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Ladies and gentlemen, thank you for standing by, and welcome to the Total Third Quarter 2020 Results Conference Call hosted by Jean-Pierre Sbraire. [Operator Instructions] I must advise you that this conference is being recorded today. And I would now like to hand the conference over to Jean-Pierre Sbraire, Chief Financial Officer of Total. Please go ahead, sir.
Thank you. Good morning and good afternoon. Let me start by saying I hope that you are all doing well and keeping safe, even more as we have entered the second wave of the COVID-19 pandemic in Europe and are not yet over with the first wave in the United States. So let's move to the results. So Total reported third quarter results that reflects the resilience of the portfolio and demonstrates, again, the group's ability to capture the benefits of improving oil prices and market conditions. Adjusted net income rose to $848 million or $0.29 per share. Debt-adjusted cash flow, DACF, increased to $4.3 billion. Leveraging strict capital discipline, we strengthened the balance sheet and reduced gearing to 22%. And based on the strong fundamentals of the company, we confirm the group's support for the dividend with the announcement of our third interim distribution maintained at EUR 0.66 per share. We saw mixed signs of recoveries in the third quarter, and we note in particular that volatility particularly in oil prices was lower than in the second quarter. Brent rebounded from less than $30 per barrel in the second quarter to more than $40 per barrel in the third quarter, thanks mainly to OPEC+ production discipline. Sales in our European marketing network came back to nearly precrisis levels. However, refining margin collapsed to negative levels during the quarter. Gas prices remained low, but we saw them rebounding to higher levels since September in Europe and Asia and as it is traditionally the case for the winter season. The group is continuing to execute and deliver on the strategy and objectives presented since the start of the COVID crisis. We have kept the organic breakeven below $25 per barrel, reduced OpEx to $5 per barrel equivalent, and we are on track to cut costs this year by more than $1 billion objectively. In this environment, capital discipline is key, and we are limiting CapEx to less than $13 billion this year, $1 billion lower than previous guidance, while still continuing to invest $2 billion for our fast-growing renewable power generation business. Operationally, oil and gas production decreased to 2.7 million barrels of oil equivalent per day in the third quarter. Mainly, this reflects strong compliance with OPEC+ quotas as well as the voluntary reduction in Canada and disruptions in Libya. To a lesser degree, there is also the net effect of seasonal maintenance, natural declines and asset sales, which were partially offset by ramp-ups on new projects. Based on the level of OPEC+ compliance and the return of Libyan production only since October, we now anticipate full year '22 production -- 2020 production will average less than 2.9 million barrels per oil equivalent per day. Turning to the results by segment. iGRP, Integrated Gas, Renewables & Power, segment reported $285 million of adjusted net operating income and close to $700 million of cash flow in the third quarter. This segment includes our integrated LNG business, as you know, where we are the second largest player worldwide and well positioned to participate in the global energy transition. LNG sales volumes were 8.1 million tons in the third quarter, a 9% increase year-on-year, mainly due to growth in our trading activities. LNG prices averaged $3.60 per million BTU, reflecting mainly the 3- to 6-month lag effects on oil-linked contracts. But this effect is beginning to reverse, and we anticipate a rebound in LNG prices to more than $4 per million BTU in the fourth quarter. We'll continue to grow our LNG business from 28 million tons of sales through the first 9 months of this year to 50 million tons per year by 2025 from projects already in our portfolio or under construction. Our integrated electricity business is a fast-growing part of the iGRP segment. Gross installed renewable power generation was 5.1 gigawatts, nearly double compared to a year ago. And worldwide, electricity production increased by more than 40% in the third quarter, and we are continuing to expand the number of gas and power customers in our European network. We are accelerating the growth of our renewable power generation notably with the acquisition of a 3.3-gigawatt portfolio of solar projects in Spain, plus agreements to develop more than 2 gigawatts of floating offshore winds in South Korea and France. We also announced that we have signed a 6 terawatt hour power purchase agreement, the largest corporate PPA to date, to cover all of our electricity needs for the group's industrial sites in Europe by 2025 using solar assets in Spain that we will develop. Consistent with the acceleration of the growth in renewables, we have added disclosures for our renewable business. We now report gross renewables capacities in operation and in development that benefits from long-term power purchase agreements. This should help the market assign value to the business as it becomes more material. As you know, we had the objective to grow renewable power generation to 35 gigawatt of gross installed capacity by 2025. We already have about 24 gigawatts in our portfolio: 5 gigawatts installed, 4 gigawatts in construction and 15 gigawatts under development. Installed capacity of 5.1 gigawatts as at end of September is fully covered by PPAs. And out of the capacity in construction or underdevelopment, I would say 20 gigawatts, 9 gigawatts are already covered by long-term PPAs. We are capital disciplined in our project selection and confident that we can generate long-term double-digit profitability while growing stable cash flows in this business. At our Investor Day last month, we concentrated on the transition of Total into a broad energy company, so I will not go into more details here. Let's turn to E&P. Our conventional oil and gas segment generated adjusted net operating income of $800 million and more importantly, I think, carried the group with cash flow generation of more than $2.6 billion in the third quarter. Average realized liquids price recovered to $40 per barrel, a 70% increase quarter-to-quarter, more than offsetting lower volumes and weaker natural gas realizations. We continue to put pressure on costs with OpEx at $5 per oil equivalent. Cash flow increased by more than 800 million ton (sic) [ $800 million ] quarter-to-quarter thanks to our resilient E&P portfolio and our sensitivity to oil prices. The Downstream faced a more challenging environment in the third quarter, with refining margins in Europe negative on average for the quarter and a less exceptionally favorable environment for trading activity than in the second quarter. Recall, we mentioned that trading generated an exceptional surplus of around $500 million of cash in Q2 due to huge volatility. The third quarter was, in fact, very stable with Brent remaining in the range between $40 and $45 per barrel. Faced with operating losses, we reduced our refinery utilization rate to 50 -- 57%, sorry, in the third quarter from 59% in the second quarter. Petrochemicals resisted well despite weaker margins quarter-to-quarter in Europe and in Asia as well as utilization rates that declined to 75% in the third quarter from 84% in the second quarter. Marketing rebounded from the second quarter low, generating more than $400 million of adjusted net income -- net operating income, well above the pre-COVID third quarter last week -- of last month -- of last year, sorry, as lockdowns were lifted in Europe and in Asia. Downstream as a whole generated $373 million of adjusted net operating income and close to $1 billion of cash flow. With a low level of investment required, Downstream has provided $2.4 billion of free cash flow to the group over the first 9 months of the year. The trailing 12-month ROACE for the Downstream is 14%. Consistent with our outlook for oil product demand in Europe and the strong growth in the renewable diesel market, we announced in July the sale of the Lindsey refinery in the U.K.; and in September, the conversion of the Grandpuits refinery to a 0 oil platform, producing renewable diesel and bioplastics. This further streamlines our refining footprint and builds on the successful conversion of La Mede into a biorefinery. These are steps towards achieving our net zero climate ambitions that have the added benefits of improving the long-term profitability and resilience of our Downstream. And finally, at the group level, in the third quarter, net investments were $1.9 billion, bringing the total for the first 9 months to $8.5 billion. We anticipate that our net investment will be lower than $13 billion this year. And because of uncertainty, we will be prudent for 2021 budget, and CapEx should be limited to less than $12 billion. Despite this difficult environment and mainly due to our capital discipline, Total generated positive net cash flow of $1.9 billion in the third quarter and $2.7 billion in the first 9 months. Although the third quarter was more stable than the second quarter, the overall market environment remains uncertain, and the way forward will depend on the speeds of the recovery in global demand affected by the COVID pandemic. It is clear that heavy inventories of oil and refined products will have to be addressed before sustained rebound can take place. We are prudent about the coming year so we are using a $40 per barrel Brent scenario as our base case. Longer term, we recognize that the growing world population will demand more energy of every type, and the many years of underinvestments have set the stage for a more constructive supply-demand balance. Our priority is to generate a level of cash flow that allow us to continue to invest in profitable projects, support the dividend and maintain a strong balance sheet. And of course, we'll continue to concentrate on the things we control: safety, operational excellence, cost reduction and cash generation. And now I'm ready to go to the Q&A.
[Operator Instructions] Your first question comes from the line of Irene Himona of Societe General.
My questions, well, I had a number of them. First of all, in Refining & Chemicals, Jean-Pierre, there was a $290 million asset impairment. Was it one particular -- one specific asset? Or if you can talk about it, it would be helpful. Secondly, in iGRP, we had lower LNG prices, lower net income, yet I noticed that your equity affiliates profit in that division actually increased between second and third quarter. And I wonder what is driving that. Is it Novatek perhaps? And finally, in M&S, volumes are obviously down quite materially. As you said, profit is higher now than a year ago. Can you talk about the changes to your product mix perhaps which is driving this apparent margin expansion?
Okay. So Irene, yes, you're right, the impairment we recorded this quarter are linked to the R&C segment, Refining & Chemicals. And it's 2 assets only, I would say 2 assets. So it's Lindsey refinery -- oil refinery and Grandpuits. So given that we announced that we divest our participation in our oil refinery, we have to write off the assets. And the same for Grandpuits. We have to impair the assets that will be discontinued, that will not be used by the biorefinery that we built in Grandpuits. So that's $290 million you mentioned, so that's impairment on 2 assets. Yes. The lower LNG prices, so you're right, and it's mainly linked to the performance of our Russian LNG assets and particularly Yamal LNG. And on M&S volumes, well, it's clear that demand has dropped during the first quarter and the second quarter massively in road transport, in air transport, of course, as well. It creates -- and of course, we have to -- we suffered from a slowdown in the industrial activities as well. We saw at that time, retail sales down to almost minus 70% in France and between 30% to 40% in Germany and in The Netherlands. And during the lockdown period, of course, customers tried to take advantage of the low fuel price to replenish their fuel tanks at home, and so we witnessed these high sales on our B2B segment. Now moving to the third quarter. So we observed a rebound with sales, particularly in Asia where sales -- we sold rapidly. More or less, the retail sales are back to the precrisis levels in Western Europe, but we are still lagging in Africa. And nonfuel activities are still below expectation. So -- and of course, the aviation will strongly be affected in the Q3 and is anticipated to -- this trend is anticipated to continue in the fourth quarter. So all in all, we are seeing sales stabilize -- more or less stabilized, minus 10% compared to 2019 level. And on top of that, of course, we benefited from higher margins because inventories were built at lower cost. So all in all, it's rationale behind the fact that with a bit less volumes and benefiting from higher margins, we are able to deliver this performance during the third quarter.
And your next question comes from the line of Jon Rigby of UBS.
It strikes me that -- I was just wondering whether you could just offer your observations on this. You are making 2 statements that on the face of it are slightly contradictory, and you're not the only one actually. It's that CapEx is coming in lower than you're expecting this year and is going down again next year, and yet you are, and I think quite rationally, setting out a case for why markets will tighten and pricing will improve. So isn't this exactly the right time to be kind of focusing on trying to get your projects out the door and through given, let's say, it's a 3- to 4-year time lag? I get that there is clearly liquidity, financing, balance sheet issue, but can you just sort of talk through how you're balancing those 2 objectives or sort of managing the short term and trying to position yourself for the long term? And what takes priority?
It's clear that we use the flexibility we have in our portfolio to preserve the cash if possible but without jeopardizing the future. So it's very important. So our main projects are not impacted by this level of CapEx. And on top of that, we are very clear that we will continue to invest more or less $2 billion per year on our renewable and electricity segment. So we play on the flexibility. That's true that now we announced that the CapEx -- the net CapEx, so organic plus the net between acquisitions and divestment, will be below $13 billion this year. As we mentioned during the last Investor Day, we are cautious regarding the prices -- the price deck for next year, and we've built our budget using a $12 billion amount for net CapEx for the next year. But you noticed, Jon, that between 2022 and 2025, assuming a recovery in oil prices, we announced a range between $13 billion to $16 billion. Once again, we have, in our portfolio, 2 main projects under construction, so mainly Arctic 2 and Mozambique LNG. And these projects will not be affected by this level of CapEx. The project that will be affected is short-term CapEx, on which we can play on this flexibility. And given that the prices are not good, it's not necessarily the right time to sanction these projects with a very short plateau in terms of production.
Right. And as you bring -- as and when you bring back CapEx -- and presumably, there is some sort of view and positioning taken on, on the ability to sort of have some flexibility as you bring it back on because, clearly, as everybody has learned, visibility is low. So would we expect you to bring back CapEx fairly cautiously in the initial stages of any recovery?
It's a matter of environment. Once again, this $12 billion -- or this $13 billion this year is clearly linked to the current price environment. The $12 billion for next year, we are clear that it's linked to an assumption -- or to a lack of visibility regarding the prices, and we need to be cautious. So $12 billion of CapEx next year, yes, it's the recognition of this -- the fact that we have no visibility on the prices next year. Beyond 2020 -- 2021, once again, prices could rebound. And that's why this rationale behind the fact that at that time, we have in mind a CapEx guidance between $13 billion and $16 billion per year. But that's true that flexible -- CapEx, we are flexible both ways. So you can -- we can be back on the jet rapidly if Brent increased, of course. That's the beauty of these short-cycle projects. And you know that in our portfolio, we have more or less the equivalent of 1 billion barrels of short-cycle projects. So it could be a strong contribution in the future cash flow if, by chance, we benefit from price rebound.
And your next question comes from the line of Oswald Clint from Bernstein.
Jean-Pierre, just back on iGRP. Just looking at your earnings down 50% year-over-year but cash flow is only down 5%. You mentioned volumes up 9%, but that's a lot of trading which, I can imagine, was particularly profitable in the third quarter. So can you just say why cash flow was so resilient relative to earnings this quarter? And is there any material power-related cash flow contribution showing up within that number? And then secondly, I think you mentioned underinvestment in supply longer term and how that might set up for a bit of a price recovery. But what I find interesting is your -- just your natural decline rate, 3% -- I think for the last 6 or 7 quarters, it's been pretty stable at minus 3%, which is remarkable in a year like 2020 with pressures on your short-term CapEx and things like logistics. So is that a real measured number? Or is that kind of backed out or an implied number from some of the other moving parts, please?
Yes. So regarding the iGRP performance, so the result and the cash flow generation. Yes, so the cash flow -- the CFFO -- the iGRP CFFO from -- for the third quarter was down more or less by 1/3 compared to last quarter. It was, of course, negatively impacted by the prices -- by LNG prices, but also by lower dividends coming from equity affiliates. And on the opposite, if you look at the net operating income, the equity contribution improved in Q3, the answer I made to Irene before, linked to the relatively good performance of the Russian assets and Yamal in particular. And they have no -- this has no impact on dividend. So that's the rationale behind the move you noticed on the CFO (sic) [ CFFO ] compared to the net adjusted income. Underinvestment -- and so the second question -- sorry?
Your -- I'm sorry. Yes, just your natural decline rates of minus 3%, which is almost unchanged every quarter.
Yes, yes, yes, because we benefit from 50%, more or less, of portfolio coming from LNG fields and fields in the Middle East, in particular in Abu Dhabi, in -- yes, in the Middle East. So all in all, if you make the math, you have 50% of our portfolio benefiting from more or less 0 decline and 50% with, I would say, standard or normal decline of 6% to 7%. So all in all, so you made the math, it leads to the 3% global decline for our production. And you're right, it's remarkably stable quarter after quarter.
And your next question comes from the line of Lydia Rainforth of Barclays.
A couple of questions, if I could. The first one, can you just come back to this idea of gearing and the debt levels? We have seen a number of other companies now moving to absolute debt levels as targets. I'm just wondering sort of how you would think still about the Total level of debt.And then the second question was just on the -- I saw recently the idea of carbon-neutral LNG cargoes, I think the first one that you did this quarter. Are you actually getting a premium pricing on that? And just a little bit more detail on how big you think that market can actually be for carbon-neutral LNG.And then very quickly -- just a quick one. Can you just give me what you're thinking about the utilization rates for refining for fourth quarter?
Okay. Gearing, yes. So you noticed that we are able to reduce our gearing by almost 2% in the third quarter compared to the second quarter because we are more or less at 24% in the second quarter. We are below -- 22% this quarter. It's the reduction -- the translation of the fact that we are able to generate cash even after the payment of the dividend in Q4. We generated after dividend more than $1 billion of cash. And it's -- and of course, it's lead to this gearing reduction. We -- as we were very consistent in saying that, yes, our objective is to have a gearing below 20%. So you'll remember what we mentioned in September during the Investors Day. The priority, of course, to prepare for the future is to allocate what I mentioned to Jon, between $13 billion and $16 billion of CapEx from 2022 to 2025, $12 billion in 2021. After that, the dividend. So we reaffirm that the dividend is supported at $40 per barrel. And you noticed that we confirm this quarter that, yes, the third interim dividend will be maintained at EUR 0.66 per share. And after that, very clearly, we put as a priority the fact that we want to maintain a very strong balance sheet. And in our mind, a strong balance sheet means gearing below 20%. And so that's why we mentioned that in the event we are able to generate additional cash, if the prices are above $40 per barrel, we will first allocate this additional cash to deleveraging the company. The premium in relation with the carbon-neutral LNG, honestly, I'm not so sure to have this answer. And I will come back to you on the answer later, and the team will give you the answer. The outlook for the refinery utilization in the fourth quarter, honestly, I have no crystal ball. I just noticed that the margins are a bit above $10 per ton since the beginning of the quarter. We'll monitor that very, very precisely. We have utilization rates below 60% in Q3, and so the utilization will improve if margins improve, of course. We'll adjust the utilization rates of our refineries to the level of margin. But honestly, given the level of demand and given the level of inventories, I'm sure that the refineries -- and perhaps I do not have to use this word I'm sure, but it's likely that the margins will become -- will remain volatile and probably at a relatively low level. And so as a consequence, the utilization rate in our refineries will probably not be very different from the figures you -- we have in the Q3.
And your next question comes from the line of Bertrand Hodee from Kepler Cheuvreux.
Jean-Pierre, two questions, if I may. The first one is -- I was looking at the line equity and income and other items and especially the line other items. And year-to-date, if I combine iGRP and Upstream, it's quite a big number. It's above $600 million. Whereas, last year, for the full year 2020, it was around $70 million. Can you remind me of what's in there? And what kind of revenues is located inside other items line? And the second question is on LNG and on Qatar. It looks like Qatar is finally moving with its massive expansion, having awarded already some long-lead items. And can you share with us if Total is -- obviously, you have made the option, but if Total is still interested by participating in that expansion? And what are the conditions required for you to jump in if Qatar Petroleum takes final investment decision next year.
All right. I think the answer for Qatar is very easy. You know that we are disciplined. We demonstrated that over the last couple of years, that we sanctioned projects only -- perhaps, I think you have to switch off your microphone because there is an echo, Bertrand.
Okay. I will sorry.
So we are disciplined. So we sanction projects only if the conditions are attractive. So you know the way we sanction projects and the internal rate of return we use and the prices we use to sanction projects. So it will be, honestly, the same for Qatar. There is no reason -- so we'll submit an offer only if terms are attractive. That's clearly the truth that we have been in Qatar for a long time. We have strong partners. By the way, we were recently awarded, as you know, 4 solar farms of 800 million watts. We know well the Qatar. We -- by the way, we have embedded (sic) [ submitted ] second bid in -- at the request of QP in this project. But we will go forward only if the conditions are attractive. That's the main -- that's my answer. You could remember that's exactly -- that was exactly what we did with the project in Brazil. We decided not to go -- not to submit or not to make an offer given that the conditions were not good or did not meet our thresholds, and it will be exactly the same for Qatar. So your question regarding the equity affiliate income, honestly, I'm a bit lost. So you mentioned...
Maybe you want me to rephrase it or -- yes?
No, no, just -- so you mentioned the equity affiliate's contribution to the iGRP results.
No, no. In fact, is -- when you -- when we look at your results, in fact, you combine a line which is equity income/loss and other items. Okay? As you also disclose the equity affiliate separately, we are able to -- in fact, to calculate what is these other items. And these other items to date is -- if I combine iGRP and E&P, is above $600 million. So that's a big number. And I was wondering what's in there in terms of contribution. Knowing that last year, if I make the same calculation, it's around $70 million, so that's a $500 million difference.
The figure that I have in mind is the contribution globally at the level of the group, not the equity affiliates. And so it's $350 million coming from Novatek participation, coming from Yamal, coming from our main LNG projects. And...
So in fact, I was referring -- the $600 million figure I was referring to was the 9-month figure. And in Q3, it's around $165 million, combined iGRP and E&P for these other items line.
Okay. It's a detailed question, and I will come back to you with the precise answer.
Okay. Fair enough. Can I just make a follow-up on Qatar? I think we're already aware of the condition. And is the bidding process already started or not yet until the final cost of the project is done?
I will not disclose to you all this information, but the offers are due by year-end.
And sorry for the accounting question.
No, I will have a look because I do not have all the tables in front of me. But of course, there is a rational answer to your question.
And your next question comes from the line of Biraj Borkhataria of RBC.
I had a couple for you. I just wanted to clarify on the net investment guidance, the less than $13 billion this year. You did $8.5 billion year-to-date, so I was wondering. If I'm thinking about Q4, there's either a big step-up in organic spend or an acquisition due or you'll come in below guidance. Can you just unpick the moving parts there? And then the second question is on Mozambique LNG. Could we get an update on your expectations or when you expect to FID that? I understand, in the short term, it's partly a function of affordability, but also maybe you can talk about what you're doing during the pause because, I guess, it gives you a chance to rework and retender. And how much more potential do you think there is on getting cost out of that project before FID?
Well, the guidance we gave on -- for the full year, so the $13 billion, is clearly linked to the fact that we have a very good visibility on the Q4. Traditionally, the Q4 in terms of investment is a bit higher or a bit heavy than the previous quarters. And so it's the rationale behind this guidance, $13 billion. And once again, as I already mentioned, we have the Mozambique LNG project. We have the Arctic 2 project. We have some -- Mero 1, Mero 2 projects in Brazil, of course, as well. That contributes to the level of CapEx that we will expend during the fourth quarter. Mozambique, I think, perhaps I haven't really understood your question, but the FID has been taken. By the way, the Mozambique FID was taken before by Anadarko because, at that time, it was in -- I think it was in July last year. It was before we acquired the assets through the OXY-Anadarko deal. So the project -- what I can tell you is that the project is on track. Of course, we are monitoring the situation very closely. But yes, the project is on track. And so the first -- as you know, we will -- we are building 2 trains that will come onstream by 2024, 2025. And on top of that, in -- I think it was in September, we confirmed that the project financing is in place. We were able to secure an external debt of about $14 billion on that project for the benefit of all the partners in the Mozambique LNG. But the FID is taken.
Just to clarify on that. Because -- you guys have FID-ed it. Obviously, the partners on the other side have kind of paused it. In terms of the kind of chasing the synergy point, is -- are there limitations to what you can do if you're working at different paces?
No, I don't think so. The synergies you have in mind is probably the synergies with the project operated by Exxon. And that's true that there could be onshore synergies with this project and with Rovuma LNG project but will not slow down the project linked to the Rovuma LNG project, to be very clear.
And your next question is from the line of Michele Della Vigna from Goldman Sachs.
Perfect. Jean-Pierre, 2 questions on your legacy oil and gas business. You've really been the only major oil and gas company to continue to FID major long-term projects like Mozambique, like Mero. I was wondering whether -- what you think about the next generation of projects, Uganda, PNG, Costa Azul and whether you think this is the right time to move ahead or perhaps wait a little bit longer.And then a second question on your recent discoveries. You've announced some really exciting results in Suriname and South Africa. I was wondering if perhaps you could quantify what you believe could be the total amount of resources there.
Yes. You're right, we continue to sanction projects because we -- definitely, we think, and that's what we tried to explain during the September Investors Day, that the planet will continue to need oil in the coming years. And even in the most challenging scenarios for an oil and gas producer, oil will continue to play a significant portion of -- in the energy mix by 2024, 2025. So we have to continue to invest on oil projects but, of course, very selectively because perhaps the demand -- the oil demand will plateau, I don't know exactly when, in 10 or 15 years time from now. And so our strategy is very clear. We want to position ourselves on low-cost oil assets and exactly the rationale we have in mind when we sanction projects. You mentioned that, yes, we will -- we have the objective to sanction Uganda project before end of this year, and it particularly fits within the strategy of low-cost oil projects. We have other projects in mind, of course, or in our portfolio that could be sanctioned in the coming years. We just sanctioned the Mero 3, but we could sanction additional projects in Brazil as well in the coming years. We have some projects in Nigeria, very well positioned in terms of costs as well, to sanction in the coming years, so Preowei. We have the Owowo project. We have the Ima project. You mentioned as well the Papua New Guinea project. We are not in a hurry to sanction that project. You know the status of the discussion between Exxon and the authorities regarding their gas agreement. So we have to be patient to be sure that we'll be able to leverage on the synergies between our project and the Exxon one but we are quite confident that we'll be able to sanction that project in the coming years and given that this project is, once again, a low-cost LNG project, very well positioned to supply the Asian markets. So we tried -- we continue with our strategy. We want to sanction a project if it's definitely a low-cost project. And by the way, by doing so, we are able to lock in the current situation and the fact that the -- to capture, I would say, the deflation as far as contractors are concerned. So that's the rationale we have in mind. So we will continue with this strategy. And we have demonstrated over the last couple of years that it's worked well, and it's the most efficient way to enhance our portfolio by doing so. Exploration, yes. Suriname and South Africa, yes, that's 1 of -- the 2 areas on which we made some significant discovery very recently. So Suriname, we entered into the asset, it was end of last year. We have a 50% stake in the project, with Apache having the 50% remaining. At present time, 3 wells have been drilled with 3 discoveries, Maka, Sapakara and Kwaskwasi. At present time, we are drilling a fourth well. And you know that after this drilling, Total will become the operator of the area. So the way forward is very clear for us. A lot of hydrocarbons has been discovered. And so now we need to -- some appraisal wells to clearly identify the level of reserves and to launch, if possible, development with an objective to start up production by 2025. And on South Africa, we announced, it was last week or -- I think yes or even this week. You have to remember that we made second discovery on the assets with a new well. So definitely, it's open, I would say, a new world-class play in South Africa. And the way forward in South Africa will consist of evaluating, of course, the size of the discoveries, to make progress regarding the development studies and of course, engage in discussions with the South African authorities regarding possible conditions for the gas commercialization. So that's what we have in mind for the coming month on both Suriname and South Africa.
And your next question comes from the line of Christopher Kuplent from Bank of America.
Jean-Pierre, 2 quick questions, please. On the CapEx cut for this year, I just wanted to understand whether you can identify specific projects that you are maybe forced to go a little bit more slowly on because of COVID restrictions and whether you can see from that CapEx cut any concerns about delays on those time lines that you talked about or whether you think it's mostly a matter of efficiency and perhaps discretionary cuts.And secondly, on a more broader level, just wanted to ask a cheeky question, whether you feel -- these days, looking at what's happening in North America, whether you feel vindicated about Total's strategy to stay away from mostly U.S. shale. Or in fact, do you feel tempted by the kind of consolidation that's happening without much share price premium being offered?
On the CapEx cut, once again, there is no significant delays on the progressing projects linked to the COVID-19. It's more a matter of playing with the flexibility we have and the short-cycle assets. And so we do not anticipate a large impact on our projects linked to the COVID effect at this stage. On U.S. shale, we are consistent. We haven't changed our mind. We think that it's a business on which we cannot -- we will not be able to leverage on synergies because we are not present on -- in the U.S. on this type of business significantly. It's high-breakeven assets, and it's completely inconsistent with our strategy to have in our portfolio low-cost assets. So that's why we continue to think that it's not the right -- the most efficient way for us to allocate our capital.
And your next question comes from the line of Thomas Adolff of Crédit Suisse.
I do apologize, I've got 3 questions, please. You've turned a bit cautious for next year, at least for budgeting purposes, $40 Brent. And I wondered, as it relates to your credit metrics in a $40 world, whether you think next year you'll be consistent with A. Obviously, you're not for this year. And in the case also the rating agencies lower their price decks like yourself, what other measures would you consider to improve your credit metrics? And maybe linked to that, are you open to perhaps do another one-off scrip offering like you've done this year? Or are you considering potentially selling some infrastructure-type assets like many of your peers are doing? And it should be fairly easy to sell these assets.
Yes. Okay. So yes, we are cautious regarding the prices for next year. And that's true that we built our budget using the $40 per barrel assumption. If I remember well, S&P used a price deck at $50 per barrel for 2021 and I think the same $50 per barrel for 2022. We -- I noticed that despite the drop in oil prices in March, April and the new price deck used by S&P and Moody's, by the way, we are able to keep our rating. That's true that we have a negative perspective, but honestly, it's the same for almost all our peers. If the prices remain at $40 per barrel, what will be the impact on our rating? Honestly, it's very difficult -- it's not so easy to anticipate. It's not fully in my control. So what I can tell you is that we try to demonstrate that we will continue to be disciplined. We will, by the way, continue to put pressure on costs, try to reduce the gearing. So it's the best answer I can make simply to Moody's regarding our credit rating. On the scrips, you know the rules in -- for a French company. Given that this scrip dividend was not voted in June during the general assembly, we will not offer the scrip dividends for the interim dividend. So therefore, it was not offered for the first. It has not been offered for the second interim dividend. You'll notice that, of course, given the reason I mentioned to you, it was not offered for the third dividend. Honestly, at present time, if the prices remain at this level, we demonstrated that in the $40 per barrel environment, we are resilient, we are able to generate cash. So we'll see in 2021 what the prices will be and if the prices will be significantly below $40 per barrel. But it's a decision of the general assembly and not a decision that the Board could do on the payment of the interim dividend. By the way, at the time, we have a yield at 9%, even 10%. And so a scrip with this level of yields is -- will be very expensive. So that's, of course, what we have in mind at the time. And I think your last question regarding the infrastructure or potential infrastructure asset sales, yes, that's true that in an environment with low prices, it could make sense to focus our M&A or divestments on infrastructure assets. We do not need to be an equity partner in infrastructure to benefit from the infrastructure. It's what we have demonstrated very recently with the divestments in infrastructure we made last year, so we will continue with this strategy if possible. And definitely infrastructure assets, they are good candidates, I would say, to divestments in a low price environment.
Perfect. So the bottom line is you'll do whatever it takes to protect the A and the few flexibilities around that, selling assets, et cetera. But the A...
Exactly. We mentioned that in our -- in the way we allocate the cash maintaining or having a strong balance sheet with an objective of gearing below 20%. And the A, of course, is a priority in the way we will allocate the cash.
And your next question comes from the line of Christyan Malek of JPMorgan.
Two, if I may, Jean-Pierre. First, in a scenario where OPEC doesn't reverse production outputs, so it's a quite significant number, around 1.9 million barrels, how would that impact your production outlook? I mean as you can...
Christyan, sorry, the line is very, very bad. And it's impossible for me...
Sorry. Can you hear me better now?
Yes. Yes, it's better. Sorry, yes. Yes, go ahead.
Hello?
Yes.
Yes. Sorry about that, just a connection issue. In a scenario where OPEC doesn't increase production next year, and so 1.9 million barrels, would that be material to your production outlook and your guidance? I just want to get some color as to how that affects your thinking around targets for next year.And the second question is regarding CapEx and sort of your dividend priority. I'm sorry to ask it directly, but to what extent is time an important factor as you think about your dividend? And the fact that if we stay below $40 and you're effectively at the money, how long would you wait to make a decision on whether you'd continue to deliver that dividend?
Yes. So if I understand well your question regarding production, we -- the main rationale behind the declining production at Total level in 2021 -- 2020, sorry, is directly linked to -- with the OPEC quota. But by the way, of course, we are supportive of this quota because it's helped to stabilize the prices above $40 per barrel. So I don't know what the decision will be during the next OPEC meeting. I'm sure that if the prices are -- remains around $40 per barrel, the discipline will be maintained. And so we can imagine that the impact on production will remain more or less the same as the current impact. And it's already embedded in the figures of the guidance we gave during the last Investor Day. So we mentioned we have a profile between now and 2025 mentioning that the production will increase more or less by 2% on average per year between now and 2025. But we'd mentioned at the same time as well that this 2% will result from more stable -- relatively stable production over period 2021, 2022 and that the increase will come later on with the start-up of the offshore Brazilian project, with the start-up of Arctic 2 and with the start-up of Mozambique LNG. Regarding your question concerning the dividends, I think we were very clear during the last Investor Day that we can support the dividend at $40 per barrel and that the dividend policy is, I would say, well sized for an environment that's $40 per barrel. And again, the rationale behind that is that we have strong fundamentals. We have demonstrated quarter after quarter that we are able to maintain a breakeven below $25 per barrel, organic breakeven. We put pressure on OpEx. We put pressure on CapEx. We continue to be disciplined. And so all the teams, they are fully mobilized since the beginning of the crisis to implement the action plan we have decided very rapidly after the crisis. And I think the best illustration of that is that at $40 per barrel, which was more or less the price we have this quarter, we are able to announce -- or the Board decided to confirm the level of dividend. And at the same time, we are able to reduce the gearing. Having said that, to be very clear, if the price falls below $40 per barrel, we'll, of course, not overreact immediately. So we did not overreact in the Q2 when the prices were below $30 per barrel. But if the price stays below $40 per barrel, we will not overstretch the balance sheet.
Okay. And can you qualify what's timing? Is it 3 months, 6 months, 9 months? If there's any way you can quantify that at this time.
It's a matter of perception rather than just mathematical. So -- but again, you have to keep in mind that we are cautious people, but we have very strong fundamentals. We can play on our balance sheet, not over a very long time period, of course. But I will not give you -- there's no formula to say if during 1, 2, 3 months, the price is below a certain number. Of course, we have to make a decision. So it's a matter of perception as well of what the market could be.
And your next question comes from the line of Paul Cheng of Scotiabank.
Two questions, please. First, Jean-Pierre, can you talk about what's trending in terms of -- I mean there's a number of nice discovery. Is that going to be candidate for fast-track development? What's the game plan there? Secondly, can you disclose what is the EBITDA or cash flow for your renewable and power business in the third quarter? And also, was it that you are concerned with the rising renewable power asset price in terms of your ability through acquisition to reach your target?
Okay. So yes, on Suriname, so I think I have already answered more or less this question. So given that we have already drilled 3 wells and the fourth well is ongoing at present time, the objective is now, through appraisal, to confirm the level of resources and the reserves and to sanction as soon as possible the project and possible fast-track development. Of course, if we have sizable resources in Suriname, the objective for us will be to put onstream -- to put on production these resources, these reserves as soon as possible. Concerning EBITDA, we noticed -- or we listen to you, by the way, what we heard from the analysts and from investors after the presentation we made in September. And so we -- as you can see in the press release, we made more disclosures regarding our renewable business. Because now we gave the level of portfolio, we gave the level of capacities already benefiting from long-term PPA. Regarding the EBITDA, we'll see in the coming reports what we can do regarding EBITDA and if we can communicate on that metric as well to give you more clarity on this business. And by the way, this could contribute to give more value to this business.
And your next question comes from the line of Lucas Herrmann of Exane.
Couple of questions or -- 2 or 3 questions, if I might. The first one is just when is a dividend reduction not a dividend reduction? Because I thought the dividend -- the interim dividend Q3 last year was EUR 0.68 per share, not EUR 0.66. So just trying to understand what the annual payout is and how you think about it. And staying with dividends and perhaps, to some degree, going back to Christyan's question. When I look at what your European peers have done, BP, Shell, admittedly by force and limited choice, they've restructured their payout policies to something which I think one could say is a lot more sensible given the transition and given the volatility that we've seen over the course of the last 9 months in oil prices. In short, they've moved to an absolute payout and to a buyback. You obviously haven't. Your shares yield a short 11% at the present time, so the market is not giving you huge credit. Would it not just make much more sense through this period, when others have done something similar and when there is so much uncertainty and when you're acknowledging the importance of your balance sheet, to change the structure of your payouts, Jean-Pierre, such that you do use a fixed component, you do use a buyback component and you take advantage of the very depressed share price at the present time to buy an asset that today yields towards 11% and which, I think you feel, probably offers exceptionally good value? Those are the 2 questions.
Dividend is stable at EUR 0.66 per share compared -- in Q3 compared to Q2. That's true that if you compare the third interim dividend this year with the third interim dividend we served in 2019, it's $0.02 difference. But honestly, what you have not to forget is that in dollar, there is a strong increase because with the stability in euro, in dollar, you have a 6% increase. So...
Do I now need to think -- Jean-Pierre, do I now need to think about your dividend in dollar terms then and adjust that mentally to consider what the euro number will be?
Sorry, I haven't captured your question. Sorry.
Do I now need to think about what the dividend is in dollar terms and try thinking about flatlining that to think about what the euro declared will be?
No. You know that given -- as a French company, we have to denominate our dividend in euro. And so the dividend policy is denominated in euro. Just to mention that in USD -- if you convert this level of dividend in dollar, our investors in USD will benefit from an increase. European...
The structure of payout, it makes less and less competitive strength...
You -- it depends how you see this subject. We consider that. Once again, we can support the dividend at $40 per barrel, so there is no way to reset the dividend policy at $40 per barrel. But on the opposite, that's true that with this level of dividend and the share price we have at present time, it leads to a yield above 9%. So in our view, it should lead to a righting of the company rather than a drop or decline or reduction in our dividends. So that's -- by the way, the conclusion of our CEO in September after the -- when he concluded the presentation, with the business case we presented, with resilience we have demonstrated over the last couple of years, with the fact that we can support the dividend at $40 per barrel, we anticipate that the share should be righted. And so that -- the current yield at 9%, 10% will be -- will go down in the coming -- hopefully in the coming weeks or months.
Okay. I guess I'd just simply argue that it's not necessarily the best structural policy for a company heading towards transition and -- given the constraints and volatility in markets, but I hear you. Jean-Pierre, thanks very much for your answering and tolerance.
Thank you. Thank you to you. So I think it was the last question.
It was the last question, sir. Please continue.
So thank you to everyone. And so once again, I hope that you will keep safe in this very challenging environment. And so have a nice weekend.
Thank you, sir. Ladies and gentlemen, that does conclude your conference call for today. Thank you for participating, and you may now disconnect.
Thank you.