TotalEnergies SE (TTE) 2021 Q3 法說會逐字稿

Ladies and gentlemen.

Thank you for standing by, and welcome to TotalEnergies' Third Quarter 2021 Results Conference Call.

(Operator Instructions) I must advise you that this conference is recorded today, the 28th of October 2021.

I would now like to hand the conference over to Mr. Jean-Pierre Sbraire, CFO of TotalEnergies.

Please go ahead, sir.

Thank you.

Good afternoon or good morning to all of you.

So let me say first that I hope you and your closed 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're currently witnessing and that would come back to a normal life in the near future.

So demand recovery continues to drive energy prices higher this quarter and particularly in the case from Asia.

Our natural gas price valuation increased by 42% to $6.2 per million BTU in the third quarter.

And our average LNG sales price increased by almost 40% to $9.1 per million BTU.

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.

And the cash flow, the debt adjusted cash flow increased by nearly 25% to $8.4 billion.

These strong first quarter results show that our multi-energy model and notably our position as a world leader in LNG is capturing the full benefit of the environment, thanks to the outperformance of our gas and LNG trading activities, which we're 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, so Iara, and Zinia 2 in Angola.

This should continue and the outlook calls for fourth quarter production to be in the range of 2.85 million to 2.90 million barrels of oil equivalent per day.

Let's have a look at the segments now.

iGRP, integrated Gas, Renewables & Power segment reported record high results for the fourth quarter.

Adjusted net operating income of $1.6 billion represent an increase of 84% from the previous quarter and more than 5x from the same quarter a year ago.

Operating cash flow before working capital changes is $1.7 billion, an increase of 90% from the second quarter and 2.5x the same quarter last year.

Cash flow was impacted by working capital outflows of $2.1 billion due to variations in margin growth related to hedging contracts in the context of highly volatile gas and electricity markets.

At this margin, all 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 link 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 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.

As you see, 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 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 & Chemicals results, thanks to margins that remained high, particularly in the U.S. We fully benefited in the dynamic environment from our refining and petrochemicals integrated model.

Marketing & Services confirmed its return to precrisis level results, notably supported by the recovery in network sales, while aviation is still 40% below 2019 average.

An increase in fuel amounts from the sector is beginning to materialize.

As you see, net operating income from the combined downstream Refining & Chemicals plus Marketing & Services rose to $1 billion, an increase of 12% compared to the previous quarter and nearly 3x 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 third quarter last year.

Finally, some comments at the company level, mainly in terms of cash flow allocation.

As you know, we are maintaining our discipline as planned at the beginning of 2021.

Our net investments were $1.9 billion in the third quarter, bringing up to $9 billion for the first 9 months, which is in line with our target of close to $13 billion for the year.

We plan to accelerate about $1 billion of short-cycle CapEx to benefit from high oil prices, so our net investment in 2022 will probably be towards the top of the $13 billion to $15 billion range.

In the third quarter, we faced working capital build of $2.4 billion in the third quarter, mainly due to iGRP's $2.1 billion change in margin growth, 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 third quarter.

And return on average capital was, again, double-digit figure at 10% and return on equity at 12%.

Including the payment of 2020 final dividend of EUR 0.66 per share or $2.1 billion cash-out, 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 buyback in the fourth quarter, and this will lead to a cash payout of around 35% for the year.

Our third 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 energy-rich 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.

(Operator Instructions) And your first question comes from the line of Irene Himona, Societe Generale.

Jean-Pierre, I had two questions, both in iGRP.

Firstly, you obviously pointed 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?

And then secondly, you had a $940 million net acquisition.

Can you remind us which particular asset that was, please?

Okay.

Irene, yes, concerning iGRP results, so you know that we do not disclose the contribution separately, but I think that you can approximate trailing contribution because we provide LNG price and production, by the way, within iGRP.

So 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 1 indication.

So taking into account this overperformance, so our trading delivered about $0.5 billion of results this quarter, so benefiting again from this favorable environment.

On the second question, yes, concerning a net acquisition, so the main contribution of this -- in this figure is the deal we signed with GIP in Australia on an asset called Gladstone LNG.

So we have GIP as now a minority interest in the asset and they will pay tolling and in exchange of this tolling, they pay downpayment of $750 million, something like that.

So that's the main contribution out of this $951 million of acquisition in Q3 for iGRP.

Your next question comes from the line of Michele Della Vigna from Goldman Sachs.

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 with the mark-to-market 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?

So once again, I gave the figures concerning the contribution of our gas and LNG trading to iGRP results this quarter, so above $0.5 billion.

So taking into account the complex and the volatility we benefited during the Q4.

You have the prices, the average prices for LNG, so the equity production, that is sold on the market directly through the third party, through our trading.

And so you can make your math and so 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 growth, as I mentioned during the speech, and the fact that we have a cash margin growth for iGRP above $2 billion, so $2.1 billion.

That's for sure will reverse in the near future.

Your next question comes from the line of Lydia Rainforth from Barclays.

Jean-Pierre, 2 questions, if I could.

One, just on -- in terms of the $1 billion of extra short-cycle CapEx that you've been talking, whereabout is that going?

And also are you seeing any impact on inflation at this side of cost pressure?

And then the second question, just would like to -- obviously about the announcements you made about the renewables, the hydrogen side.

Are you actually seeing a demand for more of these partnership?

And is that accelerating?

Okay.

So short cycle, so as I mentioned already, so in September or in February, we gave a guidance for the CapEx 2022-2025 in a range between $13 billion to $15 billion.

So now considering particularly the oil prices, we only say it, of course, to mobilize short-cycle CapEx, so mainly field wells in Western African countries, for example, so Nigeria, Angola.

And so this -- after this $1 billion of additional CapEx linked directly to this short cycle, you -- that's why I indicated that in 2022, the CapEx should be close to $15 billion instead of -- the high -- top range $13 billion to $15 billion.

So we are at the present time finalizing work program for this 2022 CapEx.

And so clearly, we have a clear focus to deliver with the short-cycle productions and identifying future opportunities.

As far as inflation is concerned, so at present time, honestly, on -- you have to remember our strategy regarding FID.

So when we sanction projects.

So when we sanction projects, for example, in E&P, which is also the case for LNG or for renewable projects, we try to lock-in with us for signing EPC contracts.

So 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.

So in the -- for future projects, it will be the case for renewables, it will be the case for E&P as well.

So we will see.

We'll continue, of course, to be very disciplined.

And so to ensure that when we sanction projects, the projects are able to deliver the profitability that's in line with our guidance.

For sure, at present time, we, in renewable -- for example, renewable activity, we will see in the next future inflation.

For E&P, I don't know, but yes, I'm not, of course, I am being cool because, of course, all the E&P, all the major (inaudible) reduced honestly the investment.

So no worries regarding this sector activity.

Could be a bit different to what we see from -- over deepwater activity.

But at the present time, no clear indication that in our -- in the projects where we have already sanctioned.

For hydrogen, for sure, so we probably will have more demand for hydrogen projects.

So we communicated in the Q3 around this hydrogen subject on the fact that we want to decarbonize the hydrogen use within our refineries.

And the last example I have in mind in the partnership we've signed with Air Liquide, so decarbonize hydrogen used in our Normandy refinery.

So it's one example.

But of course, we have the clear plan to decarbonize 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.

And so we will -- with visibility of investing $1.5 billion in -- through this fund I think at the present time.

We already have $0.8 billion or something like that already in the fund.

So it's a partnership with Vinci, it's a partnership with Air Liquede also, just to mention French entities, but also, of course, we will attract worldwide companies interested in these type of investments.

So just to give you two main -- two very recent examples regarding hydrogen partnership.

Your next question comes from the line of Jon Rigby from UBS.

Jean-Pierre, 2 questions.

Just to go on to the iGRP number again on 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 supernormal 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 that some of your competitors don't.

The second question is, if my memory serves me right, is 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.

And it's evident that you didn't.

And I just wondered what's the reason for that?

Was it technical or was it a decision that you made that -- what was the background for the absence of your buyback?

Okay.

So 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 what it was announced in July, so just before the vacation.

At that time, it was very clear that it will not be implemented in our view before September.

So that will be implemented in Q4.

So 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 reason because given that we published results today, there is period, so all -- more or less all the October month in which we cannot implement buyback.

So I confirm to you that, yes, it's a blackout period in October.

So I confirm to you very clearly that we will implement this $1.5 billion buyback and that the program will be executed starting in the coming days or weeks.

And so end of this year, you will see in our balance sheet or in our accounts, this $1.5 billion of buybacks implemented -- executed.

The -- sorry?

Before the Christmas holiday.

Yes, before -- yes, yes.

So regarding the price, so to be very clear, the $12 per million BTU we gave as the guidance for LNG prices is the pricing on our LNG, so the LNG we produce.

And so why we will 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 oil index, long-term oil index, and 20% with gas, long-term gas or spot gas prices index.

So that means that -- and given that there is time line between 3 to 6 months in the different formulas, we know, of course, the prices for Brent for the main gas indicators.

So we are able to compute more or less the formulas, the different formulas.

And so this $12 per million BTU, we indicated compared to the $9.1 per million BTU we benefited from -- in Q3 in the consequence of the different formulas on which our LNG is sold.

So it does not take into account the trading activities or the additional value that the trading will be able to capture mainly, given the volatility in the market.

Right.

And do you have visibility on what 4Q is playing out like in that part of the operation?

Obviously, once again, we do not give guidance regarding trading performance.

And obviously, it will depend on the evolution of our book, of the volatility and the prices in Q4.

But you can easily compute the portion of the iGRP results coming from our equity production given that we gave -- you have the volumes, the LNG production.

So you have the prices, so it's not very difficult to assess a reasonable part of the Q4 is in fact -- you have to take into account that, of course, Q3 was the very -- the performance of trading was very good in Q3.

Your next question comes from the line of Christopher Kuplent from Bank of America.

Jean-Pierre, just 2 quick questions, and I know you are 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 EPS, particularly now that your share count is starting to get reduced with the kickoff to your share buyback program?

And 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 during Q4, how does your indicator -- your European indicator capture the rising costs of CO2 gas and power?

Any color would be much appreciated.

Okay.

So on dividends, so you will not be surprised, so I will not give you any guidance on growing dividends 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 cost once again.

And so what has been said in September, during the Investor Day, is that this dividend increase will be supported by an underlying long-term cash flow growth.

And so we -- that's why we are very clear regarding the fact that our cash flow will grow by roughly $5 billion between 2021 and 2026.

So that -- this underlying cash flow growth, that will support this dividend thing.

And so on top of that, let's call that we obviously entered Q3 well, again, a new concept of proof.

We are able to leverage on the environment.

And so we were committed to return 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%, sorry, will be returned by -- will be returned to our shareholders.

And so that's the rationale behind the $1.5 billion of buybacks that will be implemented before end of this year.

So the next question, yes, for sure, so our indicator, the variable, the VCM, capture the rising cost of energy because it reflects both, in fact, the refining environment, I would say, to the spread between refined products and crude purchases, so that's the first component in this indicator, the VCM.

And the second component, of course, is our operational performance.

And so it's a matter of variable costs and of refining products.

And in these variable costs, of course, you have the energy cost and particularly, so the gas or the CO2 cost.

Given that, given the fact that this indicator take into account the cost of energy, the decision was made in Q3 to make restatement and to repost this again with the restatement.

So excluding the impact of the energy cost increase between Q2 and Q3 to better reflect, in fact, the underlying growth in refining margins.

So to summarize, in short, yes, VCM capture, 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 we discussed of energy and CO2 and so to make restatement and to give a better understanding of the underlying refining margins.

Your next question comes from the line of Christyan Malek from JPMorgan.

Jean-Pierre, just 2 questions from my side, please.

First of all, just maybe around the capital frame, but just firstly, on the CapEx guide.

It always felt that you start with sort of a little of the range, goes to top of the range and all of sudden we're seeing raised guidance.

And you mentioned short cycle CapEx, which absolutely makes sense in the a certain oil price environment.

I just wonder in terms of just how you think about dividend raise in the future, why it is that you've focused on CapEx, basically raising CapEx over and above raising your dividend.

I know I should have potentially put you on the spot there with sort of early two options.

But I just want to know the thinking around allocating incremental free cash flow towards your CapEx relative to your cash return particularly as you know in this period of standard prices.

And the second question is sort of pertains to the third point, activism that we're seeing in Shell.

And I'm clearly not going to ask about that.

But just sort of lateral read across it is 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 you're expediting if you don't see that fully appreciated in the equity market.

Okay.

So regarding CapEx, so I mentioned this additional $1 billion directly in line or relatively to the reactivation of short cycle CapEx.

So I would say just $1 billion.

So that means that, of course, we'll continue to be disciplined.

And by the way, it's within the range we gave $13 billion to $15 billion.

So just the fact that considering the environment, so we will be close to the top high range rather than -- close to $15 billion rather than close to $13 billion.

If the environment is good, that means that just to give you -- as you know the figure, so for additional $10 per barrel in Brent prices, we generate more than $3 billion of additional cash flow.

So that means that if the environment is very good, there is -- it remains high, so above $60 per barrel, above $70.

So we'll be able to generate even considering this additional $1 billion reasonable amount of additional cash.

And so once again, this additional cash will be up to 40% return to the shareholders.

So that's why I do not see any change in the way we try to -- we plan to allocate the cash flow generated by our activity, so CapEx, but once again, in a disciplined way, just taking advantage of the environment.

Short cycle, obviously, that was the portion of the CapEx that we cut up in 2020.

In the middle year, the prices -- so now that the prices are high, you know that we have $1 billion liquid balance reserves linked to this short cycle assets is the right time to activate this buyback.

Once again, as indicated, it was just $1 billion.

And after that, we have noted that we -- that dividend will increase, but not linked to the environment linked to the underlying cash flow growth.

We'll continue to deleverage the company.

So we demonstrated over the last couple of quarters that we are able to deleverage the company.

So we are now below $18 billion -- sorry, 18%.

So either prices or the environment continue to be high, of course, we will continue with strategies, with the ability being to anchor this range below 20%.

And once again, the share buyback will come to share additional values with our shareholders.

But because I haven't mentioned that before, in our CapEx allocation, we confirm that in 2022, we will allocate something like 25% of the CapEx to renewable and 2C business needs, so $3 billion.

And with $3 billion, a disciplined way is enough to feed our growth and to meet the objective we have -- to have in operation 35 gigawatt 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 cash flow allocation.

I don't know if I can add something that convinces you, but that's the way we think we should allocate our cash flow in the coming months or coming years.

And the second question on the third point, activism just around crystallizing value.

Honestly, 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 can -- 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, and in our view that's the best way to create value in the long term for our shareholders.

The next question comes from the line of Bertrand Hodee from Kepler Cheuvreux.

Jean-Pierre, one question relating again on the LNG.

So many thanks for giving us the guidance for the $12 per Mbtu for Q4.

I tried 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, uptick linked to spot LNG.

It looks to me that if so the assumption proved correct in terms of underlying macro environment, then we could look for above $14 per MBtu in Q1.

Have you done this exercise or can you probably give us some clue...

No.

You will be disappointed, Bertrand.

So I do not have this figure.

Also, we will enter into our budget 2022 exercise.

So for sure, we'll have the figures, but honestly I haven't made a calculation.

I don't know -- so, of course, you can try to anticipate because I give you the main assumption.

So the fact that 80% -- more or less 75%, 80% linked to oil prices, 20-something -- like 15%, 20% to gas prices.

And the problem is to around -- the difficulty is to clearly assess the time lag effect.

So depending on the contract, it varies from 3 to 6 months.

But for sure, in Q1, we'll benefit from the Brent increase in Q3 and in Q4, and we benefit from the high prices, the high gas prices in Q3 and Q4.

That's only what I can say, so I do not have anything else.

Okay.

Fair enough.

But I think directionally it looks like...

Yes.

Actually, yes, given the underlying components in the price -- the formula are under the poor trend.

Obviously, let just support high LNG prices in Q1.

But honestly, I will not provide you with a figure because I did not have made the calculation yet.

The next question comes from the line of Martijn Rats from Morgan Stanley.

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.

And the reason why that is so intriguing is that the headline refining margins in Northwest Europe, including hydrocracker margin specifically, are rather good.

They've improved a lot, and they are historically very high levels.

So that then sort of raises the sort of 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 and that, therefore, we should think about a very significant erosion of the sort of headline refining margin.

So I was wondering if you could elaborate a little bit on the shutdown of the hydrocracker and Antwerp for economic reasons and sort of how that came about.

The second question I want to ask does relate to the dividend.

And actually, I think the third quarter is never sort of quite deformed really to talk about the dividends.

But given that quite a lot of others have asked about it and you said a few things, I do want to raise this point.

I totally understand that the dividend is linked to the long-term outlook for cash generation, but that makes a lot of sense.

But 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.

So I just want to 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 are not seeing an awful lot of improvement in long-term cash generation?

No, I think we convert the opposite message, it's a number.

So we have a clear visibility regarding the cash flow growth in a constant environment.

So we gave figures in a $50 (inaudible) environment and in -- and with the different sensitivity by the way, $60, $80 (inaudible).

So that is contrary.

So given that we have this strong visibility of earning cash flow, not clean 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 course, between us and our shareholders.

We demonstrated that, given this policy, we decided not to cut the dividend in 2020 in the middle of the crisis.

So that's the long-term component, once again, of the cash flow return to our calendar on top of that to ease.

We are able to generate additional cash flow benefiting from high price -- oil and gas pricing.

Of course, we do that.

That's the rationale behind.

Once again, (inaudible).

So that's not we should -- why we are not confident regarding our long-term cash flow.

It's a matter of having a long-term component and a short-term component directly led to the environment.

Concerning constant hydrocracker, honestly, I do not have this information.

So I suggest that my team call you back to detail that with you directly.

The next question comes from the line of Lucas Herrmann from Exane.

I want to touch again on iGRP and then also move on to balance sheet.

iGRP, can you just remind -- 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 bias towards refining -- sorry, bias towards trading, your profits have increased $500 million over the quarter.

Why should I not think that the operating profit in Q4 will not be towards $500 million higher, if not more, the consequence of the prices as you're already highlighting before I even think about what's happening with the liquefaction business?

That is the first question.

And the second is very simply, when did your balance sheet become lazy?

Your gearing is improving at a rate of a short percent a quarter.

The environment is obviously pretty favorable.

The outlook for cash flow, I'd say, is similarly favorable.

At what point you say, okay, less than 20%, but we're now at 15%, 14%, 13%, 12% and start to -- what happens to cash then?

Okay.

But for the last question regarding gearing, so we do not have any magic figure regarding gearing.

So what is clear is that we -- if possible, we want to deleverage the company, and it will be the case if the (inaudible) in the environment remains high.

It's the best way to be there in case of a low -- yes, low [cycle].

Regarding LNGs, you have the guidance for the -- what we anticipated at the prices for our LNG production.

On top of that, once again, we have the savings results, able to [rewrite] on our global position and volatility of the market.

I don't know if you -- when you mentioned the $500 million if you take into consideration all the (inaudible) onlt the same part of the segment.

(inaudible) your questions, if I may.

So 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 LNG marketing, between renewables and between the other hydrocarbon businesses that run through that line.

Yes, you're right.

Given that -- for renewable electricity...

Okay, that went nowhere.

You have the capacity, and so you -- and we did EBITDA (inaudible).

So it's not very difficult to assess the contribution in terms of results for the -- in Nigeria and key result for -- on a quarterly basis.

This quarter, I gave an indication regarding the trading contribution.

So I think we gave a lot of figures to enable you to make the technician.

So you have the prices.

You have the volumes.

You know more or less the trading deadline that toon into account.

But once again, we consider at Q3 the trading performed really well.

And 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 for 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 2 numbers, which historically led to its question and the extent to which you could add additional facility.

And it was a number that around 15 million tonnes.

But you have a global LNG terms and you have the cost coming from our products in the press release.

So yes, (inaudible).

The next question comes from the line of Oswald Clint from Bernstein.

I wanted to ask about corporate renewable electricity PPAs.

And some of the stuff you're doing here with Air Liquide and the Amazon recently.

Should -- obviously, you give a weighted average PPA price, and we should use that and some levelized cost of production for.

But are these early keyed Amazon type projects, I mean, are they more attractive, more profitable than, say, certainly, intra-group PPAs you do between Spain and France, Total or some of the stuff you're doing in India?

Should we be thinking differently across these different contracts in PPAs?

That's the first one.

If you want to know all the take rates, as you can imagine, (inaudible) for those on information.

But honestly, we give already a lot of information because you have in (inaudible) on a quarterly basis, you had average PPA on the (inaudible) on the facilities, the assets on the production.

And by the way, PPA, the price for assets under development.

For sure, you see that it's obvious you have a decline in trends in terms of PPA directly leaning to the that the fact that it will cause some declining as well.

So it's a matter of (inaudible) between cost and PPA price.

So what I can tell you is the rationale behind this corporate PPAs to diversify.

In fact, our counter-party risk, but to have only a PPA with utilities or with state bodies.

But I will not disclose for obvious reasons the prices we negotiated with (inaudible) and Air Liquide.

Okay.

That's clear.

My second question was around your -- the short-cycle CapEx, some of it you said is going to Nigeria.

Obviously, during the summer, we had this PIB bill finally signed in Nigeria.

So as we put that CapEx to work next year, are the returns on this better post the PIB being signed than they would have been, say, 2 years ago as you put money to work in Nigeria, please?

I mentioned the idea, but it was, of course, an example.

So we identified the different assets we have in our portfolio.

So we have obviously then short (inaudible) feel well that they can be easily connected to exiting facilities.

And good point, I will not give you -- I can give you a figure because on this side of asserts, you have the profitability for more than 30%.

So it's not -- I understand your question, but honestly, our (inaudible) is to identify this short cycle assets to select the best profitable one and to execute on time and on budget the CapEx.

Classically, on our short-cycle CapEx, you benefited from very, very strong return because it's developed marginally.

It's marginal investment, and you do have to pay some costs in addition with collection.

Your next question comes from the line of Biraj Borkhataria from RBC.

I want to ask a question on Mozambique.

So you've obviously paused the project because of the security concerns.

But it looks like the partners in Area 4, particularly Exxon is undergoing a strategic review with some new board members, and they have decided some concerns around the project.

So I was wondering, one of the key benefits of putting those two projects together is economies of scale and shared infrastructure, things like that.

So 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 different topic.

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 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.

So regarding Mozambique, so what I can confirm to you that, of course, we remain fully committed to develop this project.

So the resources coming from the area.

One that only, of course, when the condition will allow.

So we're, for obvious reasons, a stable and a peaceful environment to be able to mobilize our staff, and it's not possible at present time.

So we will see it will be possible next year in 2022.

And if it's the case for production, it could be there in 2026, exactly what we indicated in September during the investor day.

So we are committed to this project.

Again, it's the way, of course.

So now we have to be patient and see how the situation will improve in the coming months.

So regarding our hedging strategy, that's true that most of LNG portfolio is hedged.

I will not give you all the details, but I think, in February, we'll give you more details regarding our sensitivity and regarding this subject.

I noticed that you're right that some of our peers have taken significant losses.

But for us, what is important as well is to be in a position, clearly assess the availability of the LNG volumes in the future to implement the right hedging strategy, exactly what has been done in Q3.

And so you see the results -- you see the impact in our results.

Sorry, I was asking about the retail side of electricity, where your sort of 6 million customers you have and whether you take any market risk on there.

You mean for the electricity that we sell to final customers?

Yes, essentially that.

Yes.

The answer is yes.

The next question comes from the line of Anish Kapadia from Palissy Advisors.

I have a question on the LNG business.

Given the environment we're seeing at the moment, there's clearly higher buyer appetite to sign longer-term contracts.

We've seen a number of deals signed in the market.

So just wanted to get a little bit of an update in terms of your pre-FID LNG projects, kind of mainly thinking about the U.S. and PNG in terms of how you're thinking about those.

And could we see some kind of faster progression in terms of getting to FID?

And the second question was on your chemicals business, a lot of your peers can 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.

So the (inaudible).

So as you know, we were always very vocal regarding the side that we see in the gas has been early on the transition and particularly LNG, and so that we have a very good assets in our portfolio.

So that's why we do not need to be active on the M&A side to capture additional assets as far as this is concerned.

So we have a PNG project in our portfolio.

That could be sanctioned in the coming years.

You have Cameron expansion as well.

So the Cameron assets that we acquired the LNG portfolio.

So that's operated by Sempra.

And on top of that, that could feed the NAV growth beyond 2025.

We have access to LNG resources in russia, so with Novatek, with the possibility of launching additional developments, additional trends.

So in 2024, we would have Arctic 2 LNG production that will come onstream.

And you have, yes, I have -- I think I have omitted ECA, so (inaudible) project with (inaudible) California to Mexico, who is operated by (inaudible), very well positioned to supply the Asian market.

So all in all and on top that, so we already mentioned Mozambique projects.

So the sanction that has been taken over the 2 (inaudible), but there is plenty of (inaudible) in Mozambique.

So when the condition will be there, we could, but it's where it keeps the (inaudible), of course, with consumption additional trends there as well.

So no worry.

we have enough resources in our portfolio to feed our role beyond 2025 and the $50 million of sales will be making by 2025.

For chemicals, I think we -- it could that petrochemicals was the main contributor in the Q4 results as far as ASC is concerned.

So ASC is, once again, refining petrochemical spending.

So that's the main contributor.

We do not disclose separately the results of refining, chemicals and trading.

But for sure, the prices, the margin for petrochems were particularly high in the Q3, both, by the way, in the U.S. and Europe supported by the economic recovery.

That, we'll not provide the separate figures.

The next question comes from the line of Henry Tarr from Berenberg.

Two really.

One is -- and apologies if I missed it in your earlier statements, but just some of the main moving parts around the production as we look into 2022 would be great.

And then 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 road map for the joint venture and then whether Saft and Total is kind of leading on the battery development or whether other technologies are they're going to be involved there?

So you have to be patient.

You have to wait.

I think until February or March to have production guidance for 2022.

In September, we gave a global trend as far as production is concerned.

So giving the 2025, 2026 production figure.

But be patient.

We'll provide you with the figures very soon.

For ACC, so that's true that now we have Mercedes Benz as new shareholder in ACC.

So 1/3 in Mercedes, 1/3 is (inaudible) and 1/3 TotalEnergies.

So we obviously -- is clear for this joint venture, is to provide batteries by 2030 to almost -- that will be equivalent on a yearly basis of $2.5 million.

So that means that we will present more or less 10% of the global market.

So by -- through the entry of Mercedes within the company, so we have increased the capacity of ACC, although 120-terawatt hour -- sorry gigawatt hour, sorry, of production by 2030.

So that's -- and so the technology that we will use is (inaudible) for this ACC joint venture.

So each partner will bring on expertise, that , of course, as far as the battery technology is concerned, but also (inaudible) and Mercedes for the EV technology.

So that's the main driver behind this joint venture to attract the different expertise in the joint venture.

Next question comes from the line of Jean-Luc Romain from CM-CIC Securities.

It relates to the renewable power production.

I was wondering why in the third quarter, it was stable compared to the second while your installed capacity actually increased.

That's the first question.

And the second one is on the investment in charging points in the motorways.

The EUR 200 million you plan to invest next year, which is quite explicit.

How many charging points does it represent?

So the question regarding the renewable capacity, so the change between Q3 and Q2, that's -- but the main driver is in charge, in fact.

The fact that, as I mentioned in my speech, I think -- I have to say that before.

So in January this year, so we acquired 20% of Adani Green, so it's one of the biggest renewal developer worldwide.

And in Q3, Adani Green acquired additional portfolio of 5 gigawatts in India.

So given that we are 20% of Adani Green, so it contribute to one -- to an additional 1 gigawatt globally in our new portfolio.

As far as the developed capacity are concerned, it's less than that because, of course, this 5 gigawatts of additional capacity, they are not fully developed.

So it's more or less 0.5 gigawatts of additional installed capacity directly linked to this acquisition.

And the balance is coming from other assets developed by Total or develop the Total Eren (inaudible).

Charging points, you -- I'm not sure to have really understood your questions regarding charging points.

Actually, you announced you will invest EUR 200 million next year for 150 stations, but is it just 150 charging points?

Or is it much more than one changing point per station, actually?

It's more than one, it's 2 to 3 depending on the stations.

It's part of the global strategy to have in our operation.

So 150,000 charging points by 2025, mainly in -- we were awarded in Paris, in London, in -- now in China as well with the Chinese partner, in Singapore.

So it's part of the strategy.

And so of course, we -- by this announcement, we tend to support the growth of the electric mobility plans.

And that means that in Europe, globally, by 2025, we will have something like 1,500 HTC charging points.

So it's part of this global strategy.

Your next question comes from the line of Paul Cheng from Scotiabank.

I just want two quick questions.

One, with the rise in the natural gas in Europe, can you give us some kind of sensitivity that every $1 currency exchange, how that impact on the OpEx in your refining portfolio per barrel?

And also that how the impact on the refining margin capture per barrel, given that natural gas will be used to generate hydrogen for the hydro treating and hydrocracking operation.

And also that for the electricity and power, I suppose in the OpEx.

So that's the first question.

The second question, I want to see if there's any additional news on certain name you can provide.

I think last year, the hope was it could come on stream in 2025.

And in September, I think Patrick was saying that there's a bit of the complication.

So is there a new time line you guys have in mind right now?

Honestly, we do not give sensitivity regarding the increase in NTP for (inaudible).

What we give is the sensitivity directly into our production, so the $250 million of sensitivity we gave or team sales for an increase in -- of $1 (inaudible), but we do not provide the figure for refining margins.

On Suriname, we have a lot of exploration targets to be drilled in the next future.

We have to continue to create in parallel the discoveries, which, by the way, 2 weeks in operation.

And so we will communicate after that when the results of the campaign has been denied and then before.

Okay.

Can I ask a final question on the fourth quarter, it 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 are going to be applied to?

Obviously, I remind in the end of September, the figure is $9 billion.

So that means that, given that I give you the figure and I give you the indication that -- for 2021, the CapEx will be close to $13 billion.

That means that in Q4, we have something like $4 billion of net CapEx spent over our Q4.

But traditionally, Q4 is more early, in fact, in terms of CapEx.

So there is nothing in particular in Q4 that we anticipated in this $14 billion figure.

So it's small...

And honestly, so we stick to the guidance we gave for CapEx globally, allocating more than [50%] of the CapEx to maintenance activities and the balance you see to growing activity, LNG and renewables (inaudible) we have something like $3 billion.

We're bullish for 2021 as far as CapEx are concerned.

And your final question comes from the line of Jason Gabelman from Cowen.

I wanted to ask two questions.

First, going back to iGRP trading.

And actually I 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.

So I'm wondering if you could give any details on if you generated any excess earnings in that renewable empowered business as a result of the volatile commodity environment.

And 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?

And I have a follow-up.

Frankly, the additional of a reasonable part of the value on that sector will come from the integration and from the trading.

So what we have in mind is -- and I think it was clearly stated in December, is to be able to fully benefit from (inaudible).

And in the market, of course, you have a lot of volatility in (inaudible) as well.

You have to have see full electricity generate.

And lastly, the model, we want to implement.

So it will be doubled more or less the same electricity trading in the next future to benefit from what we call this, the integration to be able to capture the volatility.

But we already have a team, of course, that you receive to develop the team take into account the fact that this business is very local.

It's different from all (inaudible) that is more global and more worldwide.

So we have to develop local teams as well to benefit from the volatility in the electricity market.

Do you have any other question?

No?

Yes.

I have one follow-up.

Just on the $1 billion increase in short-cycle CapEx.

Can you discuss how much production that will bring on when that production will come online and then the cash flow benefits from -- at your kind of planning commodity prices?

Well, as I already mentioned, we will -- we are working at the time, and so we'll give you some more details in February or March.

But of course, it will contribute to production because when you put on (inaudible) between the decision of essentially a short-cycle of assets and the first production is between 1 -- 12 or 18 months.

So for sure, you will be starting the impact of the decision in the coming quarters.

Thank you.

So I think it was the last question?

That was the final question, sir.

Thank you.

So 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.