, our average fourth quarter production was just below 45,000 barrels of oil equivalent per day, and good recovery from all the assets that we had curtailed during the first half of the year. Full year average production in excess of 42,000 barrels of oil equivalent per day. We expect to keep that production stable as we move into 2021. Excellent operating cost numbers as a result of the reset, $12 per barrel, which was at the bottom end of the guidance that we gave in the middle of the year and in line with our third quarter guidance. Continued delivery on the capital reduction program, 50% reduction from our original guidance, which was really aimed at ensuring we could maximize our free cash flow generation. That's exactly what we did.
On $120 million of operating cash flow, we fully funded that capital expenditure program and other expenditure commitments, and still were able to generate a free cash flow of $9 million when oil prices averaged only $42 per barrel Brent. I think the most impressive thing was the fourth quarter numbers as the recovery in production and prices started to come through. Our fourth quarter operating cash flow was just under $50 million, and our free cash flow generation was just under $30 million. When you consider, as Christophe has touched upon, gas prices are strong in Canada, Brent prices are significantly stronger than where they were in Q4, and Canadian differentials are as tight as we've seen in many, many years.
That momentum in terms of free cash flow generation is going to continue into 2021, and you'll hear a lot more about that in our presentation this afternoon. That's going to allow us to really continue with our immediate focus of deleveraging and getting that net debt level down from $320 million, notwithstanding the fact that we still have significant liquidity headroom under those facilities. And as we mentioned, the year-end reserves position, over 270 million barrels, 18 years of reserve life, and low decline, which sets us up for material free cash flow generation over the next five years and a material contingent resource base in excess of 1.1 billion barrels of oil equivalent. And as I mentioned earlier in the presentation, very strong performance through 2020 on the ESG front with no material incidents to report and well on track with our five-year emissions reduction strategy.
So that concludes the Q4 and full year results presentation. We can take the opportunity now for anyone to ask questions.
Thank you. Ladies and gentlemen, we'll now begin the question and answer session. To ask a question, press star one on your telephone keypad and wait for your name to be announced. To cancel your request, press star two. Once again, star one if you have any questions. You have a first question. It's from the line of Teodor Sveen-Nilsen from SpareBank 1 Markets. Your line is now open.
Thank you. And good morning to Mike and Christophe, and thank you for the presentation. I'll try to stick my questions to Q4 quarter figures only as you ask for it. So two quick questions. First one on Q4 cash flow.
Is it right that there was some substantial working capital buildup during fourth quarter, and do you expect that to reverse into Q1? Second question directly on the impairment. I understand that's mainly driven by lower price deck and increased transportation costs, but I just wondered, have you also changed the discount rate? I just noticed that some other E&P companies, they actually increased discount rates for fourth quarter impairment testing. And then second question on impairment, what's the book value of the assets in France right now? Thank you.
Yeah. Thank you very much. So on the working cap, indeed, it's actually growing, which is good. We would like it to stay this way, that the changing working cap continues to increase. It essentially means that oil prices continue to increase and receivables continue to increase.
So everything being equal, since the current prices are significantly higher now than they are at the end of 2020, they would stay the same. That would continue to increase. In terms of the impairment in France, we've not changed. We increased our WACC and the discount rates from 8%-8.5% earlier in the year in 2020 when we revised our WACC essentially on the back of the initial impact on oil prices drop and increased risk overall. In terms of the so that was the question on the discount rate. And in terms of book value, the French assets are now around $100 million-$110 million if you combine the Paris Basin and Aquitaine.
Okay. Thank you. So I'll take my questions to you after capital markets , which I guess is more or less the strategy. Thank you.
Okay. Thanks, Teodor.
Once again, if you have any questions, please press star one. We do not have any questions coming in as of this moment. Please continue.
Okay. We've got one question from the web, which is, "Hi, your financial priority is debt repayment, but second priority dividends or M&A." And if you want to defer for this afternoon, Mike will answer that one.
Yeah. I think we'll defer to this afternoon, but right now, certainly for 2021, the absolute focus is free cash flow generation and debt reduction.
Yeah. Thanks very much. That's the only question from the web there. So we'll speak to everyone this afternoon Capital Markets Day at 2:00 P.M. So just a reminder, you can go to our website to dial in, and there's also dial-in numbers available on our press release or on our website. Thanks, everyone.
Thank you. Thank you.
Thank you very much.
Thank you. That concludes our call for today, and thank you all for participating. Have a good one.