Thank you. Good morning or good afternoon. Let me start by saying that 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. Total reported fourth-quarter results that reflect the resilience of the portfolio and demonstrate again, the good ability to capture the benefits of improving oil prices and market conditions. Adjusted net income rose to $848 million or $0.29 per share. Net adjusted cash flow this year increased to $4.3 billion. Leveraging strict capital discipline, we've strengthened the balance sheet and reduced gearing to 22%. 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 €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 pre-crisis levels. However, refining margins collapsed to negative levels during the quarter. Gas prices remained low but we saw higher levels in September in Europe and Asia. As it is traditional in 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. In this environment, capital discipline is key. We're 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 in the third quarter. Mainly this reflects full compliance with OPEC+ quotas, as well as the voluntary reduction in Canada and disruption in Libya. To a lesser degree, there is also the net effect of seasonal methanol natural declines and asset sales, which were partially offset by ramp-ups on new products. Based on the level of OPEC+ compliance and the return of Libyan production only since October, we now anticipate full-year 2020 production will average less than 2.9 million barrels of oil equivalent per day. Turning to the results by segment, iGRP, Integrated Gas, Renewables & Power segments reported $285 million of adjusted net operating income and close to $700 million cash flow in the third quarter. These segments include our integrity that in the business as you know, where we are the second-largest player worldwide and well-positioned to participate in the global energy transition. Energy 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. Energy prices average $3.6 per million BTU reflecting mainly the three to six-month lag effect 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 the LNG business from 28 million tonnes of sales through the first nine months of this year to 50 million tonnes per year by 2025. From projects already in our portfolio, all under construction. Our Integrated electricity business is a fast-growing part of the IGRP segments. Gross installed renewable power generation was 5.1 gigawatts nearly doubled compared to a year ago. Worldwide electricity production increased by more than 40% in the fourth 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 agreement to develop more than 2 gigawatts of offshore wind in South Korea and France. We also announced that we have signed the 65 watts power purchase agreement, the luxurious 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 growth in renewables capacities in operation and in development that benefit 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 have the ability to grow renewable power generation to 35 gigawatts of growth installed capacity by 2025. We already have about 24 gigawatts in our portfolio: five gigawatts installed, four gigawatts in construction, and 15 gigawatts under development. The installed capacity of 5.1 gigawatts at the end of October is fully covered by PPAs and out of the capacity in construction, or under development, I would say 20 gigawatts, nine gigawatts are already covered by long-term PPAs. With our capital disciplines in our project selection, we are confident that we can generate long-term double-digit profitability while growing stable cash flows in this business. As our investors did 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 ENP. Our commercial oil and gas segments 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 liquid price recovered to $40 per barrel, a 70% increase quarter to quarter more than offsetting lower volumes and weak call natural oil gas realizations. We continue to put pressure on gas with OpEx at $5 per oil equivalent. Cash flow increased by more than $800 million, quarter to quarter thanks to our resilient ENP 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 crude remaining in the range between $40 and $45. Faced with operating losses, we reduced our refinery utilization rate to 57% in the third quarter from 59% in the second quarter. Petrochemicals performed 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 operating income well above the pre-COVID third quarter of last year, as lockdowns were lifted in Europe and in Asia. Downstream generated $373 million adjusted net operating income and close to $1 billion of cash flow. With a low level of investment required, the downstream provided $2.4 billion of free cash flow to the group for the first nine months of the year. The trailing 12 months cash flow 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 UK, and in September the conversion of the Grandpuits refinery to a zero oil platform producing renewable diesel and bioplastics. This further streamlines our refining footprint and builds on the success with the conversion of La Mède into biorefineries. These are steps toward achieving our net zero climate conditions that have the added benefit of improving the long-term profitability and resilience of our downstream. Finally, at the group level, in the third quarter net investments were $1.9 billion bringing the total for the first nine months to $8.5 billion. We anticipate that our net investment will be lower by $13 billion this year and because of that certainty, we'll be prudent for the 2021 budget and CapEx will 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 nine months. Although the third quarter was more stable than the second quarter, the overall market environment remains challenging, and the way forward will depend on the speed of recovery given that the pandemic has affected the group. It is clear that heavy inventories of oil and refined products will have to be addressed before sustained rebounds can take place. We are prudent about the coming years. So we are using $40 per barrel 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 underinvestment have set the stage for more conservative supply-demand balance. Our priority is to generate a level of cash flow that allows us to continue to invest in profitable projects, support the dividend and maintain strong balance sheets. And of course, we continue to concentrate on the things we control: safety, operational excellence, cost reduction, and cash generation. Now I'm ready to go to the Q&A.

Thank you. Your first question comes from Irene Himona of Societe Generale. Please go ahead. Your line is open.

Thank you very much. Good afternoon. I have several questions. First, in refining and chemicals, Jean-Pierre, there was a $290 million asset impairment. Can you clarify if it was related to a specific asset? That would be helpful. Secondly, in IGRP, we've seen lower LNG prices and lower net income, but I noticed that your equity affiliates' profits in that division actually increased from the second to the third quarter. What is driving that? Is it possibly Novatec? Lastly, in M&S, volumes are significantly down, yet as you mentioned, profit is higher now compared to a year ago. Can you discuss the changes in your product mix that might be contributing to this margin expansion? Thank you.

Okay, so good afternoon, Irene. Yes, you're right. The impairment we recorded this quarter is linked to the R&C segments, refining and chemicals. It's two assets, I would say two assets. So it's the Lindsey refinery and Grandpuits. So, given that we announced that we divest our participation in the 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 refinery that we built in Grandpuits. So that is the $290 million you mentioned. The impairment on two assets. Yes, the lower LNG prices, so you're right, and it's mainly linked to the performance of our Russian energy assets and particularly Yamal LNG. On M&S volumes, it's clear that the amount of growth during the first quarter and the second quarter massively in the road transport, in air transport of course as well, creates and of course, we suffer from the slowdown in the industrial activities as well. During the lockdown period, customers tried to take advantage of the low fuel price to replenish their fuel tanks at home. And so we witnessed high sales in B2B segments. Now moving to the third quarter, we observe rebounds, we sell particularly in Asia. We ourselves, we sell a bit less; more or less the retail sales are back to the pre-crisis in Western Europe but we are still lagging in Africa and non-fuel activities are still below expectation. Of course, aviation will strongly be affected in Q3, and this negative trend is anticipated to continue in the fourth quarter. So all in all, we're seeing sales more stabilized -10% compared to 2019 levels. On top of that, of course, we benefited from higher margins because they were built at lower costs so all in all, that's the rationale behind the fact that we have a bit less volume and benefiting from higher margins we're able to deliver this performance during the third quarter.

Thank you very much, Jean-Pierre.

Thank you. Your next question comes from the line of Jon Rigby of UBS. Please go ahead.

Thank you. Hi, Jean-Pierre.

Hi.

This strikes me that I just wonder whether you could just offer your observations on this is that you are making two statements that on the face of it are slightly contradictory. You're not the only ones actually. CapEx is coming in lower than you were expecting this year, and it's 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-of-the-door and through given, let's say, as a three to four year time like. I get that there is a daily liquidity financing balance sheet issue, but can you just sort of talk through how you're balancing those two objectives as to managing the short-term and trying to position yourself for the long-term, and which takes priority?

Well, it's clear that we utilized the flexibility we have in our portfolio to preserve cash if possible but without jeopardizing the future; so it's very important. 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 in our renewable energy and electricity segment. So we play on the flexibility. As we announced, the CapEx, the net CapEx, so organic plus the net between acquisitions and divestments will be below $13 billion for this year. As we mentioned during the last Investor Day, we are cautious regarding prices and we will build our budget using a $12 billion amount for net CapEx for next year. But you noticed, Jon, that between 2022 and 2025, assuming your recovery, the prices, we announced a range between $13 billion to $16 billion. Once again, we have in our portfolio, two main projects under construction, mainly Arctic 2 and Mozambique LNG; and these projects will not be affected by this level of CapEx. The projects that will be affected are the short-term CapEx on which we can play on the flexibility. And given that the prices are not good, it's not necessarily the right time to sanction these projects with a very, very short plateau in terms of production.

As you start to increase CapEx again, will you take a cautious approach and maintain some flexibility in your plans, especially considering the current low visibility in the market? Should we expect a slow return to CapEx as recovery begins?

It's a matter of variance. I don't know. But again, the $12 billion that will be starting this year is clearly linked to the current price environment, the $12 billion for next year, we are clear that it's linked to the lack of visibility regarding the prices, and we need to be cautious. So $12 billion to $20 billion of CapEx next year; yes, you see the usurpation of this, the fact that we have no visibility on the purchases next year, beyond 2020-21; once again, prices could rebound and that's why the rationale behind the fact that at that time, we have in mind CapEx guidance between $13 billion and $16 billion per year. Right. And as you bring... That's a cool and flexible CapEx. We are flexible but quick; so we can be back here on budget, I believe, when it increases, of course, there is the beauty of this short-cycled project 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 soul contribution in the future cash flow if by chance we benefit from price rebounds.

Thank you. And your next question comes from the line of Oswald Clint from Bernstein. Please go ahead.

Jean-Pierre, thank you. Regarding IGRP, I've noticed that your earnings are down 50% year-over-year, yet cash flow has only decreased by 5%. You mentioned a 9% increase in volumes, which likely contributed to significant trading profitability in the third quarter. Can you explain why cash flow remained so strong compared to earnings this quarter? Additionally, are there any substantial power-related cash flow contributions reflected in that figure? Furthermore, you pointed out a long-term underinvestment in supply and its potential to trigger a price recovery. I'm intrigued by your consistent natural decline rate of 3%; it appears stable over the last 6 or 7 quarters, which is impressive considering the challenges faced in 2020 with short-term CapEx and logistics. Can you clarify if this is a genuinely measured number or if it has been adjusted based on other variables?

Yes. So regarding the iGRP performance, so the result and the cash flow generation. Yes, so the cash flow from operations 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 the 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, to the answer I made to before linked to the relatively good performance of the Russian assets and Yamal, in particular. And they have no impact on dividends. So that's the rationale behind the move you noticed on the CFO compared to the net adjusted income and underinvestment. And so the second question? Sorry?

I'm sorry. Yes, just your natural decline rates of minus 3%, which is almost unchanged every quarter.

Yes, we have roughly 50% of our portfolio coming from LNG fields and fields in the Middle East, particularly in Abu Dhabi. When you calculate the numbers, you see that 50% of our portfolio experiences minimal decline, while the other 50% has a standard decline of about 6% to 7%. Overall, this results in a 3% global decline for our production, which remains remarkably stable from quarter to quarter.

Understood. Thank you.

Thank you. And your next question comes from the line of Lydia Rainforth of Barclays.

I have a couple of questions. First, can you elaborate on the concept of gearing and your current debt levels? I've noticed several companies are now focusing on specific debt level targets. How do you assess your total level of debt? Secondly, regarding the carbon-neutral LNG cargoes, I understand you completed your first one this quarter. Are you receiving a premium price for that? Additionally, how significant do you believe the market for carbon-neutral LNG could be? Lastly, could you share your thoughts on the refining utilization rates for the fourth quarter?

We successfully reduced our gearing by nearly 2% in the third quarter compared to the second quarter, moving from approximately 24% down to below 22%. This reduction reflects our ability to generate cash, as we produced over $1 billion in cash after paying the dividend in Q4. Our goal remains to achieve a gearing ratio below 20%. During the Investors Day in September, we emphasized our commitment to allocate between $30 billion and $16 billion in CapEx from 2022 to 2025, and $12 billion in 2021. The dividend will be supported at $40 per barrel, and we plan to maintain the interim dividend at $0.66 per share. Our focus is to maintain a strong balance sheet, defined by a gearing ratio below 20%. Therefore, if prices exceed $40 per barrel, we will prioritize directing any additional cash to the company. The premium innovation with carbon neutral energy is something I can't fully address right now, but I will get back to you with an answer later; our team will provide the details. Regarding refinery utilization in the fourth quarter, I don't have a definitive prediction, but I've observed that margins are expected to increase by about $10 per carton since the start of the quarter, and we will keep a very close eye on this. Our utilization rate was below 60% in Q3. If the margins improve, we will adjust the utilization rates of our refineries accordingly, but considering the current demand and inventory levels, it seems likely that the margins will remain volatile and possibly at lower levels. Therefore, it is probable that the utilization rates in our refineries will not be significantly different from those we reported in Q3.

Thank you. Your next question comes from the line of an indiscernible caller. Please go ahead.

Hi, thank you for taking my question. Hi, Jean-Pierre. I have two questions, if I could. First, I noticed the aligned equity income and the line for other items. Year-to-date, if I combine IGFT and upstream, the figure is quite substantial, over $600 million, whereas last year's full total was about $17 million. Can you remind me what’s included there and what kind of revenues fall under other items? My second question pertains to LNG and Qatar. It appears Qatar is progressing with its significant expansion, having already awarded some long lead items. Can you let us know if Total is still interested in participating in that expansion, given the options you have made? What conditions would you need to meet if Qatar Petroleum makes the final investment decision next year? Thank you.

The answer for Qatar is quite straightforward. We have been disciplined in our approach, as evidenced over the past couple of years when we have sanctioned projects.

Okay, I will. Sorry.

We are disciplined in our approach and only approve projects when the conditions are favorable. The metrics we use to evaluate projects will remain the same for Qatar. We will submit an offer only if the terms are attractive. We have a long-standing presence in Qatar and are strong partners. Recently, we were awarded a project for solar farms with a capacity of 800 million watts. We are familiar with Qatar, and we have incorporated input from the project stakeholders as requested. We will proceed only if the conditions are right. This approach mirrors our decision in Brazil, where we chose not to make an offer because the conditions did not meet our criteria. It will be the same for Qatar. Regarding your question about equity affiliate income, I’m not quite clear.

So maybe you want me to rephrase it or?

Yes. So you mentioned the equity affiliates contribution to the iGRP results?

No, in fact, 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 in these other items. And these other items, to date 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, is 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 of the equity affiliates and so it's $350 million coming from Novatek participation, coming from Yamal, coming from our main LNG project.

So in fact, I was referring the $600 million figure I was referring was the nine-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 binding 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 your next question comes from the line of Biraj Bukataria of RBC.

I thanks for taking my question. 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 moving parts there? And then the second question is on Mozambique LNG. Could we get an update on your expectations 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?

The guidance we provided for the full year at $13 billion is connected to our strong visibility for Q4. Typically, Q4 involves higher investment levels compared to earlier quarters, and this is the reasoning for the $13 billion guidance. Additionally, we have the Mozambique LNG project, the Arctic 2 project, and various projects in Brazil contributing to our expected capital expenditures in the fourth quarter. Regarding Mozambique, there seems to have been some misunderstanding. The final investment decision for Mozambique was made by Anadarko prior to our acquisition of the assets, specifically in July of last year. I can confirm that the project is progressing as planned, and we are closely monitoring the situation. We are constructing two trains that are set to start operations in 2024 and 2025. Moreover, as of September, we secured project financing, obtaining around $14 billion in external debt for the benefit of all partners involved in Mozambique.

Just to clarify on that because you guys have FID-ed it. Obviously, the partners on the other side, I've kind of paused it. In terms of the kind of chasing the synergy point, are there other 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 are probably the synergies with the project operated by Exxon. And that's true that we could be onshore synergies with this project with the Rovuma LNG project, but it 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 Vigna from Goldman Sachs.

Thank you, Jean-Pierre. Two questions on your legacy oil and gas business. You've really being 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, Cost 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 Surinam 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 why we try to explain during the September Investors Day that the planet will continue to need oil in the coming years. Even in the most challenging scenarios for an oil and gas producer, oil will continue to play a significant portion in the energy mix by 2024, 2025. So we have to continue to invest in our projects. But of course, very selectively because perhaps the demand for oil will plateau, I don't know exactly when, in 10 or 15 years from now, and so our strategy is very clear, we want to position ourselves on low-cost oil assets. That's exactly the rationale we have in mind when we sanction projects. You mentioned that, yes, we have the objective to sanction the Uganda project before the end of this year. 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 mill free, 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 also to sanction in the coming years. By the way, we have the WU project, we have the IMA project. You mentioned as well the Papua New Guinea project. We are not to sanction that project. You know the status of the discussions between Exxon and the authorities regarding their gas agreement. So we have to be patient to be sure that we will be able to leverage the synergies between our project and the Exxon one. But we are quite confident that we will 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 continue with our strategy. We want to sanction a project if it's definitely a low-cost project. And by doing so, we are able to lock in the current situation and the fact that to capture, I would say, the deflation as far as contractors are concerned. So that's the rationale we have in mind. 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, Surinam and South Africa, yes, that's one of the two areas on which we made some significant discovery very recently. So Surinam, 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 percent. At present time, three wells have been drilled with three discoveries, Marka, Sakata, and Carces. 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 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, or even this week, you have to remember that we made a second discovery on the assets with a new well. So definitely, it opens up, I would say, a new world-class play in South Africa. The way forward in South Africa will consist in evaluating, of course, the size of the discoveries, to make progress regarding the development studies and, of course, engage 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 Surinam and South Africa.

Thank you.

Thank you. And your next question comes from the line of Christopher Kuplent from Bank of America. Please go ahead.

Thank you. Hello, Jean-Pierre, two quick questions please. On the CapEx cuts for this year, 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 cuts, any concerns about delays on those timelines that you talked about or whether you think it's mostly a matter of efficiency, and perhaps discretionary cuts? 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? Thank you.

On the capital expenditure cuts, there's nothing delayed regarding the ongoing projects associated with COVID-19. It's primarily about utilizing our flexibility and managing short-cycle assets, as we do not foresee a significant impact from COVID at this point. Regarding U.S. shale, we maintain our stance and believe that we cannot achieve synergies in this area due to our limited presence in the U.S. market. These assets have high breakeven points and do not align with our strategy of maintaining a portfolio of low-cost assets. Therefore, we still believe that investing in this area is not the most efficient use of our capital.

Very clear. Thank you, Jean-Pierre.

Thank you. And your next question comes from the line of Thomas Adolff of Credit Suisse. Please go ahead.

Good afternoon. I do apologize. I've got three questions, please. You've turned a bit cautious for next year, at least for budgeting purposes, $40 Brent. I wonder as it relates to your credit metrics in a $40 world of whether you think next year, you'll be consistent with a single A? Obviously, you're not for this year, and in the case, also the rating agencies lower their price decks like yourself, what are the measures which you consider to improve your credit metrics? Maybe link to that, are you open to perhaps do another one-off script offering like you've done this year or are you considering potentially sending some infrastructure-type assets like many of your peers are doing and this should be fairly easy to sell these assets? Thank you very much.

You are right for sure 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 use a price deck at $50 per barrel for 2021 and I think the same $50 per barrel for 2022. 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 all 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 continue to put pressure on costs, try to reduce the gearing. So it's the best answer I can make to simply to Moody's regarding our credit rating. On the scrips, you know the rules 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. Therefore, it was not offered for the first. It has not been offered for the second interim dividend. You 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 have 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 will be very expensive. So that's, of course, what we have in mind at the time. I think your last question regarding the infrastructure or potential share 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. I would say we have demonstrated very recently with the divestments infrastructure we made last year, so we will continue with this strategy if possible. And definitely infrastructure assets, they are good candidates for divestments in a low price environment.

Perfect. So the bottom line is you'll do whatever it takes to protect the single A and the few flexibilities around that selling assets, et cetera. But the single A...

We mentioned that in our approach to managing cash, we aim to maintain a strong balance sheet with a goal of keeping our gearing below 20%. Protecting our single A rating is our priority in how we allocate 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 outlets, so there's a quite significant number around 100 million barrels. How that impact your production outlook?

Christyan, the line is very, very bad. And it's impossible...

Can you hear me 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 give 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, you're effectively out the money. How long would you wait to make a decision on whether you'd continue to deliver that dividend?

Yes. If I understand your question about production correctly, the main reason for the decline in total production in 2020 is directly linked to the OPEC quota. We support this quota because it helped stabilize prices above $40 per barrel. I am not sure what the decision will be in the next OPEC meeting, but as long as prices remain around $40 per barrel, we expect the discipline to continue. Thus, the impact on production should remain relatively unchanged from its current state. This is already reflected in the guidance we provided during the last Investor Day, where we outlined a production profile from now until 2025, indicating that production will increase by around 2% on average each year during that period. However, we also noted that this 2% increase will come after relatively stable production in 2021 and 2022, with growth expected to begin with the start-up of the offshore Brazilian project, Arctic 2, and Mozambique Energy. Regarding dividends, we clearly stated at the last Investor Day that we can maintain the dividend at $40 per barrel. Our dividend policy is designed for a $40 per barrel environment, supported by our robust fundamentals. We have consistently demonstrated that we can maintain a breakeven price below $25 per barrel on an organic basis. We are focused on keeping operating expenses and capital expenditures in check and remain disciplined. All teams have been fully engaged since the beginning of the crisis, rapidly implementing our action plan. A good illustration of this is that at $40 per barrel, which is approximately the price this quarter, we were able to confirm the dividend level while also reducing our debt. That said, we are clear that if prices fall below $40 per barrel, we will not immediately overreact. We did not overreact in Q2 when prices were below $30 per barrel. However, if prices stay below $40 per barrel, we will not stretch our balance sheet.

Okay. And can you quantify what staying means, is it 3 months, 6 months, 9 months? Is there any way you can quantify that decline?

It's a matter of perception rather than mathematical 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 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.

Thank you very much.

And your next question comes from the line of Paul Cheng of Scotiabank.

Thank you. Good afternoon. I have two questions. First, Jean-Pierre, can you discuss the current trends regarding the recent discoveries? Are any of them potential candidates for fast-tracked development? What is the gain plan for that? Secondly, can you share the EBITDA or cash flow for your renewable and power business in the third quarter? Additionally, are you concerned about the rising prices of renewable power assets and how that might impact your ability to reach your targets through acquisitions?

On Surinam, I believe I've already addressed this question. We have drilled three wells, and the fourth is currently in progress. Our goal now is to confirm the resource levels and reserves through appraisal, with the aim of quickly sanctioning a project and facilitating faster development. If we find significant resources in Surinam, we will prioritize putting those reserves into production as soon as we can. Regarding EBITDA, we are keen to hear feedback from analysts and investors based on our September presentation. As stated in our press release, we have provided more information about our renewable business, including details about our portfolio and capacities secured through long-term power purchase agreements. We will assess what we can disclose regarding EBITDA in upcoming reports to give you more clarity on this area, which could enhance the value of the business.

And your next question comes from the line of Lucas Herrmann of Exane.

I have a couple of questions. First, when is a dividend reduction not actually a reduction? I thought the interim dividend for Q3 last year was $0.68 per share, not $0.66. I'm trying to understand what the annual payout is and how you think about it. Also, regarding dividends and in relation to Christyan's question, when I look at what your European peers have done, Shell has restructured their payout policies to be more sensible given the transition and the volatility in oil prices over the past nine months. They’ve moved to an absolute payout combined with a buyback. You haven’t made similar changes. Your shares currently yield just under 11%, and the market isn’t giving you much credit. Wouldn’t it make more sense during this uncertain period, particularly when others are adapting, to change your payout structure to include a fixed component and a buyback component? This could take advantage of the currently depressed share price to buy assets that yield around 11% and are likely to offer significant value. Those are my two questions.

Yield stable at €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 a $0.02 difference. But honestly, what you have not to forget is that in dollar, there is a strong increase because with this stability in euro, in dollar, you have a 3% increase.

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?

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 the USD, if you convert this level of dividend in dollar, our investors in USD will benefit from an increase. European...

Structure payout makes less and less competitive strength or so.

It depends on your perspective regarding this situation. We believe we can maintain the dividend at $40 per barrel. Therefore, there is no plan to change the dividend policy at that price. However, it's important to note that with the current level of dividends and our share price, the yield exceeds 9%. In our opinion, this should enhance the company's rating instead of causing a decrease in our dividends. The conclusion drawn by our CEO in September emphasized this point. Given the business case we presented and the resilience we've shown over the past few years, along with our ability to sustain the dividend at $40 per barrel, we expect the share rating to improve. Consequently, the current yield of 9% or 10% is likely to decrease in the upcoming 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.

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. 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 all disconnect.

Thank you.