International Petroleum Corporation (IPCO) Earnings Call Transcript & Summary

Welcome to IPC's Third Quarter Financial Results 2020. [Operator Instructions] Just to remind you, this conference call is being recorded. I'll now hand the floor to our speakers.

Thank you, and a very good morning to everyone, and welcome to IPC's third quarter results and operations update presentation. My name is Mike Nicholson. I'm the CEO. Also joined this morning by Christophe Nerguararian, the CFO; and Rebecca Gordon, who is our VP of Corporate Planning and Investor Relations. I'll plan to start in the usual format by walking you through the operational results for the third quarter. I'll then pass across to Christophe. He'll take you through the detailed financial numbers for the third quarter and the year-to-date. And then we'll return, and participants joining on the conference call will have the opportunity to ask questions. So to begin with the highlights for the third quarter of 2020. I'd like to start by saying, obviously, the third quarter was much better than the market lows that we saw during the second quarter of 2020. And really one of the largest single factors driving the improvement was the production curtailment announcements by OPEC+ and other producers. And that really saw the market, as we moved into the third quarter, move into a position of deficit. And we saw the stock levels drawing down as the market rebalancing process started. And of course, that fed through into more favorable commodity prices. Absolute Brent prices were up from the lows of $30 a barrel that we saw during the second quarter to slightly over $40 per barrel during the third quarter. And Christophe will talk about Canadian realizations, but we did see improved Canadian differentials as we moved into the third quarter. So if we turn now to the IPC highlights, Q3 average net production was just under 42,000 barrels of oil equivalent per day. That was better than we had expected, and it was really driven by a strong performance with faster-than-forecast ramp-up, predominantly at our 2 core assets in Canada. And as a result of that strong third quarter performance, we're now revising upwards our full year guidance above the upper end of our previous guidance range to in excess of 41,000 barrels of oil equivalent per day. Also, good performance on the cost side. Q2 operating costs per BOE were $12.40. Putting that together with the first half, that gives us a year-to-date operating costs per BOE of $12 per barrel. So we're now expecting for our full year numbers to be towards the lower end of our previous guidance range of $12 to $13 per BOE. No change to the CapEx guidance, $80 million still expected for the full year. And what we've really seen with that stronger production in oil price environment is a significant improvement in overall liquidity of the company. You'll recall that during the second quarter, we announced that we had refinanced both our international and Canadian RBL facilities, and we'd also put in place a very low-cost unsecured French facility. During the third quarter, we generated $37 million of operating cash flow. And more importantly, given the significant expenditure reductions, we've moved from a cash flow neutrality position during the second quarter to generating $23 million of free cash flow during the third quarter. And when you take the market cap that we had at the end of September of around $280 million, that represents a free cash flow yield of in excess of 8% in the third quarter. The cash flow generation was used to reduce our debt levels predominantly. We saw net debt fall from $341 million at the end of the second quarter to $322 million by the end of September. And that means that the previously guided financial headroom that we'd originally expected by the end of the year of in excess of USD 100 million was actually achieved already by the end of the third quarter. On the ESG side, pleased to report no material incidents. We continue to be very diligent with respect to the COVID protection measures and the enhanced screening that we have, all of our operational sites. No impact on any of our operations as a result of the coronavirus during the third quarter. And we have previously mentioned that we had secured the 2020 portion of the carbon offsetting projects that we've committed as part of our 5-year commitment. I'm very pleased to announce this morning that in parallel with the publication of our third quarter results that we had, for the first time, published IPC's first sustainability report, amongst a number of other measures. I'll come back to that. That reaffirms our commitment to reducing our greenhouse gas emissions intensity to the global average by 2025. And I'll come back to put some more details around that later on in the presentation. So now if we walk through some of the individual items in a little bit more detail and we start with our production. As I mentioned, third quarter production was above forecast at just under 42,000 barrels of oil equivalent per day. You'll recall that we did mention during the third quarter that we had started the progressive ramp-up of the production that have been curtailed in Canada, predominantly our Suffield oil and our Onion Lake Thermal assets. You'll see that in early July, we did take 2 shutdowns on 2 of our biggest facilities: the Onion Lake Thermal facility and our offshore Bertam FPSO. Very good execution by both our teams in Malaysia and in Canada on those turnarounds. And as you look at the chart on the right-hand side, you can see really strong and steady, progressive recovery on our production through late July and into the rest of the third quarter. In Canada, good performance and faster-than-forecast ramp-up at Suffield and Onion Lake Thermal, very steady performance from our Suffield gas asset. And on the international side, following the FPSO turnaround, we were still able to sustain uptime performance of 100% during the third quarter if we exclude the planned shutdown, which was really a phenomenal performance by our team in Malaysia. And you'll see a very steady performance across all of our producing assets in our French business. So what does that mean in terms of the progression of our guidance through the year? I did mention on the summary slide that we are increasing our full year guidance. The last guidance that we gave was during our second quarter presentation. That was 37,000 to 40,000 barrels of oil equivalent per day. Year-to-date production, so for the first 9 months, was actually in excess of 41,000 barrels of oil equivalent per day. And as you can see from the chart on the previous slide, we are today producing at levels in excess of that. So we now anticipate that our full year 2020 average production will be slightly above 41,000 barrels of oil equivalent per day. On the cost side, no change to the guidance that we gave during the second quarter. Of course, we did announce a dramatic reduction in our original February guidance. In our Capital Markets Day, we'd forecast a capital budget of in excess of $160 million. We've always stated that we are in the fortunate position that we operate all of our assets, which, of course, means that we do have a very high degree of discretion and we have the ability to move very swiftly and either decelerate or accelerate our investment program. But given the uncertainties with respect to the second wave of the pandemic, we feel it's still very important to take a cautious approach with respect to our capital rationing. So we don't expect to change our expenditure forecast for the remainder of this year, and we're retaining that 50% reduction to $80 million for the full year on the CapEx and decommissioning side. In terms of our OpEx, continued delivery on the OpEx reduction program. Our low pricing strategy is still maintained in all regions. We still have a number of our wells that are shut in are higher marginal cost wells. Major assets, the Suffield and Onion Lake Thermal are now recovering, and we'll see when we go into the individual asset slides that we're getting back up to pre-curtailment rates on those assets. And as a result of that, with our first 9 months, average operating costs per barrel were $11.90 per BOE. We, of course, now expect a bias towards the bottom end of our full year operating cost guidance forecast of $12 to $13 per BOE. Turning a little bit more detail on the liquidity position. Of course, we're very pleased during the second quarter to be able to announce that we have increased our international reserve-based lending facility to USD 140 million and extend the maturity of that facility out to December 2024. Likewise, we refinanced the Canadian facility, and that stands at CAD 350 million. And again, the maturity of that facility was extended out to May 2022. And the leverage covenant was removed from the Canadian facility as part of that refinancing. We were also able to put in place a very low-cost, unsecured facility that was provided by the French government, EUR 13 million, and all-in cost is around 0.5% for that facility. So net-net, we were able to add about USD 10 million to our financial headroom following all of those refinancings. And what we had guided in the second quarter results presentation is that assuming a $35 per barrel oil price for the remainder of the year and a $22 per barrel WCS price, we expected our financial headroom to increase in excess of $100 million by the end of 2020. Given the strong ramp-up in production and the fact that oil prices have been higher than those forecasts that were presented, we're now extremely pleased to report that we've accelerated achieving that target by 3 months and have now available in excess of USD 100 million of available liquidity headroom. And of course, we do expect on the current forward prices at these production levels to be free cash flow positive during the fourth quarter. If we turn now and spend a few moments just on each of the individual key assets, and we start with our Suffield property in Southeastern Alberta. If you look at the chart on the bottom left-hand side of the slide, this is our Suffield gas production. I think what's very noticeable there is the very, very steady, low decline across the year. We've still been able to be very active with respect to our swabbing campaign and really managed to offset any natural declines as a result of that robust swabbing program. If you look on the chart on the bottom right-hand side of the slide, you can see the dramatic and swift action that we took during the second quarter when we saw Canadian crude prices collapsing. But I think what's just as robust is the recovery on the other side and how quickly we ramp back up to pre-curtailment rates. And one of the things that has helped us get back up so quickly has been the really good performance on our end-to-end enhanced oil recovery project that we started last year. We're starting to see some really good well productivities, which means that notwithstanding the fact that we did take a pause in the chemical injections during the low oil price period, our ramp-up of N2N is actually still running ahead of those pre-curtailment forecasts. So that stands us in good stead as we look forward to the months ahead. Our remaining 2020 development activity is still on hold. We had originally planned a 20-well development well campaign on our Suffield oil assets. We drilled 6 wells during the first quarter, but we don't expect to continue any more drilling activity through the remainder of 2020. We have still been working on maturing additional targets for 2021 to support an organic growth program. But I think given the uncertainties, it's too early to see whether we're likely to restart that program as we move into 2021. I think we're likely to take a more cautious approach to capital budgeting for next year as well. Turning to our Onion Lake Thermal property. If you look at the chart, it's a similar story to that, that we saw for the Suffield oil, very swift action taken in the second quarter to reduce production. What we did was we actually shut in one train, effectively 6,000 barrels a day of capacity, but we continue to inject steam with the objective of maintaining pressure and temperature across all of the individual well pads that you can see that produce our Onion Like Thermal. You see the map on the right-hand side there. And really, the objective there was to ensure that we would have good and fast recovery back to pre-curtailment levels. And if you look at the chart on the bottom of the slide, you can see that we've managed successfully to ramp production back up through the third quarter to pre-curtailment rates in the 10,000 to 11,000 barrels per day range. Pleased to report that we did complete the last of the drilling of our D-prime activity. The bulk of the drilling was completed during the first quarter. And through 2020, we've completed a total of 5 producers and 14 steam injectors, and the plan will be that in -- towards the end of the second quarter next year, likely to tie in those -- this well pad and start to ramp production up. And that has the ability to add up to 2,000 barrels a day of incremental production capacity through the second half of 2021. If we look on our Malaysian Bertam field now, again, we've had very high facility uptime, 100%, if we exclude the planned maintenance shutdown, strong base well performance, which has been slightly lower than forecasted declines. We did take the decision at the end of the first quarter to suspend the sidetrack operations on our A15 well. You can see the A15 potential that's shut in, and what we expect is to conduct that sidetrack activity during 2021. The team in Malaysia are still busy maturing additional organic growth opportunities in the Malaysian field. We're still looking in that A15, A20 northeastern part of the field to determine if there are any incremental infill drilling opportunities. And a lot of work's been done in looking at pump optimizations, and we may well put in place a program to start to replace some pumps in the main part of the field to see if we can drive liquids production rates slightly higher. So overall, a very good performance from the Bertam field during the third quarter. Turning now to France. We did have -- during the second quarter, we did have to curtail production as a result of the coronavirus outbreak in the Total-operated Grandpuits refinery. You can see that, that refinery is back up and running, and we've recovered production levels back to pre-curtailment rates in excess of 3,000 barrels of oil per day. All development activity remains on hold. In France, we did originally have in our 2020 capital budget plans to complete 3 wells on the western flank of our Villeperdue field, but that's suspended pending a recovery in oil prices. Total did announce during the third quarter that they planned to discontinue crude oil refinery at their Grandpuits facility starting in the first quarter of 2021. We do have a contract in place with Total for a Grandpuits offtake through to the end of 2021, so there will be any impact on 2021 operations. And what the team is busy doing, working in combination with Vermilion, who also produced in the Paris basin, and Total is to review the medium- and long-term offtake arrangements to optimize those. So that's looking at trucking, it's looking at barge operations and the potential for rail export to put in place long-term solutions as we come into 2022 and beyond. And finally, as I mentioned on the first slide with respect to IPC's sustainability strategy, since we spun the company out from Lundin Energy now back in 2017, integration of all ESG aspects has always been extremely important, and we've incorporated that into our governance framework and all of our business activities. And this quarter, we've now really seen a step change in IPC's nonfinancial disclosure with the publication of our first sustainability report, which is in line with the Global Reporting Initiative Standards. And really, the idea is this is our first report, but it's going to establish a baseline for us to give annual updates on our progress as we move forward, and we'll be reporting on the material issues such as environment, social and governance. And as a result, to show our commitment, we also joined the United Nations Global Compact during the third quarter. This is one of the largest corporate sustainability initiatives that was set up by Kofi Annan, and it celebrated its 20th anniversary this year. So we're very pleased to be a participant company now to the UN Global Compact. As we first launched back in our February Capital Markets Day, IPC put in place a commitment and a strategy to lower our net emissions intensity to the global industry average of 20 kilograms of CO2 per BOE by 2025, which represents a 50% reduction in our 2019 levels. And our plans are really to achieve that through reductions in our operating emissions, also with carbon offsetting. I'm very pleased that we've formed and established a partnership with First Climate. They've been operating in this field for in excess of 20 years, and we have secured our 2020 offset credits as part of that 5-year commitment and journey. So it's a very good report. There's a lot of good work has gone into that, and I would encourage people to read the report to see really the good work that is going on within the company. So that concludes my part of the presentation. I'd like now to pass across to Christophe, and he will take you through the financial results. So over to you, Christophe.

Yes. Thank you very much, Mike. Good morning to everyone. So as Mike mentioned, for the financial highlights, this quarter was actually the best quarter for 2020. Obviously, 2020 has been a challenging year, but in that challenging year, this third quarter is by far the -- has generated the best financial performance. We've seen, as mentioned, a strong ramp-up on our Canadian oil production. And that has allowed us to produce just shy of 42,000 barrels of oil equivalent per day during the third quarter, making the average production for the first 9 months in excess of 41,000 barrels equivalent per day, which is now where we are re-guiding our full year average production performance. So best quarter in 2020. The costs in parallel to a strong production. Our costs remained under control at $12 for the first 9 months, $12.40 per BOE for this quarter. And so on the back of the performance for the first 3 quarters, we're comfortable in guiding that our average operating costs for the full year will be at the low end of the range we previously guided, from USD 12 to USD 13 per barrel of oil equivalent. On operating cash flow and EBITDA, respectively, at $37 million, $34 million. Actually, represent more than 50% of the OCF and EBITDA for the first 9 months. So indeed, a good quarter. That good quarter not only was supported by this ramp-up in production but also by stronger oil prices. And even though the Brent was only USD 43 per barrel this quarter, we enjoyed in Canada a fairly tight WTI WCS differential, which really supported strong realized prices in Canada. The WCS was twice as high in this quarter as it was in the second quarter at USD 32 per barrel versus USD 17 -- lower than USD 17 in the second quarter. And more importantly, realized prices for our 2 largest oil assets in Canada, Suffield and Onion Lake, were more than twice as high than the second quarter, explaining why that performance was really helped by this tight differential in the third quarter. It's worth mentioning on that front that at Onion Lake, we used to sell oil as we were producing it, I mean, before any blending. And so we were receiving USD 6 to USD 8 per barrel discounts because of the quality because it was heavier than the WCS. Now we -- in this quarter, we've started to actually ship some of our Onion Lake Thermal oil production directly into pipe where we enjoy a much better netback this quarter. So we are buying from condensate blend before we ship this oil onto the pipe, and the result is that we are getting a much better netback. So you will be able to see from this third quarter increased revenues but also increased production costs as a result of the fact that we are blending more condensates into our oil to sell it at the WCS. So you can see on this realized oil prices, Slide 14, that Onion Lake realized price was just $3 below the WCS, much better than the $7 discount achieved in the first and second quarter. In France and Malaysia, happy to report that the discounts of premium are normalizing, and we expect the discount in France to further normalize at closer to the historical levels of around minus $1 to the Brent in the fourth quarter. In terms of gas prices on Slide 15, it is pretty clear now when you look at the graph at the bottom of that slide that there is virtually no more -- in the spot market at least, there is virtually no more premium or differential between Empress and AECO, but AECO is much, much stronger. And so that's the first point. And we expect that situation to stay as is for the foreseeable future. What is more important actually is that gas prices have become much stronger. It's not yet apparent in the realized price -- gas price for the third quarter, but you can see the bottom of the graph that gas prices have moved in excess of CAD 3 per Mcf. And it is actually very much the case right now with October pricing at above CAD 3.30 per Mcf. Going forward -- and that will be one of the slides further down this presentation, but we've hedged and/or sold forward some of our gas production, securing already for 2021 realized prices -- gas prices in excess of CAD 3 per Mcf. So very positive development and good support from gas prices. On the -- if you compare our financial results, despite the fact that we've had a very good quarter for 2020, if you look at the year-to-date performance on operating cash flow, EBITDA, we've only generated 1/3 or not even 1/3 of the 2019 performance. And that is really a result of the lower Brent -- combination of lower Brent prices, lower WCS prices and the lower -- 10% lower production. So we hope to continue to see the market and the oil prices recover. We are hopeful that the differential -- WCS differential is going to remain tight given that, overall, the Canadian production is lower than it used to be, making some more aggress export capacity available to us and other Canadian producers. Operating costs have remained under control. It looks easy when you look at a slide like this, but actually, it took our teams lots of effort and creativity to reduce the cost base because some of our cost base is actually fixed cost. But despite that obvious challenge, we were able to lower generally the cost base and on the dollar per barrel, maintain low operating costs at USD 12 per BOE. And we expect -- as Mike mentioned, we've revised our full year guidance to the low end of our initial guidance at USD 12 per BOE for the full year. In terms of netback, again, you can see that the third quarter was much better than the previous quarters. It was close to USD 10 per BOE for cash margin or for operating cash flow. EBITDA would be just shy of that number at almost USD 9.5 per BOE. And you can see that this third quarter performance was actually 50% higher than our year-to-date netback performance, still unfortunately short of what we obviously realized in 2019. In this third quarter, IPC, the group, was able to generate USD 23 million of free cash flow, which were entirely directed at reducing our debt. The debt reduced from USD 341 million at the end of June down to EUR 322 million at the end of this quarter. And you can see that the operating cash flow covered all of the development CapEx, which was decided and executed in the first quarter before we were able to actually stop actually any and no development CapEx. But overall, the debt still has increased since the beginning of this year. The jury is obviously out on whether the fourth quarter oil prices will be at the same level on average as the third quarter or lower, but everything being equal, we still provided we're going to generate free cash flow in this fourth quarter. We would intend to further reduce our net debt and the deleveraging of our balance sheet going forward. In terms of G&A, same story as the OpEx per barrel, they remain under control. G&A, as a whole, remain below $1 per barrel of oil equivalent. And if you look at the financial items, you can see that the finance costs have increased. And if you would compare it to the previous quarters, and you can expect a marginal increase further into '21 of financial costs as a result of the increased funding costs on the back of the refinancing of our main facilities we're negotiating during this summer. But it's -- the refinancing of our credit facility was a very strong point, and our ability to extend maturity was a big positive in June and July. So looking at the diagram of our financial results, as we've shown and discussed already, just as a look back, the cash margin was positive at USD 73 million. Unfortunately, with the depletion and some exploration costs, G&A and financial items, both our gross profit and net profit was negative year-to-date. We obviously hope that the annual results will be more closer to 0 or positive. But obviously, we will tend, as I say, to -- and will direct any free cash flow during the fourth quarter to further debt reduction. On the balance sheet, the overall size of the balance sheet has remained almost constant. On the asset side, you can see oil and gas properties actually flat, which is the result of the Granite acquisition in Canada earlier this year, less than the 9 months depletion, which left our oil and gas properties value virtually the same. Current assets have gone down as a result of lower production and lower oil and gas prices compared to the end of last year. On the liability side of the balance sheet, the increased -- the acquisition of Granite resulted in higher financial debt, increased -- as you can see on the balance sheet. But as I said, we've already reduced the debt between the end of June and the end of September, and we'll continue to do so between now and the end of the year. The current liabilities have increased, but actually, it is because the short -- some short-term debt has been accounted for here. That should be moved back into long-term liability once we've refinanced and extended our last small credit facility, which we inherited from Granite acquisition. I will not go into each and every line for hedging portfolio. But it's important to say that 1/3 of our oil and gas production in Canada is hedged between now and the end of June. And as I said, we've hedged in excess of 40% of our gas production, looking ahead into 2021, until October 2021, at very decent prices indeed, which, on average, should secure us almost CAD 3 per Mcf. So very good -- very supportive gas prices. And hopefully, we'll see that the diff -- as I mentioned before, the WTI WCS diff on the back of a reduced Western Canadian oil production will remain tight going into 2021. Thank you for that, and I'll hand back the microphone to Mike for the conclusion.

Thank you very much, Christophe. So yes, just to close off with the Q3 highlights. Clearly, second quarter was a very challenging time, and we had to take some really swift action to completely reset our business plan and turn it on its head and significantly cut costs, CapEx and OpEx, curtail higher-margin barrel production. And in the second quarter, we were obviously free cash flow neutral. And as we took the decision coming into the third quarter to start to ramp up production, we've seen very strong recovery in that production performance, just under 42,000 barrels of oil equivalent per day for the third quarter. And as we touched upon during the presentation, we've seen a really good performance from our key assets that were curtailed, particularly our oil production assets in Canada. As a result of that, we're now revising up our production guidance above the top end of our previously guided range to now in excess of 41,000 barrels of oil equivalent per day. Good delivery on our operating cost performance for the first 9 months. We're running at just under $12 a barrel, which means we're in great shape to achieve the lower end of the guidance that we gave as part of our reset business plan at $12 to $13 per barrel for the full year. CapEx reduction plans remain on track, cut by 50%. So we expect $80 million for the full year. And as Christophe went through in more detail in his presentation, really strong cash flow generation, $37 million of operating cash flow, $23 million of free cash flow, representing an 8% yield. And we've been able to apply that to debt reduction and the debt levels fall now to $322 million, which puts us in a very comfortable position of having in excess of $100 million of spare financial headroom at the end of the third quarter. And a very proud day for us all as well to be publishing our first sustainability report. A lot of good material. I'd encourage everyone to read that, and you can see again our reaffirmed commitment to reduce our greenhouse gas emissions intensity to the global average of 20 kilograms per BOE by the end of 2025. So that concludes the presentation part. If we can now turn back to the moderator, and of course, we can open up and have the opportunity to answer any questions.

[Operator Instructions] Our first question comes from the line of David Round from BMO Capital Markets.

I've just got a couple, please. Firstly, at Onion Lake, I'm just trying to understand the ramp-up there. I might be splitting hairs a bit, but it looks like you're still maybe about 1,000 barrels a day shy of where you exited 2019. So is there further ramp-up from the current well stock? And you mentioned 2,000 barrels a day from D-prime next year. Could you just remind us about capacity and potential debottlenecking there next year or potentially next year, but -- potentially after that? And secondly, I can probably guess the answer, but I've got to ask. Just around France and whether you can give us any early sense of costs associated with the new offtake routes or if you're just happy that Vermilion number is a reasonable place to start at this point.

Yes. Thanks very much, David. So let me start with the Onion Lake Thermal question. No, you're right. I mean when you look at the averages, we've been just above 10,000 barrels a day in September and October. We, of course, have seen -- on a given day, we've had production back up in excess of 11,000, and it just depends if there's any well downtime that starts to impact whether we were in that kind of 10,000 to 11,000 barrels a day production range. Looking forward, as I mentioned, we plan to tie in D-prime, which can add additional well capacity of another 2,000 barrels a day, and that's likely to be ramping up on stream through the second half of next year. We did do and invested in last year in some additional facility debottlenecking. So the original Phase 1 and Phase 2 projects had 12,000 barrels a day of facility capacity. And as a result of adding some additional steam generation capacity in 2019, our overall facility capacity is now 14,000 barrels a day. So we can accommodate the ramp-up of D-prime through 2021 without any additional facility increases. Coming back on your Total Grandpuits refineries, it's going to be too early to give us any firm guidance. Our -- and our contract is slightly -- must be slightly different for Vermilion's. Total are obliged still to receive all of our crude through 2021 at the Grandpuits refinery. So we don't anticipate any cost increases during 2021. And as we look to estimate longer-term costs, it's, of course, going to -- it's going to be balanced by any incremental costs on barges or rail or trucking. But our Paris Basin crude is actually in line with Brent quality. And we've had this long-term contract with Total at Grandpuits where we sell our crude at a discount to $1.50 per barrel. Now, of course, the theoretical value of that crude is higher than a $1.50. So we're able to change the delivery point that can obviously offset any impact of marginally higher transportation costs. So it's too early for us to give any firm numbers, but the teams, as I mentioned, are very actively engaged in and put it in place medium- and long-term alternatives for that offtake.

Okay. That's helpful. Can I just come back just quickly on Onion Lake? You mentioned sort of well downtime. Is that normal business? Or have you seen that sort of downtime increase post the shut-ins earlier this year?

No, we haven't seen any material change in well downtime, David. I mean you look there, we have a total of 6 -- or 5 pads today, but 6-well pads with the drilling completed. So it's just natural. We always have -- as we always factor in all of our assets, a certain amount of production downtime as we do well workover. So I haven't seen any material step-up in well downtime relative to historical levels.

Our next question comes from the line of Teodor Nilsen from SB1 Markets.

Three questions, if I may. First, on 2021 production, it looks like your fourth quarter production now will be around 41,000 barrels per day based on your new full year guidance. But as far as I understood, you won't drill anymore in fourth quarter. So should we expect some decline going into 2021? Or any comments around 2021 production would be very useful. And secondly, exciting to see that you're launching a new target for CO2 emissions by 2025. Could you be some more specific around how [ reach ] that target of 20 kilos? And then my final question is just on leverage. Christophe, you said that you were deleveraging the company. Could you just provide some idea what kind of gearing ratios you're looking for?

Okay. Thanks, Teodor. I'll take the first 2 questions, and then Christophe can answer your last question. So I mean it's obviously too early for us to give any firm guidance on 2021 production because we still have to go through all of our final budget discussions through December and January. But you're right, 2021, let's say around -- you mentioned in the low 40s, and we haven't got any additional drilling activity through the fourth quarter. So it's reasonable to assume that there's going to be a certain level of natural decline. And the 2 big -- the most likely the 2 big moving parts that will start to add production capacity, we'll be bringing back on the A15 well, which is likely to take place in the second half of 2021, and the D-prime production ramp-ups. We will have -- in a more conservatively budgeting scenario for next year, still have some incremental production capacity coming on in 2021. On your second question with respect to CO2s, as I say, it's going to be a combination of looking for further operational efficiencies and then bridging that gap with voluntary carbon offsetting. And if you look at the kinds of things that we've done operationally in Malaysia, we invested in dual-fuel power generation to provide the electricity to run all of our ESPs. And what that meant is we could capture the flash gas that comes off the separation and use that to generate electricity as opposed to flaring that gas. In our Onion Lake Thermal project, there's been significant investment in heat recovery units that, again, reduced the need for us to buy gas to generate steam. And between those 2 initiatives alone, we removed about 150,000 tons of CO2 from our emissions. Now I'm not saying we're going to be able to continue to deliver that year-on-year, but we'll be challenging our businesses to obviously increase the efficiency of all of our facilities. In terms of carbon offsetting, the first project that we've partnered with First Climate in -- for 2020 relates to acquiring carbon offsets that are generated from 2 power plants and solar power plants in the Punjab region in Northern India, supplies clean energy for around 200,000 people. And of course, with the power generation mix in India being 70% coal fire generated if these solar projects can move forward, and that clearly crowds out significant emissions. So any gap we would plan to bridge with carbon offsetting between now and end of 2025. Christophe?

Yes. On the gearing ratio, we don't have a gearing ratio target per se. What we recognize is that we've increased the leverage of our balance sheet in the course of 2020 with, for obvious reasons, initially an acquisition and then poor prices in the second quarter. As you've seen in the third quarter, we have directed a lot of our free cash flow to reducing the debt. We're going to continue on doing the same in Q4. We've soft guided that we expect a reasonably low CapEx budget in 2021. It's too early to disclose more, but directionally, we wouldn't qualify 2021 as a heavy CapEx budget given the current uncertainty. And so we're going to continue to deleverage the balance sheet. Again, a bit too early to tell, but we should have a net debt-to-EBITDA ratio just above 3x by the end of this year. And so we would definitely like to bring that below 3x in the course of 2021.

[Operator Instructions] Our next question comes from Mark Wilson from Jefferies.

Another solid presentation. Certainly, you can generate free cash flow. You just commented then about the net debt to EBITDA, you want to get that down, which makes sense. But I'd just like to get some comments on the market environment for further M&A from here. Do you think that further bolt-ons in Canada given the commitment to reducing carbon would not be the area you're looking at? And I'm wondering if we might expect any international developments in the coming year, particularly I've seen Petronas with comments regarding their asset disposals possibly. Where do you think we'd be looking, if at all, for future bolt-ons?

Yes, thank you very much, Mark, for the question. And I think our position with respect to M&A, I would say, is unchanged since the spin-off. We've never wanted to put ourselves in a geographical box and rule out any particular areas. It's always going to be a value-based decision, and it always starts with the quality of the subsurface and where we can see long-term upside from those assets. So we continue to very actively look at assets in Canada and look at assets internationally. And of course, if we make acquisitions, we'll have to evolve our missions intensity strategy and factor those costs into any acquisitions. I think it's -- given where oil prices are, though, I think, certainly, there's -- there does seem to be quite a big differential, particularly in the asset market with respect to where sellers' expectations are, where companies are currently trading at significant discounts to the fair value of their assets. So of course, it certainly becomes more challenging to look at bringing the new assets into the company given that where our stock is currently trading. So if you like asset acquisitions, we'd always have to compete with the theoretical buyback valuation of the assets that we currently own. And any M&A, corporate deals, again, we'd have to ensure they're going to be accretive to the long-term cash flow and value proposition for IPC. And I think given where the small independents are trading, of course, that does make it more challenging to make asset and then the corporate acquisitions work. But we still continue to be very proactive and are as aggressive in our approach to looking and screening assets.

Okay. Got it. And then just on a detail, Christophe, the net debt to EBITDA, just remind, you said there's no covenants against the refinance facilities. Are there any covenants against any of the facilities that we should be aware of?