Thank you. Good afternoon or good morning to all of you. Let me say first that I hope you and your close ones are safe despite the COVID situation. I think we all hope that we are close to the end of this health crisis to consolidate the recovery we are currently witnessing, and that we will come back to a normal life in the near future. Demand recovery continued to drive energy prices higher this quarter, and particularly, it was particularly the case from Asia. Our natural gas price realization increased by 42% to $6.2 per MMBtu in the fourth quarter. Our average LNG sales price increased by almost 40% to $9.1 per MMBtu.
As you know, Brent continued its year-long rise, moving up another 7% from the second quarter to average more than $73 per barrel in the third quarter. Leveraging this strong environment, TotalEnergies' adjusted net income increased to $4.8 billion, up 38% compared to the second quarter. The cash flow, the debt-adjusted cash flow, increased by nearly 25% to $8.4 billion. These strong third quarter results show that our multi-energy model, and notably our position as a world leader in LNG, is capturing the full benefits of the environment. Thanks to the overperformance of our gas and energy trading activities, which were able to leverage our global LNG portfolio.
Operationally, the company's third quarter oil and gas production was 2.8 million barrels of oil equivalent per day, up 2% from the previous quarter, reflecting the gradual curb on OPEC+ production cuts, the end of summer maintenance, and the ramp-up of some projects in Brazil, uncertain, and N'Yuntu in Angola. This should continue, and our outlook calls for fourth quarter production to be in the range of 2.85-2.9 million barrels oil equivalent per day. Let's have a look at the segments now. IGRP, Integrated Gas, Renewable and Power segments, reported record high results for the fourth quarter. Adjusted net operating income of $1.6 billion represents an increase of 84% from the previous quarter and more than 5 times from the same quarter a year ago.
Operating cash flow before working capital changes hit $1.7 billion, an increase of 90% from the second quarter and 2.5 times the same quarter last year. Cash flow was impacted by working capital outflows of $2.1 billion due to variations in margin costs relating to hedging contracts in a context of highly volatile gas and electricity markets. This margin call will reverse in the near future. Regarding our LNG business, LNG sales were 10 million tons in the third quarter, up 24% from a year ago, and year to date, LNG sales are above 30 million tons.
Given the links to oil and gas prices and the lag effect, we can expect continued strength in LNG prices, with the fourth quarter price expected above $12 per million Btu, compared to $9.1 per million Btu, per million Btu in the third quarter. Regarding our electricity business, we continue to grow our renewable power generation towards our objective to 35 gigawatts and 100 gigawatts of gross installed capacity by respectively 2025 and 2030. We are confident that we'll achieve these objectives. With 9.5 gigawatts installed at the end of this quarter, thanks mainly to the addition of 1 gigawatt in India, plus 6 gigawatts under construction and more than 25 gigawatts in the development portfolio. On the supply side, we continue to grow our customer base with a number of electricity customers reaching the 6 million mark during the quarter.
Turning to the E&P segment, strong results were driven by rising hydrocarbon prices and the increase in production by 2% as well. Adjusted net operating income was $2.7 billion in the third quarter, close to a 25% increase from the previous quarter and more than a threefold increase from a year ago. Operating cash flow before changes in working capital was close to $5 billion in the third quarter, up 16% from the second quarter and almost 90% increase from a year ago. Moving now to the downstream, European refining margins have improved, but results are impacted by higher energy costs. Petrochemicals strongly contributed to the refining and chemicals results, thanks to margin that remained high, particularly in the U.S. We fully benefited in this dynamic environment from our refining and petrochemicals integrated model.
Marketing and Services confirmed. It's returned to pre-crisis level results, notably supported by the recovery network sales. While aviation is still 40% below 2019 average, an increase in fuel demand from this sector is beginning to materialize. Adjusted net operating income from the combined downstream refining plus chemicals plus marketing and services rose to $1 billion, an increase of 12% compared to the previous quarter and nearly three times the level from a year ago. Operating cash flow before changes in working capital was $1.6 billion, a 10% increase from the second quarter and a 66% increase from the first quarter last year. Finally, some comments at the company level, mainly in terms of cash flow allocation. As you know, we're maintaining our discipline as planned at the beginning of 2021.
Our net investments were $1.9 billion in the first quarter, bringing us to $9 billion for the first nine months, which is in line with our target of close to $13 billion for the year. We plan to activate about $1 billion of short cycle CapEx to benefit from high oil prices. Our net investment in 2022 will probably be towards the top of the $13 billion-$15 billion range. In the fourth quarter, we faced working capital builds of $2.4 billion in the fourth quarter, mainly due to iGRP's $2.1 billion change in margin costs, as I already commented, a negative inventory effect of $1.2 billion, and an increase in tax liability of $0.9 billion.
We generated net cash flow of $6.2 billion in the fourth quarter. Return on average capital was again a double-digit figure and 10% and the ROI and return on equity at 12%. Including the payment of 2020 final dividends of EUR 0.66 per share or $2.1 billion cash outs, we continue to reduce our net debt, and gearing fell below 18% at the end of the third quarter. As announced in September, we will execute a $1.5 billion share buybacks in the fourth quarter, and this will lead to a cash payout of around 35% for the year.
Our fourth quarter results demonstrated that we were able to fully leverage the environment and deliver strong cash flow from oil and gas, which allow us to invest in profitable renewable and electricity projects while deleveraging the company and returning surplus to shareholders. This is our way to building a sustainable multi-energy company, combining the energy transition and shareholder returns. On that positive note, I am ready to go to the Q&A.
Thank you. Ladies and gentlemen, we will now begin the question and answer session. As a reminder, if you wish to ask a question, please press star one on your telephone and wait for your name to be announced. Please kindly mute any audio sources while asking the question. If you wish to cancel your request, please press the hash key. Once again, please press star one if you wish to ask a question. Your first question today comes from the line of Irene Himona, Société Générale.
Thank you. Good afternoon, Jean-Pierre. I had two questions, both in IGRP. Firstly, you obviously point to a fairly strong trading result in the quarter. I wonder if there's any way you can specify the approximate magnitude of that just to help us really with the modeling the underlying profitability. Secondly, you had a $940 million net acquisition. Can you remind us which particular asset that was, please? Thank you.
Okay. Good afternoon, Irene. Yes, concerning IGRP results. You know that we do not disclose the contribution separately, but I think that you can approximate trading contribution, because we provide LNG price and production, by the way, within IGRP. You have the prices, the realized prices for LNG. We talk about overperformance this quarter of our trading that was able to leverage our global LNG portfolio. All in all, I will just give you one indication. Taking into account this overperformance, our trading deliver above $0.5 billion of results this quarter. Benefiting again from this favorable environment. On the second question, yes, concerning a net acquisition.
The main contribution of this in this figure is the deal we signed with VIP in Australia on an asset called VNJ. We have VIP as of now minority interest in partners in VSS. They will pay a tolling, and in exchange of this tolling, they pay a down payment of $750 million, something like that. That's the main contribution out of this $951 million dollar of acquisition in Q3 for iGRP.
Thank you very much.
Thank you. Your next question comes from the line of Michele Della Vigna from Goldman Sachs.
Thank you, Jean-Pierre. It's Michele here. When we look at the results of your competitors throughout this third quarter, gas derivatives have had big impact across P&L and cash flow, you know, with the mark to markets and with the margining. I was wondering, did it have some impact as well on your results? I'm referring especially to the strong cash generation in the quarter. Was there any positive impact from gas derivative margining there? Thank you.
Once I gave the figures concerning the contribution of our gas and LNG trading to iGRP results this quarter, above $0.5 billion. Taking into account the context and the volatility, we benefited during the Q4. You have the prices, the average prices for LNG, the equity production that is sold on the market directly through our trading. You can make your math, and you end up with the figures with iGRP results. The impact of the volatility we have in our accounts this quarter are linked to the margin costs, as I mentioned during the speech.
The fact that we have a cash margin costs for iGRP above $2 billion, so $2.1 billion, that's that for sure will reverse in the near future.
Thank you.
Thank you. Your next question comes from the line of Lydia Rainforth from Barclays.
Thanks, and hi, Jean-Pierre. Two questions if I could. One, just on, in terms of the $1 billion of extra short cycle CapEx that you're putting in, whereabouts is that going? And also, are you seeing any impact on inflation on this side or cost pressures? And then the second question, just link back to the announcements you made about the renewables, the hydrogen side. Are you actually seeing a demand for more of these partnerships, and is that acceler ating? Thanks.
Short cycle. As I mentioned already, in September or in February, we gave a guidance for the CapEx 2022-2025 in a range $15 billion-$16 billion. Now considering particularly the oil prices, we, on this basis, of course, to mobilize short cycle CapEx, mainly infill wells in West African countries, for example, Nigeria, Angola. After this $1 billion of additional CapEx linked directly to this short cycle, that's why I indicated that in 2022, the CapEx should be close to $16 billion, the higher of the range $15 billion-$16 billion.
We are at present time finalizing work programs for this 2022 CapEx. Clearly, we have a clear focus to deliver this short cycle productions and identify future opportunities. As far as inflation is concerned, at present time, honestly, you have to remember our strategy regarding FID when we sanction projects, for example in E&P, but it's also the case for LNG or for renewable projects, we try to lock in the costs through signing EPC contracts.
That means that for all the contracts that are under development, all the assets that are under development at the same time, we will not suffer from this possible inflation on CapEx. For future projects, it will be the case for renewable, it could be the case for E&P as well. We will see. We'll continue of course to be very disciplined and to ensure that when we sanction projects, the projects are able to deliver the profitability that in line with our guidance. For sure at present time we are able, for example, in renewable activity, we see, or we will see in the near future inflation.
For E&P, I know the yards are not far from being full, because of course all the E&P majors have reduced dramatically their investment. No worries regarding this type of activity. It could be a bit different for steel or from other deepwater activity. At present time, no clear indication that in our projects we have already seen. For hydrogen, for sure. Probably we'll have more demand for hydrogen projects. We communicated in the Q3 around this hydrogen subject on the fact that we want to decarbonize the hydrogen used in our refineries.
The last example I have in mind is the partnership we've signed with Air Liquide to decarbonize the hydrogen used in our Normandy refinery. It's one example, but of course, we have a clear plan to decarbonize the hydrogen in all our refineries, and so it could come through partnerships. We have another example. During the Q3, we announced that we will finance funds to develop hydrogen infrastructure worldwide. We will with an objective of investing $1.5 billion through this fund. I think at present time, we already have $0.8 billion or something like that already in the fund. It's a partnership with ENGIE.
It's a partnership with Air Liquide also, just to mention French companies. Also, of course, we'll attract worldwide companies interested in this type of investments. Just to give you two very recent examples regarding hydrogen partnerships.
Your next question comes from the line of Jon Rigby from UBS.
Thank you. Hi, Jean-Pierre. 2 questions. Just to go on to the IGRP numbers again and the guidance. The $12, so the $3 increase, 3Q to 4Q, can we think about that as ratably impacting both your underlying sort of production to sales legacy business, but also your trading business? I presume you've got some visibility on volumes locked in. Or is there other moving parts in your trading business that might mean that you don't make the same kind of super normal profits in 4Q that you made in 3Q? I'm sort of conscious that access to volumes are important, and you appear to have access to volumes some of your competitors don't.
The second question is if my memory serves me right, at the 2Q call, I think I remember Patrick saying that as soon as you got back from your vacation, which I believe was the end of August, you'd be buying back stock in the market. It's evident that you didn't.
Yes.
I just wondered what the reason for that was. Was it technical or was it, you know, a decision that you made that what was the background to the absence-
Okay.
of your buyback? Thank you.
Okay. First I will start with the second question because it's very easy. I think from the beginning when we announced that we will implement buyback in 2021, we mentioned very clearly that it will be done in Q4 and not in Q3. That's true that it was announced in July, so just before the vacation, but at that time it was very clear that it will not be implemented in August or in September, and so that will be implemented in Q4.
We do not have any technical issues except the fact that in October to be very clear, we do not, it's not possible for us to buy back our shares for obvious reasons, because given that we publish results today, there is a period, so more or less all the October months in which we cannot implement buyback. I confirm to you that, yes, it's a blackout period in October. I confirm to you very clearly that we will implement this $1.5 billion of buyback and that the program will be executed starting in the coming days or weeks.
End of this year you will see in our balance sheets or in our accounts this $1.5 billion of buyback implemented, executed.
Right. Okay.
the 12-
Before the Christmas holiday.
Sorry?
Before the Christmas holiday.
Yes, before. Yes. Yes. Regarding the price, to be very clear, the $12 per MMBtu we gave as a guidance for LNG prices. This is the price on our LNG we produce. Why we are able to give this guidance? Because of course, we know the different formulas used to sell these volumes. Just to give you a rough figure, the contracts are something like 80% with an oil index, long-term oil index, and 20% with gas, long-term gas or spot gas prices index.
That means that given that there is a timeline between 3-6 months in the different formulas, we know of course the prices for Brent for the main gas indicators. We are able to compute more or less the different formulas. This $12 per million BTU we indicated compared to the $9.1 per million BTU we benefited from in Q3 is the consequence of the different formulas on which our energy is sold. It does not take into account the trading activities and the additional value that the trading will be able to capture, mainly given the volatility in the markets.
Right. Do you have visibility on what [inaudible] playing out like in that part of the operation?
Honestly, once again, we do not give guidance regarding trading performance. Obviously it will depend on the evolution of our book or the volatility and the prices in Q4.
Okay. All right.
You can easily compute the portion of the iGRP result coming from our activity production, given that you have the volumes, the energy production, so you have the prices, so it's not very difficult to assess the reasonable path of the Q4 results. You have to take into account that of course the performance of trading was very good in Q3.
Sure. Okay. Thank you very much.
Thank you, John.
Thank you. Our next question comes from the line of Christopher Kuplent from Bank of America.
Yeah, thank you. Hi, Jean-Pierre. Just two quick questions. I know you're not going to tell me what the next board decision will be, but I just wonder how you're thinking around the attractiveness of your dividend. It's been flat on a quarterly basis in nominal terms for some time. Maybe you can remind us of your priority regarding growing that DPS, particularly now that your share count is starting to get reduced with the kickoff to your share buyback program. As a second question, again, I'm not expecting formal guidance, as I'm sure you know, but maybe you can help us understand a little bit the moving parts that your refining margins will be exposed to in Q4. How does your indicator, your European indicator capture the rising costs of CO2 gas and power?
Any color would be much appreciated. Thank you.
On dividend, you will not be surprised. I will not give you any guidance on growing dividend because, of course, it's a decision that's to be made by our board. What I can tell you to repeat, that we see dividend as a long-term component in our shareholder returns. It's a matter of trust once again, and what has been said last summer during the Investor Day is that this dividend increase will be supported by an underlying long-term cash flow growth. That's why we are very clear regarding the fact that our cash flow will grow by roughly $5 billion between 2021 and 2026.
That's this underlying cash flow growth that will support this dividend piece. On top of that's true that we obviously the Q3 was again a new proof of concept. We are able to leverage on the environment. We are committed to return the part of the surplus cash flow generated by the environment to our shareholders. That's why we're very clear. We gave clear guidance saying that up to 40% of the surplus cash flow above $60 per barrel will be returned to our shareholders. That's the rationale behind the $1.5 billion of buybacks that will be implemented before end of this year.
The next question, yes, for sure. Our indicator, the variable, the VCM capture the rising cost of energy because it's it reflect both in fact the refining environment, I would say through the spread between refined product and crude purchases. That's the first component in this indicator, the VCM. The second component, of course, is our operational performance. It's a matter of variable costs and of refining outputs. In this variable cost, of course, you have the energy costs, and particularly so the gas and all the CO2 costs.
Given the fact that this indicator takes into account the cost of energy, the decision was made in Q3 to make the restatements and to report VCM with restatements. Excluding the impact of the energy cost increase between Q2 and Q3 to better reflect, in fact, the underlying growth in refining margins.
To summarize in short, yes, VCM capture the rising cost of energy and CO2, but to give more clarity, in Q3, we decided to make a restatement to exclude the increase in relation with this cost of energy and CO2, and so to give a better understanding of the underlying refining margins.
Okay. Understood. Thank you, Jean-Pierre.
Thank you.
Thank you. Your next question comes from the line of Christyan Malek, J.P. Morgan.
Hi, Jean-Pierre, and good afternoon. Just two questions from my side, please. First of all, just, but mainly around the capital framework, but just firstly on the CapEx guide. It always starts like this. You start at the sort of middle of the range, goes to the top of the range, and all of a sudden we're seeing raised guidance. You mentioned short cycle CapEx, which absolutely makes sense in a firmer oil price environment. I just wonder, in terms of just how you think about, you know, dividend raise in the future, why it is that you've focused on CapEx, you know, basically raising CapEx over and above raising your dividend.
I know I've sort of perhaps potentially put you on the spot there with sort of only two options, but I just wanna know the thinking around allocating incremental free cashflow towards your CapEx relative to your cash return, particularly in this period of firmer prices. The second question, it sort of pertains to the third point, activism that we're seeing in Shell.
I'm clearly not gonna ask about that, but the just sort of lateral read-across is, you know, when you think about how to extract value or crystallize value within your own business in low carbon renewables, to what extent are you looking at these statements, listening to investors as you've been on the road to sort of think about realizing that value potentially earlier, expediting if you don't see that fully appreciated in the equity market? Thank you.
Regarding CapEx, I mentioned this additional $1 billion directly in line or directly linked to the reactivation of short cycle CapEx. It's just $1 billion, that means that of course we'll continue to be disciplined. By the way, it's within the range we gave, $13 billion-$15 billion. Considering the environment, we'll be close to the top high range rather than close to fifteen rather than close to thirteen. If the environment is good, that means that just to give you, and you know the figures, for an additional $10 per barrel in oil prices, we generate more than $3 billion of additional cashflow.
That means that if the environment is very good, it remains high, so above $60 per barrel, above $70, so we'll be able to generate, even considering this additional $1 billion, a reasonable amount of additional cash. Once again, this additional cash will be up to 40% return to the shareholder. That's why I do not see any change in the way we try to allocate the cash flow generated by our activity. CapEx, but once again, a disciplined way, just taking advantage of the environment.
Short cycle, obviously that was a part, a portion of the CapEx that we cut in 2020, in the middle of the crisis. Now that the prices are high, given that we have 1 billion oil equivalent reserves linked to this short cycle assets, is the right time to activate this asset. Once again, a disciplined way, just $1 billion out there. After that, we have demonstrated that dividend will increase but not linked to the environment, linked to the underlying cash flow growth.
We continue to de-leverage the company. We demonstrated over the last couple of quarters that we are able to de-leverage the company, so we are now below 18%. If the prices or if the environment continue to be high, of course we will continue with strategy. The objective being to anchor this gain below 20%. Once again, the share buyback will come to share additional values with our shareholders. Perhaps because I haven't mentioned that before in our CapEx allocation, we confirm that in 2022 we'll allocate something like 25% of the CapEx to renewable and electricity businesses, $3 billion.
With $3 billion, a disciplined way is enough to feed our growth and to meet the objective we have to have in operation 35 GW of renewable capacity in our portfolio by 2025. I'm not sure that I think that's clearly the DNA of TotalEnergies, and so we stick to this capital to this cashflow allocation. I don't know if I can add something that could convince you, but that's the way we think we should allocate our cashflow in the coming months or coming years.
Thank you. The second question on the third point, activism, just around capital value.
Obviously I will not comment on Shell. You know the strategy, so I will not repeat all what has been said in September. We definitely think that we will create value implementing our strategy, combining energy transition and shareholder returns, investing in particular in growing markets of renewable and power. So that's the model, our business model, we want to execute. In our view, it's the best way to create value in the long term for our shareholders. Thank you.
Thank you. The next question comes from the line of Bertrand Hodee from Kepler Cheuvreux.
Hello, Jean-Pierre. One question relating again on the LNG. Many thanks for giving us the guidance for the $12 per MMBtu for Q4. I try to make a kind of exercise for Q1 next year based again if oil price, let's say, stay at $80 for Q4 plus some. I would say particularly to spot LNG. Looks to me that if those assumptions are proved correct in terms of underlying macro environment, then we could look for above $14 per MMBtu in Q1. Have you done this exercise or can you
No.
Give us some clue.
You will be disappointed, Bertrand Toddy, I do not have the figure. We will enter into our budget 2022 exercise. For sure we will have the figure. Honestly, I haven't made the calculation. I don't know, of course you can try to anticipate because I give you the main assumption. The fact that 80%, 75-80% linked to oil prices, something like 15-20% to gas prices. And the difficulty is to clearly assess the time lag effect because depending on the contract, it varies from 3-6 months.
For sure in Q1, we benefit from the price increase in Q3 and in Q4, and we benefit from the high gas prices in Q3 and Q4. That's only what I can say. I do not have the figure.
Okay. Fair enough. I think, yeah, it was clearly directionally it looks.
Yeah. Directionally, yes. Given that the underlying component in the formula are on the upward trend, obviously, that should support high LNG prices in Q1. But honestly, I will not provide you with the figures because I do not have made the calculation yet.
Thank you, Jean-Pierre.
Thank you, Bertrand.
Thank you. The next question comes from the line of Martijn Rats from Morgan Stanley.
Yeah. Hi. Hello. I had two questions, if I may. First of all, I was very intrigued by the news that Total shut down the hydrocracker at the Antwerp refinery. The reason why that is so intriguing is that the headline refining margins in Northwest Europe, including hydrocracker margins specifically, are rather good. They've improved a lot, and they're historically very high levels. That then sort of raises the sort of, you know, the question following on sort of Chris' question earlier, that the increased cost of natural gas and hydrogen in the refinery actually is so large that it does trigger shutdowns of hydrocracking units for economic reasons.
That therefore we should think about a very significant erosion of the sort of headline refining margins. I was wondering if you could elaborate a little bit on the shutdown of the hydrocracker in Antwerp for economic reasons and sort of how that came about. The second question I wanna ask does relate to the dividend, and actually, I think the third quarter is never sort of quite the forum to really talk about the dividends, but given that quite a lot of others have asked about it, and you've said a few things, I totally understand that the dividend is linked to the long-term outlook for cash generation, but that makes a lot of sense.
By then not growing the dividend, you're sort of indicating to us that you're also seeing not a lot of increase in long-term cash generation. In the end, it becomes very hard for the share price to rally meaningfully if there is no increase in the long-term prospects for cash generation. I just wanna make sure that I'm sort of trying to understand the messaging and the signaling behind what you're saying. Are you indicating to us that actually you're not seeing an awful lot of improvement in long-term cash generation?
No, I think we convey exactly the opposite message in September. We have a clear visibility regarding the cash flow growth in a constant environment. We gave figures in a $60 per barrel environment and with a different sensitivity, by the way, $60-$80 per barrel. That's exactly the contrary. Given that we have this strong visibility regarding cash flow, not linked to the environment, we are able to envisage to grow the dividend. But once again, we see a dividend as a long-term component in our shareholder returns. It's a matter of trust between us and our shareholders.
We demonstrated that, given this policy, we decided not to cut the dividend in 2022 in the middle of the crisis. That's the long-term component once again of the cash flow return to our shareholders. On top of that, if we are able to generate additional cash flow benefiting from high oil or gas prices, of course we'll do. That's the rationale behind, once again, the shareholder highlights. That's not why, because we are not confident regarding our long-term cash flow growth.
It's a matter of having a long-term component and a short-term component in or directly linked to the environment. Concerning hydrocracker, honestly, I do not have this information, so I suggest that my team call you back to discuss that with you directly.
Okay, thank you. That's great. Much appreciated.
Yeah. Yeah.
Thank you. The next question comes from the line of Lucas Herrmann from Exane BNP Paribas.
Jean-Pierre, thanks very much for taking the questions. I want to touch again on IGRP and then also move on to balance sheet. IGRP, will you just remind, like, if I look at what's happened to your LNG price Q3 versus Q2, and think about what you're saying about the LNG price, Q4 versus Q3, the increases are not dissimilar. At the operating level, which I appreciate is biased towards refining, sorry, biased towards trading, your profits have increased $500 million, you know, over the quarter. Why should I not think that the operating profit in Q4 will not be towards $500 million higher, if not more, you know, as a consequence of the prices that you're already highlighting before I even think about what's happening with the liquefaction business? That was the first question.
The second is very simply, when does your balance sheet become lazy? Your gearing is improving at a rate of about 1%, you know, a quarter. The environment's obviously pretty favorable. The outlook for cash flow, I'd say, is similarly favorable. At what point do you say, "Okay, less than 20%, but we're now at 15, 14, 13, 12," and start to. What happens with cash then?
Okay. For the last question regarding gearing, we do not have any magic figure regarding gearing. What is clear is that we, if possible, want to deleverage the company and it will be the case if, for obvious reasons, the environment remains high. It's the best way to be prepared in case of a new low cycle. Regarding LNG, you have the guidance for what we anticipated as being the prices for our LNG production.
On top of that, once again, you will have the trading results, able to leverage on our global position and volatility of the market. I don't know if you, when you mention the $500 million, if you take into consideration all the IGRP businesses or only the trading parts of the segments. It's not clear in your questions, if I may.
I'm just looking at what I can see, which obviously is the increase in operating profit, given that you don't split the operating profit between, you know, LNG marketing, between renewables and between the other, you know, hydrocarbon businesses that run through that line.
Yes, you're right. We, given that for renewable electricity
Okay, that went nowhere.
... you have the capacity, and so you and we gave the result, by the way.
Yeah
It's not very difficult to assess the contribution in terms of results for the IGRP results on a quarterly basis. This quarter, I gave an indication regarding the trading contribution. I think we gave a lot of figures to enable you to make your calculations. You have the prices, the LNG prices, you have the volumes. You know, you know more or less the trading baseline taken into account. Once again, we consider that in Q3 the trading performed particularly well.
You're not prepared to give us any idea of what the LNG volumes that you have available to trade in your portfolio might be? Obviously, if I look at what comes into your portfolio per your figures and what you're committed to deliver to customers per long-term contract in your portfolio, I can see a very large difference between those two numbers, which historically led to us questioning the extent to which you could add additional facility. It was a number that ran at 15 million tons.
You have the global LNG sales, and you have the part coming from our equity production in the press release. Again, these figures.
Okay. Jean-Pierre, thank you.
Thank you, Lucas.
Thank you. The next question comes from the line of Oswald Clint from Bernstein.
Jean-Pierre, thank you. I wanted to ask about corporate renewable electricity PPAs and some of the stuff you're doing here with Air Liquide and Amazon recently. You should, you know, obviously you give a weighted average PPA price, and we should use that in some levelized cost of production for. But, you know, are these Air Liquide, Amazon type projects, I mean, are they more attractive, more profitable than, say, certainly, you know, intragroup PPAs you do between Spain and France Total or some, you know, some of the stuff you're doing in India? Should we be thinking differently across these different contracts and PPAs? That's the first one.
You want to know all the secrets, so as you can imagine, it's confidential information. Honestly, we gave already a lot of information because you have in the press release on a quarterly basis, you have the average PPA on existing facilities, on the facilities, the assets under production. By the way, PPA the price for assets under development. For sure, you see, it's obvious you have a decline in France in terms of PPA, but it's directly linked to the fact that the costs are declining as well. It's a matter of parallelism between cost and PPA price.
What I can tell you is the rationale behind this corporate PPA is to diversify, in fact, our counterparty risk, not to have only a PPA with utilities or with state bodies. I will not disclose for obvious reason the prices we negotiated with Amazon and Air Liquide.
Okay, that's clear. My second question was around the short cycle CapEx. Some of it you said was going to Nigeria. Obviously, during the summer, we had this PIB bill finally signed in Nigeria. As you put that CapEx to work next year, are the returns on this better post the PIB being signed than they would've been, say, two years ago as you put money to work in Nigeria, please? Thank you.
Well, you know, I mentioned Nigeria because it was of course an example. We identified the different assets we have in our portfolio. We have for obvious reason short cycle assets in Nigeria because it's in field oil that can be easily connected to existing facilities. The point I will not give you, I can give you figures because on this type of asset, you have a profitability 40, more than 30%. I understand your question, but honestly, our objective for us is to identify these short cycle assets, to select the best profitable ones, and to execute on time and on budget the CapEx.
Classically on a short cycle CapEx, you benefit from a very strong return because it's developed on marginal investment, and you just have to pay some cost in relation with connections.
That's very clear. Thank you.
Thank you. Your next question comes from the line of Biraj Borkhataria from RBC.
Hi there. Thanks for taking my question. I want to ask a question on Mozambique. You've obviously paused the project because of the security concerns, but it looks like the partners in Area 4, particularly ExxonMobil, is undergoing a strategic review with some new board members, and they have cited some concerns around the project. I was wondering, you know, one of the key benefits of putting those two projects together is economies of scale and shared infrastructure and things like that. If under the scenario that the Area 4 project doesn't go ahead, where does that leave Total's project? Would you still be looking to push ahead if and when the security situation allows? And then the second question is on a different topic.
You know, you have a fairly sizable electricity and gas retail business now in Europe, and we've seen some very volatile markets. When you structure your sales, are you typically fully hedged or do you take a market risk? I'm just wondering because a number of companies have reported fairly substantial losses of being on the wrong side of these volatile markets. Thank you.
Regarding Mozambique, what I can confirm to you is that of course we remain fully committed to develop this project. The resources coming from Area 1, but only of course when the condition will allow. We need for obvious reason a stable and a peaceful environment to be able to remobilize our staff, and it's not possible at present time. We will see if it will be possible next year in 2022. If it's the case, production could be there in 2026, exactly what we indicated in September during the Investor Day. We are committed to this project. The gas is still there, of course.
Now we have to be patient and see how the situation will improve in the coming months. Regarding our hedging strategy, well, that's true that most of LNG portfolio is hedged. I will not give you all the details. I think in February we will give you more details regarding our sensitivity and regarding this subject. I notice, you're right, that some of our peers have taken significant losses, but for us, what's important as well is to be in a position to clearly assess the availability of the LNG volumes in the future to implement the right hedging strategy.
It's exactly what has been done in Q3, and so you see the impact in our results.
Sir, I was asking about the retail side of electricity, you know, with your sort of 6 million customers you have, whether you take any market risk on there.
You mean, for the electricity that we sell to final customers?
Yes, essentially that, yeah.
Yes. The answer is yes.
Okay. Understood.
Thank you. The next question comes from the line of Anish Kapadia from Pallasite Ventures .
Good afternoon. I had a question on the LNG business. Given the environment we're seeing at the moment, I know there's clearly higher buyer appetite to sign longer term contracts. We've seen a number of deals signed in the market. Just wanted to get a little bit of an update in terms of your pre-FID LNG projects, kind of mainly thinking about the US and PNG in terms of you know, how you're thinking about those and, you know, could we see some kind of faster progression in terms of getting to FID? And the second question was on your chemicals business, you know, a lot of your peers will give a breakout of the chemicals contribution.
I was just wondering if you could give us some sense of, so far this year, what's been the cash flow or the earnings impact in terms of chemicals out of your total result? Thank you.
The energy business. As you know, we are always very vocal regarding the fact that we see the gas as an area of the transition, and particularly LNG. We have very good assets in our portfolio. That's why we do not need to be active on the M&A side to capture additional assets as far as LNG is concerned. We have PNG LNG project in our portfolio that could be sanctioned in the coming years. You have Cameron extension as well. The Cameron asset that we acquired when we acquired the Engie LNG portfolio, the asset operated by Sempra.
On top of that, to feed the LNG growth beyond 2025, we have access to the LNG resources in Russia, so with Novatek, with the possibility of launching additional development, additional trains. In 2024 we would have the Arctic LNG 2 production that will come on stream. I have omitted ECA, so Costa Azul project in Baja California, Mexico, who is operated by Sempra as well, very well positioned to supply the Asian markets. All in all, we already mentioned Mozambique project.
The sanction that has been taken for the two first trains, but there is plenty of resources in Mozambique. When the condition will be there, we are not in a hurry, of course, we could sanction additional trains there as well. No worry, we have enough resources in our portfolio to feed our growth beyond 2025, and the 50 million tons of sales we indicated by 2025. For chemicals, I think, it's true that petrochemicals was the main contributor in the Q4 results as far as R&C is concerned. R&C is what we are refining, petrochemicals plus trading.
That's the main contributor. We do not disclose separately the results of refining & chemicals and trading. For sure, the prices, the margin for petrochemicals were particularly high in the Q3, both by the way in the U.S. and Europe, supported by the economic recovery, but we do not provide separate figures.
Okay. Thank you.
Thank you. The next question comes from the line of Henry Tarr from Berenberg.
Hi, and thanks for taking my questions. Two really. One is, and apologies if I missed it in your early statements, but just some of the main moving parts around the production as we look into 2022 would be great.
The second question is just on the ACC joint venture to build the battery factories and the entry of Mercedes into that joint venture. Could you just talk us through the sort of roadmap for the joint venture and then whether Saft and Total is kind of leading on the battery development or whether other technologies are gonna be involved there? Thank you.
You have to be patient. You have to wait, I think till February or March to have the production guidance for 2022. In September, we gave global trends as far as production is concerned, giving the 2025, 2026 production figure. But be patient, we'll provide you with the figures very soon. For ACC, that's true that now we have Mercedes-Benz as a new shareholder in ACC. One third of Mercedes, one third of Stellantis, and one third TotalEnergies. The objective is clear for this joint venture.
It's to provide batteries by 2030 to almost have to be equivalent on a yearly basis of 2.5 million cars. That means that it will represent more or less 10% of the European market. By improving the entry of Mercedes within the company, we have increased the capacity of ACC above 120 GWh of production by 2030. The technology that we will use is lithium-ion for this ACC joint venture. Each partner will bring its own expertise.
Saft of course, as far as battery technology is concerned, but also Stellantis and Mercedes for the EV technologies. That is the main driver behind this joint venture to attract the different expertise in the joint venture.
Okay, thanks.
Thank you. The next question comes from the line of Jean-Luc Romain from CM-CIC Securities.
Good afternoon. Thank you for taking my question. It relates to the renewable power production. I was wondering why in the first quarter it was stable compared to the second, while your installed capacity had actually increased? That's the first question. The second one is on the investment in charging points on the motorways. The EUR 200 million you plan to invest next year, which is quite impressive, how many charging points does this represent?
The question regarding the annual capacity, the change between Q3 and Q2, that's well, it's the main driver is India, in fact, the fact that as I mentioned in my speech, I think, yeah, because I have to say that before. In January this year, we acquired 20% of Adani Green. It's one of the biggest renewable developers worldwide. In Q3, Adani Green acquired additional portfolio of 5 GW in India. Given that we have 20% of Adani Green, it contributes to an additional 1 GW globally in our renewable portfolio.
As far as the developed capacity are concerned, it's less than that, because of course this 5 GW of additional capacity, they are not fully developed. It's more or less 0.5 GW of additional installed capacity directly linked to this acquisition. The balance is coming from other assets developed by Total or developed directly. Charging points. I'm not sure to have really understood your questions regarding charging points.
Actually, you announced you will invest EUR 200 million.
Oh, yes.
next year for 150 stations. Is this
Yes.
150 charging points, or is it more than one charging point per station, actually?
It's more than one. It's 2-3 depending on the stations. It's part of the global strategy to have in our operation 150,000 charging points by 2025, mainly in. We were awarded in Paris, in London, now in China as well, with a Chinese partner, in Singapore. It's part of the strategy. Of course, by this announcement, we start to support the growth of the electric mobility in France.
that means that in Europe globally by 2025, we will have something like 1,500 HPC charging points. It's part of this global strategy.
Thank you very much.
Thank you. Your next question comes from the line of Paul Cheng from Scotiabank.
Thank you. Good afternoon. Jean-Pierre, two quick questions. One, with the rise in the natural gas in Europe, can you give us some kind of sensitivity that every $1 per MCF change, how that impact on the OpEx in your refining portfolio per barrel? Also how it impact on the refining margin capture per barrel, given that natural gas will be used to generate hydrogen for the hydrotreating and hydrocracking operation, and also that for the electricity and power, I suppose that in the OpEx. That's the first question. The second question, I want to see if there's any additional news on surina me you can provide.
I think the last year, the hope was, you could come on stream in 2025, and in September, I think Patrick was saying that there's a bit of the complication. Is there a new timeline, you guys have in mind right now? Thank you.
Obviously, we do not give the sensitivity regarding the increase in MVP for refining margin. What we give is the sensitivity directly linked to our production. That's the $250 million of sensitivity we gave our downstream sales for an increase of $1 per million BTU, but we do not provide this figure for refining margins. On Suriname, we have a lot of exploration targets to be drilled in the near future. We'll have to continue to appraise in parallel the discoveries with, by the way, two rigs in operation. We will communicate after that when the results of the campaign have been analyzed and thereafter.
Okay. Can I ask a final question on the fourth quarter?
Yes, please go ahead.
Looks like, to meet your full year CapEx, fourth quarter is going to see a pretty substantial increase in the CapEx comparing to the third quarter. Where is the incremental CapEx in the fourth quarter going to be applied to?
Obviously.
For comparison.
The figure I have in mind is the end of September. The figure is $9 billion. That mean that, given that I gave you a figure and I gave you the indication that, for 2021, the CapEx will be close to $13 billion, that mean that in Q4, we'll have something like $4 billion dollar of net CapEx spent over Q4. Traditionally, Q4 is more heavy in fact in terms of CapEx. There is nothing particular in Q4 that is anticipated in this $14 billion dollar figure.
You're saying it's almost.
We stick to the guidance we gave for CapEx globally, allocating more or less 50% of the CapEx to maintenance activities and the balance 50 to growing activity, LNG and renewable. That mean that in renewable, yes, we have something like $3 billion globally over 2021, as far as CapEx are concerned.
All right. Thank you.
Thank you. Your final question comes from the line of Jason Gabelman from Cowen.
Hey, thanks for squeezing me in.
Yes, absolutely.
I wanted to ask two quick questions. First, going back to iGRP , and I actually wanted to ask about the renewables and electricity business. I know the big energy companies that are investing in renewables suggest that there's integration value from that renewables business being in the larger entity, and it seems like during 3Q, during a period of volatile power and gas prices, you could have seen some of that integration value emerge. I'm wondering if you could give any details on if you generated any excess earnings in that renewable and power business as a result of the volatile commodity environment. If not, do you need to kind of get that business to a minimum capacity level or add some different assets in order to realize that integration value? I have a follow-up. Thanks.
For clarity, the additional value, reasonable part of the value in that sector, will come from the integration and from the trading. What we have in mind is, and I think it was clearly stated in September, is to be able to fully benefit from the volatility. In that market, of course, you have a lot of volatility, intraday volatility as well. You have to have a skillful electricity trader. That's exactly the model we want to implement. We will double, more or less, the electricity trading in the near future to benefit from what you call the integration.
To be able to capture the volatility. We already have a team, of course, that we have is to develop the team. Take into account the fact that this business is very local. It's different from oil or gasoline that is more global and more worldwide. We have to develop local teams as well to benefit from the volatility in electricity markets. Do you have
Okay. Yeah.
Any other questions? Bill?
Yeah. I have one follow-up. Thanks. Just on the $1 billion increase in short cycle CapEx, can you discuss how much production that'll bring on, when that production will come online, and then the cash flow benefits from at your kind of planning commodity prices? Thanks.
As I already mentioned, we are well doing the design, and we'll give you some more details in February or in March. Of course, it will contribute to production. Because when you put on stream, between the decision of sanctioning short cycle assets and the first production is between 12-18 months. For sure you will start seeing the impact of the decision in the coming quarters.
Okay. Thanks a lot.
Thank you. Thank you. I think it was the last question.
That was the final question, sir. Thank you.
Thank you very much to all of you, and I hope you will have a good day.
Thank you. Ladies and gentlemen, that does conclude your call for today. Thank you all for participating, and you may now disconnect.