Hello, and welcome to IPC's first quarter financial results. Throughout the call, all participants will be in a listen-only mode, and afterwards, there will be a question-and-answer session. Just to remind you, this conference call is being recorded. Today, I'm pleased to present Mike Nicholson, CEO. Please go ahead with your meeting.
Hello. Thank you, and a very good morning to everyone, and welcome to IPC's first quarter results and operations update presentation. My name is Mike Nicholson, the CEO. I'm also joined this morning by Christophe Nerguararian, the CFO, and Rebecca Gordon, who's our VP of Investor Relations. I'll begin in the usual fashion by taking you through the highlights and the operations update for the first quarter, and then I will pass across to Christophe, who will run through the financial numbers. And then, at the end of both of our presentations, there'll be a chance for those dialing in on the conference call to ask questions, and you can also send in your questions via the internet. So if we get started with the highlights for the first quarter, I want to start just by touching upon the macro position.
Clearly t hrough the first quarter, we witnessed the unprecedented twin challenges of the COVID-19 outbreak and the impact that that, of course, had on oil demand and the initial lack of response from the OPEC+ group. And if we look at what that means in terms of numbers, and I'm referring to the latest IEA numbers, global demand in the second quarter is expected to fall by around 23 million barrels a day, seeing slight improvement through June, but still down 15 million barrels a day. But even by the end of the year, we're seeing estimates of reduced demand compared to the previous year of down by 3 million barrels per day. So when you take that together, what that means in terms of the impact on full-year 2020 demand, you're looking at close to 9 million barrels per day reduction in demand.
Of course, in early April, we thankfully saw the welcome news that there was going to be some coordinated measures put in place by the OPEC+ group by all producers, including ourselves, and also governments, which we should start to see the market rebalance in the second half and as we move into 2021. In terms of the supply response, the announced cuts from OPEC+ are a reduction of around 10 million barrels a day in May and June, by 8 million barrels a day for the second half of 2020. Then right through 2021 and to the end of the first quarter of 2022, they're still looking at about 6 million barrels a day of production curtailments.
And when you add on to that the anticipated cuts from G20 nations, you're looking at further reductions through the end of this year of about five million barrels a day as people start to curtail their production. So I think such a profound and sharp shock, nothing really would have rebalanced markets quickly. And I think the actions and the coordinated actions that have been taken should see the markets move into a deficit position in terms of starting to draw down some of the inventory builds that we've seen in the first half through the second half. And that should hopefully start the process of market normalization. Again, if we look at the IEA's numbers, they were talking about a first half stock build of around 12 million barrels a day, but in the second half, looking at a drawdown of five million barrels a day.
So hopefully, we're starting to see some signs of a return to a more normalized market. But of course, that profound weakness that we've seen in oil prices as a result of that turns everyone's business on its head, and the market's essentially telling producers to cut costs, curtail production that doesn't make positive cash flow. And of course, the key in a situation like this is to maximize your liquidity headroom, and that's exactly what IPC has done. So I'll return now to our latest revised guidance. And what we're announcing this morning is we're actually tightening our expenditure cuts to the top end of the previously guided range. We're now looking at total expenditure reductions of between $175 and $190 million. CapEx and decommissioning costs have been reduced by $85 million, down to $77 million for the full year.
And we're tightening our production guidance to 30,000-37,000 barrels of oil equivalent per day as a result of the further optimization work that we've concluded since our last guidance on the 2nd of April. Our per barrel unit operating costs are unchanged at $12-$13 a barrel, but when you look at that in absolute terms, we've got the option to reduce our operating costs down by between $90 million-$105 million to $140 million-$155 million for the full year. Turning now to the liquidity side, our operating cash flow for the first quarter was just under $22 million.
That was below our original capital markets day forecast as a result of the weak pricing that we saw through the first quarter, and particularly later on in the first quarter, timed with some of our liftings in Malaysia and our payment mechanism in France, which Christophe will come back to later on in our presentation. But on the positive side, big working capital movements over $20 million, favorable exchange rates gave us a $20 million boost, which means that when you consider we had the bulk of our capital spend in the first quarter of $56 million, our net debt from the end of the year only increased marginally from $291 million to just over $302 million. And actually, if you'd excluded the share buyback, it would have been slightly lower.
Also, very pleased to report that we've managed to secure a new EUR 13 million unsecured credit facility, and so that will add to the liquidity position of the company. And on our other two key facilities on our international RBL discussions have commenced with international banks, and we're looking at extending the maturity of that facility and even potentially increasing that facility. And we're also pleased to see the announcement in April by the Canadian federal government that there's a program that's been put in place for the oil and gas sector to ensure that they can maintain access to existing liquidity lines, and that's going to be supported through some guarantees provided by the Export Development Canada. In terms of our hedging position, we did put in place some supplemental hedges.
We had some existing WTI hedges through the second quarter that finished at the end of the quarter. What we've done is we've added some incremental WTI hedges, and we've paired them up with some Western Canadian Select differential hedges. And taken together, what that means is that on our crude deliveries that we anticipate now through the second quarter, we've secured a minimum realized Canadian WCS dollar per barrel price of $16 per barrel. So I'll come back to where we're seeing prices for April and May, but certainly, that gives us price certainty as we move through one of the weakest quarterly expectations for Canadian prices. So when we look at the financial headroom now updated since our last announcement, that's increased with the new French facility to in excess of $100 million.
With the operational changes and the hedging position that we've put in place, we're now guiding that we need less than 40% of our existing financial headroom through the end of the year on our worst-case planning scenario, which is a $25 per barrel Brent oil price and a $0 WCS price for the remainder of 2020. On the business development side, we announced early in the quarter that we'd completed the acquisition of Granite that brought 14 million barrels of additional 2P reserves. I'm also pleased to report that we had no material incidents through the first quarter, and we also secured our carbon offset project that we talked about at our capital markets day back in February of this year.
Also very pleased to report that the COVID measures that we've put in place, so in terms of reducing staff numbers, health monitoring and screening, and ensuring that we don't have any contamination at any of our sites, we haven't had any interruptions at any of our operational sites as a result of the coronavirus. So good to see the fruits of those protective measures that we've put in place paying off there through the first quarter. So I'm turning now to the next slide, which just recaps on the last guidance that we gave to the market, which was in our April 2nd press release. We guided on the CapEx side that we were reducing by $85 million to $77 million, and we also guided on the operating cost side that we expected that to be reduced by between $125 and $190 million, by $40 million- $105 million.
So in total, between those CapEx and operating cost savings, that was giving us total expenditure reductions of between $125 and $190 million. That, in terms of production, assuming the largest cost reductions, so $105 million of OpEx reductions and $85 million of CapEx reductions, would have given us a low-end production guidance of 30,000 barrels of oil equivalent per day. And our high-end guidance of $45 assumed $40 million of operating cost cuts and minimum voluntary production curtailment. So that was really the basis of the assumptions of that original guidance. And when you feed that through into the liquidity headroom that we announced at the beginning of April, we had available liquidity headroom of around $90 million. And assuming forward prices for the last nine months of $25 Brent and $0 per barrel in Canada, we expected to use approximately 50% of that available liquidity headroom.
When we look at the work that we've done to further optimize the position of the company over the last month, as I mentioned in the introduction, we're now looking at total expenditure reductions of between $175 million-$190 million. The CapEx guidance hasn't been changed. That's still more than a 50% reduction in our CapEx of $85 million, down to now $77 million. We're tightening the reduction in our operating costs. We're reducing that now down by between $90 million-$105 million to absolute $140 million-$155 million for the full year. That's an approximate 40% reduction from our original capital markets day guidance. When you feed that through in terms of the new production numbers, our unit operating cost is unchanged at between $12-$13 per barrel.
If we look at the production numbers in a bit more detail, tightening that production range, so we're revising it today to 30,000-37,000 barrels of oil equivalent per day. That range is, of course, still going to be driven by forward-looking commodity prices and the operational choices that we're going to be making between now and the end of the year. At the upper end of that guidance, the 37,000 barrels of oil equivalent per day, that really assumes that the existing curtailments that we've implemented in Canada will continue through the second half of 2020. The lower end of the range assumes that Canadian prices stay at zero for the rest of the year, and we fully curtail our Canadian production. So that's really a plan for the worst, but be prepared to adjust if we see improving market conditions.
Of course, if we see markets continue to improve through the second half, we do have the flexibility to increase that production back above the top end of that guidance range should we see stronger pricing during the second half. So when we feed that through and look at the latest liquidity position, starting with the funding side, as I mentioned, we're very pleased to secure this additional EUR 13 million facility that we've put in place that complements our existing borrowing facility. This is a facility that's part of the financial assistance package that's been offered by the French government to deal with the coronavirus and provide additional financial support. Christophe will come back to it very attractive terms. Of course, what that means when you add that to our existing financial headroom, our available liquidity headroom now increases to in excess of $100 million.
Also, as I mentioned and touched upon in the highlights, we've been able to capitalize on the hedging position that we have in place through the second quarter, adding some additional WTI hedges, pairing those with some Western Canadian Select differential hedges. When you put that into context, the way Canadian crudes are priced, it's the average of the current month of WTI prices less the WCS differential for approximately the first two weeks' average of the previous month. If you look at what that would translate to in terms of actual April prices and current expectations of May prices, you'd be looking at around $4 per barrel WCS price for April and May.
So having those hedges in place and ensuring that we're going to realize a minimum of $16 per barrel for the second quarter puts us in as strong a position as we can possibly be in what we expect is going to be one of the weakest quarters. And of course, we did match our delivery obligations against those hedging volumes to give us certainty of that minimum pricing through the second quarter. So when we take all of those choices together, the operational optimization, the crude delivery volumes, and the hedges in place with the additional liquidity that we've put in place, we've increased our existing facilities to $104 million. And in an oil price scenario of $25 Brent and $0 WCS, we expect to now use less than 40% of that available liquidity headroom. So it puts IPC in a very strong position to weather the downturn.
Turning to the next slide, just touching upon the first quarter production and expectations going forward. If we look at the Q1 production, it was actually in line with our original capital markets day guidance. You can see the production through the first quarter. We had the Bertam A20 well. It came online during January. Late in the quarter, we did take the decision to suspend the sidetrack of the A15 well. We faced some operational challenges as a result of some tool failures. That meant our shales were exposed for longer than we wanted to do, which gave us some issues with running the completion equipment. But as a result of the weakness that we saw in commodity prices, we decided to suspend that sidetrack and come back at a later date to continue that activity.
Looking forward to production outlook, production curtailments in Canada, you could see late in March there. We did take very swift action, and we did already start to slow down our production late in March in Canada. And as we look forward, decisions will need to be taken, and these decisions will be taken on a month-to-month basis, particularly on Onion Lake Thermal. We're partially curtailed right now, and any decision on full curtailment will be based on that month-to-month look at forward pricing. In our production guidance numbers, we don't expect any curtailment on our Suffield gas because that's still generating positive cash flow, nor is there any assumption of production curtailment from our Bertam field. We do have some partial production curtailment on our Paris Basin asset as a result of refinery constraints. And again, those are built into our latest production guidance numbers.
Turning to our operating costs, our Q1 operating cost was slightly ahead of guidance at $12.50 per barrel. And as I've mentioned previously, OpEx reductions across all assets based upon the low oil price environment with the reduction range of between $90 million-$105 million, approximately 40% reduction from that original CMD guidance, which translates into reduced unit operating costs down to between $12-$13 per barrel compared with our original CMD guidance of just below $14 per barrel. And as I mentioned, we have got the flexibility to ramp that back up should we see an improvement in pricing through the second half of this year. In terms of our capital expenditure, total 2020 CapEx and decommissioning expenditure is now forecast at $77 million.
You can see from the chart on the top right-hand side of the slide, the majority of that CapEx has been spent, $56 million of that, during the first quarter, so really minimal CapEx remaining for the rest of 2020, and essentially, we've cancelled or deferred all forward-looking discretionary projects in all regions, and we've reduced our abandonment costs strictly to compliance spend only for the remainder of 2020, and the final slide, just an update on the ESG strategy that we presented back in our February capital markets day. IPC is committed to reducing our carbon footprint over the next five years down to the global average. We currently have an average of just over 30 kg of CO2 per BOE, and that five-year reduction target is to get us down to 20 kg per BOE.
number of operational initiatives already enacted that have seen us take about 150,000 tons of CO2 per year out of our business. We've started to commit to that carbon offsetting program. We've partnered with First Climate and are pleased to report that we've been able to secure 50,000 tons of CO2 reductions in the first quarter, which meets that full year 2020 commitment. That concludes my part of the presentation. I'll pass across to Christophe now, who will run through the financial numbers.
Thank you very much, Mike. Good morning to everyone. We're on slide 12 now. The production for the first quarter was at 46,000 barrels of oil equivalent per day, just shy of our initial guidance, and the reason why it was slightly below is partially the voluntary curtailment we made in Canada, as explained by Mike.
Then the average Brent price for the quarter stands at $50 per barrel on average for the quarter. But obviously, the quarter has been extremely volatile because the Brent started at above $65 at the beginning of the quarter, but ended at $15, was actually $15 on the 1st of April. And so that has had an impact, obviously, on our revenues as we were selling more towards the end of the quarter. I'll come back to that in my next slide. The OpEx were in line at $12.50 per BOE, as mentioned, and we are revising down our guidance for the year at between $12 and $13 per BOE, so improving our performance there on the back of the heavy cost-cutting exercise we've been through and that which Mike talked about.
The operating cash flow was weaker than expected, obviously, in our capital markets day purely as a result of a drop in revenues on the back of a drop in the oil prices across the globe, so the operating cash flow and EBITDA were reasonably just above and below $20 million, making our net result for the quarter negative $40 million, which was also mainly, not mainly, but we had a negative finance charge, which is non-cash resulting from the depreciation of the Canadian dollar against the U.S. dollar. I'll come back to that. Moving on to the next slide on realized prices, I think it's important to understand that we are selling our Malaysian cargoes when those cargoes are ready to be lifted, obviously, and so what happened in this quarter is that we had one cargo in Malaysia in February and two in March.
So, selling on the average of the Dated Brent price, one cargo in February, two in March. So on average, the reference Dated Brent for Malaysian cargo was actually $40 per barrel. And so when you look at the realized price of $48.90, we actually had very, very high premiums on our cargoes in Malaysia, just shy of $9 per barrel. But the reference Dated Brent was not $50 but $40. And almost the same story goes for France, where actually our sale formula is based on the forward months. So the production in France for January, February, and March was actually settled on the February, March, April average Dated Brent. And so over that February to April period, the average Dated Brent was $35.
So if you look at the realized price, actually, it was really, as usual, if not better for Malaysia and as usual for France, but translated into a much lower realized price overall, especially compared to the seemingly average Brent price for Q1. In Canada, the WTI was on average $4 below the Brent, and we experienced the differential between the WTI and the WCS of around $21. And it's worth mentioning that on the back of the current curtailment in Canada, one of the positives is that we see the cost of taking barrels from Alberta or from Western Canada to Gulf Coast or wherever it's needed to refineries is much less expensive. And so actually, we've seen a very welcome tightening of that differential below $10 lately.
On our gas prices, so the winter months, which is really from November to end of March in Canada, those winter months are usually very cold and as a result translate into a higher gas consumption, which itself translates into a higher gas price. The Q1 this year in North America was reasonably not so cold as it was last year, for instance, translating into reasonably soft gas prices. And we realized CAD 2.28 per MCF during that quarter. That this being said, on the back of the massive oil production curtailments that we can witness in North America, and especially in the U.S., all the associated gas usually produced with the shale oil production is no longer coming to the market.
So as a result, all the economists are very constructive on the gas price, especially for the second half of this year and even towards the later months of this summer strip. So we are quite constructive on gas prices going forward and expect a much stronger everything being equal, we expect a much stronger winter next winter, 2020 over 2021. In terms of operating cash flow and EBITDA, the story is fairly simple here. The revenues compared to the first quarter of 2019 were $60 million-$65 million lower this quarter, and that directly translates into lower operating cash flow and EBITDA. The only positive being, as Mike mentioned, that we benefit this quarter from positive working capital movement, change in working capital that is typically beneficial to our cash position. And I'll explain that after in a couple of slides.
In terms of operating costs, we've lowered and improved our guidance in the current challenging conditions that we are all aware of. We're guiding we had the operating cost per barrel of $12.50 per BOE this quarter, and we expect to remain within the range of $12-$13. We keep on investigating ways to actually further improve this OpEx per barrel for the full year. In terms of netback, another way to look at it is to look at our revenues and costs on the dollar per barrel basis, with revenues just shy of $20 per BOE for the first quarter and operating costs, as I just mentioned, of $12.50. We generated gross margin operating cash flow just above $5 per BOE and EBITDA of $4.50 per barrel, so much lower than the previous quarter.
Now, looking at the net debt reconciliation from the beginning towards the end of this quarter, it's interesting, I believe, to exclude two, I would call it exceptional items. So we closed the Granite Oil acquisition on the 5th of March, and the total consideration was roughly CAD 80 million, 50/50 between the equity portion of the transaction and the other CAD 40 million, which was the assumed part of the existing Granite Oil debt. And the other one was until roughly around from the beginning of the year until our capital markets day, we continued on our share purchase program. And so excluding those two elements or adding those two elements to the opening net debt this quarter, we had a net debt of $304.5 million U.S. dollars.
And so our net debt was flat during that quarter, excluding the Granite Oil acquisition and the share buyback program, which was the result of $20 million operating cash flow, $54 million development CapEx, but a positive effect on the FX given the comparative weakness of the Canadian dollar and, as just mentioned, by a positive change in working capital in excess of $23 million. So we always knew, and it was always the plan, that our first quarter would be the heaviest in terms of CapEx. We've obviously, as explained previously by Mike during this thorough cost-cutting exercise we embarked on, we've cut pretty much all remaining CapEx for the year, and you shouldn't expect to see that massive CapEx anymore in the next three quarters this year.
In terms of G&A and financial items, happy to report, as you'd expect, that the G&A are very much under control and are standing for less than $0.6, around $0.6 per BOE this quarter. In terms of financial income, just worth mentioning a couple of points there. Interest expenses have increased, as you'd expect, on the back of higher outstanding debt on the back of the Granite Oil acquisition and the flip side of being a modest decrease in our commitment fees as we're using a bit more of our credit facilities. The main charge here is actually a foreign exchange loss that is the result of some intra-group loans we have denominated in Canadian dollar, Canadian dollar having depreciated against our external debt in U.S. dollar. We're reporting here a loss of $22 million, which is absolutely non-cash and has no impact on taxes.
In terms of financial results on slide 20, so with 46,000 barrels of production this quarter, we had a cash margin of $21 million less depletion G&A and financial items, including this non-cash item that translated, as we reported before, into a negative result of $40 million . On the balance sheet, total assets remain flat or very close to stable at $1.35 billion . Oil and gas properties very stable at $1.1 billion . Interesting to note, as you'd expect, again, that the current assets decreased as a result of the lowest revenues we expect from March into April, and which also explains why we had a positive change in working capital because the revenues we cashed in in January, which were generated in December, were higher, and so the current assets were higher at the end of 2019 compared to the end of this quarter.
Flip side on the liability side, you can see the increase in financial liabilities, which is mainly the result of the fact that we're now assuming on the back of the Granite Oil acquisition, we're assuming the previous Granite debt. Really, this quarter or towards the end of the quarter and since pretty much the 9th of March on the back of the initial oil price war launched by Saudi Arabia and Russia and then the demand destruction resulting from the COVID-19 outbreak, IPC management has been focusing on really two items. First one was the optimization of our operations, which really meant curtailing production to adapt our business to the environment and to the oil price environment.
The second leg of our strategy was to actively engage with our credit providers to ensure that we always have enough access to liquidity to weather what we expect to be another challenging few quarters, even though we can see that the oil prices have rebounded a bit. And so as a result of engaging with our partners, our credit partners, we were quick to identify the French government-backed economic support plan, which was rolled out four weeks ago, which was announced four weeks ago. And so happy to report that we just entered into a € 13 million loan, which is unsecured, 90% guaranteed by the French state and which bears cost of only 0.5%. There are no fees, no other costs. So it's unsecured, makes all the banking partners comfortable, no fees, 0.5% cost per annum.
It's an initial 12-month facility, which can be extendable at our option for another five years. We were also actively engaged with our international banks for international RBL, which was not previously maximized, and so we've embarked on the process to refinance and extend the maturity of this loan with a view as well to improve the facility size, so that's pretty much work in progress. Also happy to report that in Canada, we obviously have good dialogue with our banking partners, and on the back of the recently announced federal plan support upstream companies, we've also had bilateral discussions with EDC, which is going to support commercial banks to ensure that upstream companies qualify for that plan. We'll keep on having very good access to liquidity, and based on our initial discussion with both commercial banks and the EDC, IPC totally qualifies for that plan.
So, both of the refinancing of the international RBL and the outcome of the redetermination of our Canadian RBL, together with the support from the EDC, we would expect to be able to report, at the latest, on both those points before the Q2 release in early August. So, that was really, on the finance side, a challenging quarter, but good progress on the liquidity. Actually, an improved situation even compared to only four weeks ago as a result of the active management and reshape of our business in only a few weeks. Thank you. And I hand back to Mike for the conclusion.
Yeah, thank you. Thank you very much, Christophe. And as Christophe just referred to, it's clearly been a very challenging time for the upstream oil and gas industry with a profound commodity price weakness that we've seen.
But I think what I've been most impressed about for IPC is that we do obviously operate all of our assets and we've got a huge degree of discretion and we have been able to swiftly react to the challenges and significantly reduce our expenditure levels. So cuts that we're announcing today down a total of $175 million-$190 million. We're tightening our production guidance range to 30,000-37,000 barrels of oil equivalent per day. We do have the flexibility to increase that. And some of the early signs that we're seeing, we're seeing Canadian crude prices today trading above $20 per barrel. So there is the potential opportunity to flex up from that point. Operating costs slightly down from our CMD guidance down to $12-$13 per barrel for the full year.
And as Christophe has mentioned, we've been able to improve the liquidity situation of the company from the last business plan update just over four weeks ago. The cash flows that we generated of just under $22 million have been able to fund our capital expenditure in the heaviest quarter, $56 million. And with the favorable working capital movement of $23 million, exchange rates of $20 million, have meant that our net debt has only increased from $290 million to just over $300 million. And as Christophe talked through, we've been successful in securing that very low-cost additional €13 million credit facility. In terms of the hedging program that we've got in place, that does give us certainty through what's expected to be a weak quarter of pricing, particularly in Canada.
On the production volumes that we're expected to deliver, we've secured a minimum realized WCS price of $16 per barrel. When you put those two together, financial headroom increasing to an excess of $100 million, the hedges in place, reducing our required liquidity through the remainder of the year means that now less than 40% of that existing financial headroom is expected to be utilized to fund the business plan for the remainder of the year. That's a big improvement from the last business plan update. That does assume the worst-case scenario of $25 Brent and zero Canadian prices for the remainder of the year. Completed a Granite acquisition early in the first quarter, an additional $14 million of long-life reserves coming into the portfolio. As I mentioned on the ESG side, no material incidents to report during the first quarter.
We've secured the carbon offsets to meet our 2020 reduction commitments. That concludes the presentation part. We can now turn across and open up for questions.
Thank you, ladies and gentlemen. If you do have any questions, it's zero one on your telephone keypad to register. Our first question comes from the line of Dave Brown from BMO. Please go ahead. Your line is now open.
Thanks. Sorry, I've got three questions. On Onion Lake, obviously, it feels like that's a bit of a swing factor for you guys this year. So would you be able to just elaborate on what a partial curtailment actually means in terms of both production, pads online, etc., and then just run through the specific challenges with shutting in that type of asset and how you model or manage those risks?
The second one, probably for Christophe, just in terms of OpEx, just really interested in how you're managing to maintain unit OpEx at $12-$13 a barrel, given there must be some elements of fixed costs that you're still incurring. And the third one is Malaysia. You've obviously mentioned the A15 well. Can you just cover performance from the other production wells there and perhaps where you're guiding full year production to? Thank you.
Okay, David, yeah, I'll take the first and the third question. So in terms of Onion Lake Thermal and the swing factors, so your production capacity was around 12,000 barrels a day. And that doesn't include the initial planned contributions from D-Prime, which has of course now been suspended. So where we're looking at as we move through the second quarter, we're looking at curtailing Onion Lake production by approximately 50%.
The high end of the guidance assumes that that curtailment level remains for the remainder of the second half of 2020. The low end down to the $30 per barrel full year range assumes that we would fully shut Onion Lake Thermal in. Now, in terms of the operational flexibility, of course, the best way in a thermal project to give yourself the quickest opportunity to respond and ramp production back up is to continue the steam cycling. What we're tending to do is to still steam cycle and just partially curtail production from all of those pads that gives us an opportunity to ramp up much more quickly. The third question, I think, was on Malaysia, A15. Yeah, I mean, it's been another very good performance in terms of the Bertam FPSO with a 99% production uptime again during the first quarter. So, excluding the fact that we don't have the production contribution from the A15 well, which in this low oil price environment can be seen as a blessing in disguise, we've seen production broadly in line with expectation.
Sorry, go ahead.
I was just going to follow up on the Malaysia. Obviously, you've had the operational issues. Is there a solution there or has the thinking there changed? Do you expect that there is a way to get A15 up on stream when prices make sense?
Yeah, I mean, typically, so the issue was when we drilled through the shale and we had some problem with tool reliability, which meant those shales were exposed for a longer period. So the plan when we go back would be, as we've done in other areas of the Bertam reservoir, would be to case off the shales before we drill the sidetracks . So that's the engineering solution to take that issue out going forward.
Okay.
On the OpEx side, obviously, a very good question, David. We were thinking of ourselves as lean and cheap operators, but we just discovered that we could be even leaner. And so what that means is that we've proportionally cut back more cost than viable because indeed you have a portion of fixed costs. By investigating deeper, we realized that some of those fixed costs could actually be taken out. And so there were also some elements of reported as OpEx, such as minor workovers or small work to improve productivity from wells. All of that activity has been taken out. So that was a combination of looking deeper into the way we operate and also a reduction in additional activity to maintain production.
And I guess we've also been able to reduce our contract staff significantly, which we're going to be involved in some of the workover and growth projects. So we can obviously set aside all of that contract staff, which removes a significant cost as well.
Okay. Partial unemployment in France, partial unemployment in Canada. We're using all the tricks. Got it. Got it. Cheers.
Thank you. Once again, ladies and gentlemen, for any questions, it's zero one on your telephone keypad. And we currently have no more questions registered, so I'll hand back to our speakers.
Okay, thanks. We do have three questions from the internet. So firstly, Mike, will it be possible to return production to 50,000 barrels a day with the current CapEx haircut? Can we think again in 50,000 barrels a day production if oil comes back to higher levels in the second half of 2021, for example?
Yeah, I mean, of course, the assets still have that production capacity in our reserve base. So the actions that we're taking today are not expected to have any impact in terms of our overall reserves position. So of course, is it possible for us to get back to 50,000 barrels a day? Yes, is the short answer. The question will be, where will oil prices be and how quickly do we want to ramp up our capital expenditure? And is it prudent to do that? So it's going to be a balancing decision as to how much capital we want to allocate and how quickly we want to ramp back up to those levels.
Okay, thanks, Mike. Christophe, there's a question on the curtailment strategy for IPC. Is there any effect on Malaysian operations and are we still receiving revenue on the Malaysia side?
Yeah, no, absolutely. We continue to produce and sell our barrels, so no particular incidents on that front. We're expecting to sell less cargoes in the second quarter, which is actually a blessing given where oil prices stand, so with a bit of oil price rebound in Q4, overall, we should achieve between Q2 and Q3 a better average towards the later quarter, so obviously, second quarter will be challenging again, but we believe we're well positioned, and as Mike just mentioned, the performance on our Malaysian assets continues to be very, very good.
And just to clarify, would we still be able to rent the FPSO while shutting in Malaysian operations? Yes. On a ship, yeah?
Yes, yeah. That's a contractual obligation, correct. Yeah.
Yep. Mike, a question on the Blackrod pilot. Is your intention to continue this pilot as planned and what is the status at the moment?
So the pilot has been suspended as we speak. So we still plan to maintain a minimum level of heat going into the pilot well, but we don't plan to produce it until we see prices recover. Yep. And one final question that's just come through on pipeline development in Canada. How do you see the projects being impacted by the current crisis? I think if we look at the announcements that we've seen through the first quarter, directionally, it's been positive. We've seen on the Trans Mountain Pipeline that construction has started. About half of the 50 km section outside Edmonton has already been completed. And work on the additional storage tanks in Burnaby on the west coast has also started. So the latest update from the company is that they expect all sections of the pipeline to be under construction by the end of this year.
I haven't seen any changes to the planned construction completion towards the end of 2022. I think when you look at the Keystone XL project, it was obviously very positive during the first quarter to see TC Energy take the final investment decision in that project and also to see that the Alberta government was committing over $1 billion in equity investment to fund the project through 2020. There has been some challenges with respect to construction around the waterways, but construction is planned to commence on that pipeline. So again, directionally, there's been a positive there. The latest update on the Enbridge Line 3 replacement, the last couple of challenges have been overturned. I think there's two remaining permits that are required from the Department of Natural Resources and the Army Corps of Engineers.
And the latest update from the company was that they expect to get those permits around June, July. And it takes six to eight months to complete the remaining section. The only section that needs to be completed is through Minnesota. So we could be looking potentially at an in-service date late 2020 and into 2021. But I haven't seen any material updates as a result of coronavirus if there's been impacted schedule delays.
Okay. Thanks, Mike. That's the end of the web questions and also the phone questions.
Okay. I'd like to thank everyone for tuning in. Clearly, it's been a tough quarter, but I think we've taken the firm actions to reset our business plan, put the company on a very strong financial footing to get through the crisis. We look forward to markets rebalancing and starting to look forward to resetting our growth plans as we move ahead. Thank you very much, everyone, for tuning in.
Thank you. Have a nice day. Stay safe.
This now concludes our conference. Thank you all for attending, and you may now disconnect.