TotalEnergies SE (TTE) 2021 Q4 法說會逐字稿

Ladies and gentlemen. Thank you for standing by, and welcome to TotalEnergies' 2021 Results and 2022 Outlook Conference Call. (Operator Instructions) I must advise you that this conference is being recorded today, the 10th of February 2022.

I would now like to hand the conference over to Mr. Patrick Pouyanne, TotalEnergies' Chairman and Chief Executive Officer. Please go ahead, sir.

Good afternoon or good morning, wherever you are, and welcome to our TotalEnergies' 2021 Results and 2022 Outlook Presentation. But we are more conceived today, as I should say, a call on our Q4 and yearly 2021 results and our objective 2022 and as a full presentation. And you will understand why at the end of the presentation because we'll give you a new date for our new meeting soon.

We have condensed so the format for today. Jean-Pierre, our CFO, will cover the 2021 results, and I will present the outlook focusing on 2022, which means executing the strategy that we presented you at the end of September, which does not change, obviously, even if we benefit from better environment today. But as you know, safety is a core value for TotalEnergies, and we start all our meetings with a safety moment. So let's do it.

(presentation)

So this safety moment is a good introduction to our Renewables and Power business with this new CCGT, which has just been built and which is being started in France in Brittany. So welcome again. I would say that the year 2020 and 2021 was quite an extraordinary times, and we experienced, I would say, some Russian mountains. No humor from my side there. But really, we get -- we went from, I would say, the historic bottom in terms of results last year, facing hard times to record results and cash flows in 2022. So as we entered into 2021, I would say, quite prudently with no visibility, it was my message 1 year ago. The pandemic was not yet over. In fact, indeed, COVID continued to have a major impact on our lives and day-to-day ways of working.

However, I feel today that maybe the worst is behind us, and we entered into 2022. In fact, 2021 was also, I would say, marked but an impressive economic recovery worldwide and a clear rebound of energy demand, a rebound, which linked to tighter supplies because of the crisis resulted in, I would say, exceptional high prices but we have benefited during the second half of '21 and in particular, the fourth quarter.

These high prices, especially gas prices, but also power prices demonstrated, by the way, the interconnections of all the energy markets in these times of energy transition. There are 2 lessons for me of 2021, which are supportive of the strategy we put in place. The first one is that we have clearly seen that gas is transition fuel as a key role, the demand for gas because it's a source of electricity has been huge and the competition between Asia and Europe to get this LNG led to quite high prices, very high prices, exceptional ones.

And the second lesson that we can drive is that clearly, again, this energy transition is leading to more complexity, more volatility in energy markets. And from this perspective, we are more and more, I would say, convinced that the multi-energy model that we're developing within TotalEnergies is the right way to leverage this complexity and this interconnection between energy markets. But year 2021 will also remain, I would say, for us, of course, a historic year because not only because of our results and cash flow, that Jean-Pierre will present you, but also because this is a year where we moved from Total to TotalEnergies.

And it means a lot to us. It means, in fact, that the old company, together with its shareholders were voted at 92% in favor, are engaged in a strategic transformation to build a sustainable, multi-energy company which will address the challenges of more energy, less emissions, more sustainability and fully capturing the complexity and volatility across all energy markets and to position TotalEnergies as a leader of the energy transition.

On this slide, you have there, I would say, a demonstration that our new multi-energy model is now in motion. And the 2021 key achievements illustrate that -- I would say, illustrate this strategy. Of Course, oil has provided -- is providing a record source of cash flow, which is to fund the transition. This is the engine, cash engine. And our new strategy is to focus on low cost, low emission is also in progress, with examples of Deepwater in progress in Brazil or Uganda projects.

On the gas, we also, as you know, we have built in the last 10 years, I would say, a global LNG business from upstream to downstream with a global reach to grow the business, create value, increase cash flow generation and clearly in 2021, we had the benefit of this strategy, leveraging our #2 worldwide rank position.

On both segment as well, we have entered oil and gas in a way to adapt our portfolio to, I would say, biofuels on one side, biogas on the other side. In Renewable and Electricity, we have reached -- by the way, each year will beat the record EBITDA. Otherwise, it will be a problem as we are growing, but $1.4 billion in advance to our plan, which was a little less under $1 billion, 10 gigawatts of renewable capacity, 6 million electricity customers and now this segment represents 25% of our CapEx, in line with the allocation of the capital investment strategy.

So these are key achievements, I would say, but I would also mention the fact we are continuing, of course, to get our net zero ambition. By diminishing our emissions, we'll come back on it and including methane. And we are also in line with this strategy, decided to exit some camp projects like Venezuela because heavy oil is not low cost and low emission.

I would say a symbol of this strategy was, of course, the multi-energy projects. We managed to put in place the multi-energy hybrid projects in like the one we have done in Iraq, where we will valorize gas resource and solar resource, financing all that with oil productions. So I would say for 2022, I will come back on this part in the presentation.

The key word for all of us will be to deliver, so delivery because, obviously, in such favorable environment, getting the most out of our assets is our key priority. This slide is -- I will maybe come back on it in the conclusion. It's a summary of, I would say, the compelling investment case we put together to our investors for TotalEnergies, building a sustainable multi-energy company, while at the same time, increasing shareholder returns, transforming and increasing shareholder returns.

In this introduction, I just want to highlight maybe the fact that the Board of Directors yesterday has taken 2 important decisions to continue to get an attractive and sustainable return to shareholders which is on one side to increase the interim dividend, quarterly dividends by 5% for the year 2022 to decide. Of course, this has been decided because it's supported by a sustainable underlying cash flow growth, and I will come back on it.

And the second decision, as we announced in '21 is to share the present oil and gas price upside by a new tranche of buyback. We bought back $1.5 billion on the second half of '21. We increased for the first half of '22 to $2 billion buyback, and the Board intend to monitor the level of the tranche of buyback semester after semester. I will not be longer on this slide because I prefer to present it to you in the conclusion.

And I prefer, in fact, to hand over to Jean-Pierre, who will talk about our 2021 results.

Thank you, Patrick. I think this slide is a perfect introduction for my presentation. Last year, in 2021, we delivered the highest cash flow in the history of the company. Net results and profitability were also record setting in 2021. To deliver these record results, we rely on strong execution, leveraging our high-quality, low-cost portfolio.

So let's move to safety. You know safety is a core value for TotalEnergies and a cornerstone of our strong execution and operational excellence. It is important to point out that the measures have progressed to an impressive safety standard of less than 1 recordable injury per million man hours, far below -- that's what you can see on the slide here, far below the T, the total recordable injury rate shown by the main utilities. As far as TotalEnergies is concerned, we are still at the level of the best company in our industry. But unfortunately, we had a fatality in 2021 in our operation. An electrician lost his life in Kazakhstan in 2021. This is grim remainder that we need to implement constant improvements in safety standards.

Note that we integrate, as you know, renewables into our portfolio. This means that we are bringing in businesses that have, on average, a higher (inaudible) than our existing portfolio. Of course, we implement our safety culture in our renewable units, raising the standards to our own and making it safer, but it will take some time and may have an impact during the integration phase. But you can see that the progress that has been done on that field are impressive as well. And so we are confident that we can implement our culture as well in that business.

Now the environment. You know that perfectly well, 2021 turned out to be a year with record high commodity prices. You see here the price curves, oil, gas, electricity, I think, all the curves are impressive and spectacular.

All markets began to rally early in the year 2021. And the gas and power markets followed, moving sharply higher in the summer. All supporting -- supported by increasing energy demand linked to the overall economic rebound after the 2020 recession in relation with COVID-19. Very, very important to note that gas and power curves moving in sync also illustrates the increased complexity and interconnection of energy markets, as already highlighted by Patrick.

For oil, the current macro is likely to persist because demand is expected to grow as we continue to emerge from the pandemic and there is no significant influx of new supply on the horizon. OPEC has been very disciplined in its releases of (inaudible), but does not appear to have a lot of spare capacity. Years of underinvestment, I would say, since 2015 should lead to tension in supply and should support prices. A data point that is pretty telling, the current upstream CapEx level of $350 billion is aligned with the assumption of the IEA net zero scenario, while actual demand is way higher. So no wonder, prices are going up. 2020 was has clearly established gas as a transition fuel. It is the most flexible fuel to ensure power reliability and the obvious alternative to coal.

In many parts of the world, gas demand was supported by electricity demand and low output for either intermittent renewable or (inaudible) or both, for instance, China, Latin America and Europe. Supply were tight, and we saw Europe competing with Asia for LNG cargoes. As you know, several major LNG projects have been delayed, many of those due to COVID-19. So the LNG other supply that was anticipated in 2019 is gone at least until 2025. Europe is transitioning to renewable power generation, but it will take time. For now, higher gas and coal prices and cost of carbon for marginal gas coal or gas plants has driven up power prices, as you can see on the slide as well.

First, focus on our Q4 performance, the highest quarter in terms of CFFO, cash flow generated from our operations and net results in the story of the company. Here, you see a comparison between the cash flow generated by our operation, Q4 2021 versus Q4 2020. Cash flow rose sharply, more than doubling from $4.5 billion to $9.4 billion in Q4 2021. This performance, I think, demonstrated clearly our ability to use our multi-energy model to fully capture in Q4 2021, the very favorable market environment.

Oil continuing to rise above $80 per barrel. Gas in Asia and in Europe, reaching all-time highs above $30 per millimeter. And at the same time, European power above EUR 100 per megawatt hour. In absolute terms, our leverage to oil prices was the main driver, nearly doubling oil-linked cash flow, I mean the cash flow generated by E&P and downstream, this cash flow being more than $7 billion. But in terms of relative increases, integrated LNG grew by 2.5x with CFFO above $2 billion. This historic level builds on the globally integrated LNG portfolio, leveraging rising oil and gas prices and outperformance in the gas and LNG trading business. And Renewables and Electricity grew their positive contribution by 1.5x, thanks to our growing power trading team, reflecting last quarter's exceptionally strong electricity markets, particularly in Europe.

Let's move now on the full year picture. The full year 2021. 2021, it was the highest cash flow delivery in the history of the company, as I already mentioned in my introduction, thanks mainly to the LNG contribution. Full year 2021 cash flow hit a record high of close to $30 billion, almost doubling compared to 2020 figure. Upstream was clearly the cash machine, we've a CFFO close to $19 billion and CapEx at $6.5 billion.

This segment generated an impressive $12 billion of net cash flow. Integrated LNG moved to a record level as well and contributed close to $6 billion of CFFO, demonstrating that the volume growth and expansion along the value chain has indeed moved this business to structurally higher level. Downstream was resilient, more than covering its CapEx to add $3 billion of net cash flow to the company. And Renewables and Electricity while still in early days, made a positive contribution of close to $1 billion.

In this context, not surprised, we doubled our EBITDA in 2021 compared to 2020 at $42 billion. As you know, controlling the breakeven ease at the heart of our sustainability. We have lowered our pre-dividend organic breakeven below $25 per barrel. At this level, we are clearly more resilient to potential downturns in the environment and the low breakeven also increased upside in a rising price environment, that's exactly what we're able to demonstrate last year.

Net results and profitability. They were at record setting in 2021, but it was not a historical high. The company reported adjusted net income of $18.1 billion representing a return on equity of nearly 17% and a return on capital employed, ROCE, of nearly 14% for 2021. This, I think, demonstrate clearly the high quality of our portfolio and operations. All the segments contributed to that performance. E&P benefited for sure from higher oil and gas prices, with an adjusted net operating income above $10 billion.

LNG business reported historic results with an adjusted net operating income close to $6 billion. This builds on the globally integrated LNG portfolio, leveraging rising oil and gas prices and outperformance in the gas and LNG trading business. But please note, that we consider that around $1 billion was linked to the exceptionally volatile markets captured by our trading in 2021.

As you can see, Renewables and Electricity while still in early days, made also a positive contribution in terms of adjusted net operating income last year. Downstream was hit particularly hard by the pandemic but marketing is recovered back to its pre-COVID level, leading to adjusted net operating income of $3.5 billion.

In 2021, we recorded $2 billion of net income adjustments. That means that the IFRS net income was $16 billion. So the $18 billion minus this $2 billion of net income adjustments. This amount of adjustments is mainly due to the $1.4 billion loss on the sale of TotalEnergies' stake in Petrocedeno to PDVSA in Venezuela. We recorded this $1.5 billion loss in our statement end of June. And this adjustment takes into account as well a $300 million impairment linked to our withdraw from Myanmar.

For the computation of the impairment or potential impairments, we have taken into account the net zero scenarios computed by IEA for our price trajectory assumptions. So the oil price trajectory converged from $50 per barrel in 2040 towards $25 per barrel in 2050. That means the price retained in 2050 by IEA in its net zero scenario. And we had exactly the same rationale for gas scenario.

The revision of this long-term price assumption, both on oil and gas leads to limited additional impairments, around $300 million, reflecting the resilience of our portfolio.

Turning now to CapEx. As you know, we are investing with discipline selectively across all our activities in support of our strategy to build the multi-energy company. In response to 2020 COVID crisis, we came up on top of collapsing oil prices. We cut CapEx by 25% from 17% in 2019 to 13% in 2020. We have established a target range for net investments of $13 billion to $15 billion per year to 2025. And as you can see, our 2021 CapEx came in at just over $13 billion, at $13.3 billion to be precise.

It is true that we plan our CapEx quite prudently for 2021 as at that time, we have no visibility for the remaining part of the year. So slightly more than half of our CapEx was dedicated to maintaining the base, mainly Upstream and Downstream oil and the other half went to the strategic growth, Renewables and Electricity on one side, LNG and gas on the other side.

In fact, Renewables and Electricity represented more than $3 billion of -- or 25% of our 2021 CapEx. The remaining parts, close to 25% at $3.1 billion was dedicated to LNG and gas, but also, as you can see on the slide, biomass, mainly related to biofuel and renewable diesel at an early stage of development.

Among the majors, TotalEnergies has been and continues to be the low-cost producer in terms of cash OpEx per barrel and the low emission hydrocarbon producer. We believe that these benchmarks are important to demonstrate the competitive advantages we have developed and maintained within our company. We have cut our OpEx in half since 2014 to nearly $5 per barrel equivalents and the Upstream Scope 1 and 2 emission intensity, 100% on operated assets has been reduced to 17 kilograms CO2 per barrel oil equivalent. I can tell you that we have top down buy-in on these metrics across the organization. Our teams understand the importance of operating as cleanly and as efficiently as possible. The need for tight controls on OpEx is something that we all recognize and CO2 emission is taken with the same level of importance both in terms of sustainability and as a barometer of efficiency.

Downstream cash flow was $5.5 billion in 2021, a 17% increase from the previous year but still below pre-COVID level. The impact of slowdowns linked to the pandemic were particularly hard on our refining businesses. And refining suffered due to the drop in demand for roads and aviation fuel, and we adjusted rents in our refineries accordingly.

In Europe, the refining margins remained weak in 2021, having been eaten up by high energy costs. Petrochemicals, on the other hand, remained a bright spot, benefiting from the very dynamic polymer markets, which are linked to health and safety products. Marketing & Services dipped in 2020, but cash flow from operations recovered to pre-COVID levels with an increase of 15% on average between 2020 and 2021, meaning that 2021 CFFO is even slightly above 2019 level. At the same time, Marketing & Services sales globally declined by almost 20%. That means that we were able to successfully implement our Scope 3 selectivity strategy on low-margin volumes, arbitraging our portfolio.

Downstream CapEx was $2.2 billion in 2021. That means that with the CFFO of $5.5 billion, this side of our business contributed $3.3 billion of net cash flow to the company. It was a resilient source of free cash flow in 2021, clearly. One of the most exciting aspects of the TotalEnergies story has been the successful development of our integrated LNG business to the level of best-in-class across the industry. The main driver has been the growth in sales, up by more than 20% compared to pre-COVID 2019 level. That provide us with a strong base we can use to leverage favorable market condition, and it was the case, obviously, in 2021. As you can see here, cash flow increased to $5.6 billion in 2021, a massive 70% jump from the previous year by capturing the strong rebounds in both oil and gas prices.

To understand the $2.3 billion increase in cash flow, let's have a look at the Upstream, Downstream splits. The Upstream, essentially the liquidation part of the business, provide the scale and global reach that sets TotalEnergies apart as a major player in all of the main markets. Cash flow from the Upstream part of the business increased by $1.7 billion linked to the higher average LNG price which is, in turn, driven mainly by oil prices with a 3 to 6 months lag time effect.

Our average LNG price for 2021 increased by $4 per million BTU to $8.8 per million BTU on average over 2021. In Q4, I remind you that our average LNG price reached more than $13 per million BTU. The Downstream, effectively everything beyond the tailgate of the liquefaction plan is the integrated tool we use to leverage and arbitrage volatility and across the global markets. Cash flow from the Downstream part of the business increased by $0.6 billion. So $1.7 billion coming from Upstream, $0.6 billion coming from Downstream. Here, we are relying on contractual flexibility to set destinations, our worldwide footprint including our position as the largest exporters of U.S. LNG.

Ample gas capacity in Europe and a fleet of 20 chartered LNG carriers, we have developed strong position along the entire LNG value chain. And we have a growing trading operation that -- as already mentioned, that takes full advantage of this. Our integrated LNG businesses is the main driver for our underlying cash flow growth, as Patrick highlighted in his introduction and a key lever to capture the benefits of high oil and gas prices.

Now Renewables and Electricity business. Compared to LNG, our Renewables and Electricity business is at an early stage of development for sure. But as you know, we are scaling up. In 2021, we expanded our global footprint to more than 70 countries and we added more than 10 gigawatts of gross installed renewable power generation capacity. Our portfolio has grown to 43 gigawatts of growth capacity, including the 10 gigawatts of installed capacity, 7 gigawatts under construction and 26 gigawatts in development. Like LNG, we are building Renewables and Electricity business that is integrated along the entire value chain. And as illustrated on the slide, with interest in storage, in trading, EVs, mobility and retail distribution.

I will not comment in details the map showing the main 2021 achievements. But you can see that we are very active and successful on each segment of the value chain and particularly in offshore winds. We just mentioned, of course, the acquisition of the 20% stake in Adani Green in India in January 2021. So the largest solar developer in the world for $2 billion investments. And now given Adani Green share price increase, this investment is valued at around $8 billion.

In 2021, Renewables and Electricity outperformed our expectations. Net electricity production increased to 21 terawatt hour, a 50% jump from the previous year and slightly ahead, as you can see, of our forecasts. In addition to strong growth from renewables, we benefited from increasing CCGT power generation linked to the addition of 4 CCGT plants, 2 in France and 2 in Spain in late 2020.

And of course, we benefited as well of exceptional volatility captured by our electricity trading. Our proportional share of EBITDA for Ren and Electricity in 2021 was $1.4 billion, about 2.5x the level of the previous year and far above our expectations, reflecting once again the leverage we are building into that business to profit from favorable market conditions.

So how has this record cash flow generation been allocated in 2021. First, once again, we invested $13.3 billion. That means that 45% of the $29.1 billion of cash flow generated from operation, we are back into the business. We reduced debt and lowered the gearing to 15% at year-end 2021. The gearing is (inaudible) at the end of 2020 was 22%. We insist that a strong balance sheet is the first line of defense for any entity exposed to commodity prices. That is very important. That is a very clear priority whenever we find ourselves on the high side of the commodity cycle. And we allocated 1/3, 33% of our cash flow to shareholder returns, second only to CapEx in terms of magnitude with most of that in the form of dividends, $8.2 billion plus $1.5 billion in buybacks in Q4 2021.

Shareholder return is the topic that Patrick will cover in detail. So I will stop here and hand the stage back to Patrick. Thank you.

Thank you, Jean-Pierre, for these '21 results, which clearly positioned us quite well. And we enter in fact, 2022 in a very different mind than last year. Last year, no visibility, quite prudent. This year -- this doesn't mean that we will lose our discipline on the investment part. But clearly, we think that 2022 is much more largely the risks in terms of markets environment.

Our outlook '22 is clear for another probably strong year in terms of results. And a year where the priority for all the teams is again to focus on delivery, delivering or production or utilization rate of our refineries, delivering our expansion of renewables, delivering on our marketing margins, all that is a key to increase the value and the shareholder returns.

So we have, as you know, breakeven down to less than $25 per barrel, like Jean-Pierre told you. We plan our budget at $60 per barrel, which is quite conservative. But clearly, the outlook is positive for the company and for our shareholders. Of course, there are some risks in commodity markets, which are inherent, I would say, to supply and demand. But on the supply side, we do not see a necessarily material risk for oversupply. We are not in a situation like Jean-Pierre explained to you, where other investment is leading to oversupply, not yet.

Even if we, obviously, will all observe the behavior of independent U.S. shale oil producers and at which pace shale oil production will grow in 2022 because this is a main factor of uncertainty in my view, on the oil side. The other side, of course, is on the demand. On the demand, we are clearly continuing to get out of the pandemic, I would say, still some markets like the aviation fuel is not yet at its prepandemic level. So there is still more room for increasing demand for oil products. So again, this is favorable to, I would say, the outlook for 2022. But we should not as well forget that the 2021 results demonstrated that we have a clear ability to leverage a favorable environment. And by the year 2020, demonstrating the resilient performance when we are -- we have to weather the harsh environment.

So going forward, I really think that we are focusing now on transforming TotalEnergies into a sustainable, multi-energy company and can best navigate the transition towards net zero world. So getting to a net zero ambition by 2050 together with society just to give you the results of 2021, jean-Pierre spoke to you about safety. I'm taking the CO2 emissions, which is the other, I would say, core value of the company, reducing these emissions, 2021 is another year of decrease.

You have these figures, which have been calculated by excluding a specific COVID impacts on Scope 1 and 2, 37 million tons, so a reduction from 20% compared to 2015. I remind you that we have a target of minus 40% by 2030. So we are well on the journey to that. So that's the first point. I would remind you as well that in this figure is including all the emissions of the CCGT which we are not in the perimeter of 2015. So it's 4 million tons, which represents. So that means that, in fact, the efforts done by all the teams in exploration and production and refining and chemicals, mainly have already been quite impressive, moving down from 45% to less than 35%.

Then another metric is important when we speak about our emissions and our operated activities is a methane, as I said. We didn't wait for Glasgow to focus on methane, even if the world seems to have discovered the impact of methane, we took that very seriously for many years. And from 2015 to 2021, it's a reduction of almost 50%. '14, we are a little less 49,000 tons per -- for the year '21 of methane. We will set some new targets, and I can already tell you that we revised the target we set in September. It will be reported end of March in our Sustainability and Climate Report to a reduction of 80% for the next decade and 50% by 2025, which means that we are really working hard to go to go next to zero for methane emissions as soon as possible.

And it's important because, of course, our involvement in the natural gas business is strong. So it's a matter of consistency. Then on the Scope 3, as you can see and we can see that we are driving down our Scope 3 emissions in Europe in order to adapt, I would say, our sales to the demand on oil products by anticipating. We have established a strategy that would say, to arbitrate the low-margin sales and it's already -- our contribution to the green deal is clear, a minus 23% on Scope 1, 2 and 3 in Europe.

But globally speaking, we said that the during the decade 2030, our ambition is to maintain a Scope 3 worldwide under the Scope 3 of 2015, despite the fact that we are growing almost by 30% the company in terms of energy delivery to our customers. That means that if the 400 million ton figure seems to be the same that the 400 ton then it's very different, in fact, because there is more emissions coming from gas and less from oil products.

Last figure, which I think needs to be recorded is a carbon intensity of our sales, which are down by 11% in compare ['15], our objective is minus 20% by 2030. So then again, we are well on the way to get the objective. So I think it's also a strong set of results, and it's more and more important, not only to look to financial results but also to extra financial results like these ones.

So coming back to '22, yes, we have announced in September a capital investment strategy of $13 billion, $15 billion. For the year '22, we will be on the high range, let's say, $14 billion, $15 billion. Keeping the same, I would say, split that we announced, which is a fundamental, I would say, to our transformation, the way we allocate our capital. So 50% on the -- what we call the old maintenance. That means that we have no ambition to grow in oil, want to maintain the oil production upstream and aligning the refining around 1.3 million barrel oil per day. This required capital because, as you know, we have a natural decline around 3%.

So to maintain, we need to invest. We need also to invest to maintain the reliability and safety of our Downstream plants, refineries and petrochemical plants. So this 50% are necessary to maintain to stabilize, and the rest 50% is to grow, to grow under 2 pillars. One pillar is Renewables and Electricity, which has taken 25% of our global CapEx. So we'll go for more, from $3 billion to $3.5 billion in 2022 and the other pillar is LNG and gas, I would say, and new molecules like in gas, you could understand that biogas and hydrogen, even if it's yet limited in 2022.

So going to industry sales, let's begin by all. In oil, the program, obviously, again, is to focus on delivery and on organic value creation. So we have increased -- and it's part of the reason why the budget, CapEx budget increased in '22 compared to '21. We have reactivated short-cycle CapEx that we have in countries like Angola or Nigeria, $1 billion of short-cycle CapEx are now mobilized more rigs coming on stream, keeping in mind of (inaudible) limitation, which is a COVID impact on the operation.

So it's not exactly the level where we were before the pandemic, but it's growing, and it will bring production contribution of around 50,000 barrel per day, main asset being the Block 17 in Angola. I would also remind that we have some startups in 2022, in particular, Marwan, Brazil, the first of the 4 Marus is coming on stream by middle of the year, EKK Nigeria and some new fields in the Novatek portfolio. We have also, in terms of gaining value creation, continuing to explore in particular, we have some very high impact wells. We have one -- 3, in fact, being drilled today. One in Brazil, Maru prospect. We -- our explorers have good hope, I hope, I would say. Surinam continues to drill to, I would say, appraise the world potential of the block with -- in view to identify or development by end of '22. And Namibia is another high-impact well, which is being drilled. That's for the organic part.

But to highgrade our portfolio and which we also use, I would say, M&A with 2 clear axis, divesting mature high emission assets, noncore but we have done this year in Gabon, in Angola Block 14. So that's one part, and we sold for $2 billion of assets. And I would say it's not because price of all is high, but we must stop this strategy. We must, on the contrary, implement it in '22. So there is more to come of these mature marginal fields because probably we get more value from investors in '22 than before.

And on the other side, we are acquiring, we continue to have an acquisition of interest in low-cost, low-emission assets. And I would say that I consider we have been very successful in the tour auctions end of December by getting access to 2 giant (inaudible), CPR and Atapus plus PSCs with quite good return. So we are very happy to be a partner of these 2 giant fields. And we know also that we are leveraging when we looked for low-cost oil, we are looking, of course, to -- we have a very strong foothold in the Middle East and Iraq, Libya, we already explained.

By the way, on this slide, you can see that we accelerate our growth in deepwater Brazil. We are planning to reach 150,000 barrels per day by 25%. Now it's by 23% with the additions we have done. And really, that will be some cash in gin for all business in the coming years. Last comment on this one, we continue -- and we are able -- and by the way, it's a demonstration that the strategy can work, including on the oil and gas business. We have been able, even focusing and divesting some high cost, high emissions projects, but focus -- but investing in low-cost, low-emission projects to have a reserve replacement rate in '21 of 123%. The average is 116%.

So this strategy can work to focus on, again, some low cost, low emissions, oil and gas fields. So for '22, one figure for the Upstream division and Nicolas' teams is 2.9 million barrels of oil per day or equivalent, plus 2%. There are some plus sort cycle some new productions. There are some minus when we go invisible from Myanmar, obviously, we are -- we'll lose some productions will be gas there. But this is a clear focus of all the teams. I know in E&P and thank you for that.

The Downstream is the same message. In fact, it's on 2 pillars there. It's a delivery on one side for refining. It's coming back to, I would say, a decent utilization rate, 80%. As Jean-Pierre said, the year '21 was rough for margins were lower. Energy prices are high, still high, in particular, natural gas is impacted quite a lot the refining -- but also, we had honestly some operational issues in some plants.

So teams are mobilized there. So which is good because that means that we have extra cash, which will be -- might be delivered. The other part of the delivery is a cracker in the U.S. We are expecting it to be also transparent. It suffered from the COVID, I would say, impact in terms of capacity delivery. So it's late. It's late, and it was difficult to manage all the COVID impacts, I would say, on the building of this cracker. But now the teams are all mobilized in the U.S. to start up the cracker by, I would say, middle of the year, which will allow by the way, to start the cracker almost together with the polymer lines.

So in terms of integration, it will be economically, it's not too bad. I would say, the part for Refining & Chemicals is to engage into the transformation on biofuels on one side. And also on circular economy, we've more polymers being produced from bio and recycled polymers 100,000 tonnes is a target for 2022. And on Marketing & Servicing, they implement the strategy we have defined, which is also a form of transformation, of course, getting most of the assets, which is the growing nonfuel revenues -- this is a source of additional cash. So getting to the -- we have a target of 35%. But also, at the same time, continuing to be selective on all product sales by arbitraging the low margin sales.

Compared to 2015, the objective is to decrease this type of sales by 20%. And new energies, there again, continuing to develop in EV charging. In particular, I would say, we put more and more focus on our own retail network because we think that the customers have -- will may have the same trend than before going to a retail station. But there, we need to invest in high power charging because these are the expectations and will be the focus of investments.

So all in all, we are expecting another good year, but we have not been disappointing by the Downstream for many years. $5.5 billion in '21, more than EUR 6 billion in '22. The extra should come, of course, from refining, which was low. Maybe the petrochemicals, the polymer will not be able to redeliver the exceptional year of '21, that's the market. But I think this is again important for the whole company and to fund the transformation.

Then LNG. LNG, I think, Jean-Pierre spoke about it. Of course, this is the engine of the growth and in particular, of the underlying cash flow growth, which is feeding the increase of the dividend. As you can see, we have clearly a volume increase by 6 million tonnes, mainly driven by long-term contracts, and these are these long-term contracts, which will deliver, I would say, the sustainable underlying cash flow. Of course, at the same time, there is a strong leverage to high and volatile price. High it's for 3 volatile. This is what our downstream people like to make arbitration, I would say. It seems to be strange, but we like volatility, but in fact, we have some big teams who love that.

So on the Upstream part, we have 2 informations there. 80% of our -- I would say, our production LNG production is linked to oil. So of course, we have a leverage to oil, which is quite strong. But we have also leveraged to, I would say, spot markets and deep indicators. Before we are giving you $1 million by $1 per million BTU, with the volatility, we said, no, we will give it for $10 by billion BTU because we plan on $10 million as a price on NBP, but maybe it will be 20% like it is more than 20% since the beginning of the year. So it's $800 million extra cash for $10 per million Btu, only on the Upstream part of the LNG.

And in fact, another information, which is important to us is that -- and Jean-Pierre told you, we have a time lag of 3 to 6 months in our LNG formula. So we embark, in fact, in '22, with a very strong visibility for the first semester of more than $12 per million BTU, which is a higher average than the one we had in the second half of '21. So that's important.

And again, on the other side, our Downstream LNG teams, they have the capacity to arbitrage and to again get benefit from volatility with 2 key indicators, which illustrate their capacity. The first one, they have a global portfolio flexibility of 65%. So they can changes destination of 65% of the, I would say, the sales portfolio they have in their hand. And second, remember that we are #1 U.S. exporter which, of course, is very important in terms of flexibility because there is one gas price which does not move too much even if it goes last year from $3 to $5 per million BTU is the U.S. gas price.

So the capacity to arbitrate between China, Asia and Europe, of course, is a strong engine for cash flow. So this -- of course, LNG, again, like '21, even '22 more than '21, will be a year where we should get the fruits of all what we invested and we continue to invest in this business.

Renewables and Power. I would say, this is an important year, '22, because we'll go from growing 3 gigawatt per year to 6 gigawatt per year. In 2019, it was 7. We went from 7 to -- it was 4, we went from 4 to 7 in 2020, from 7 to 10 in '21. So it was plus 3, plus 3.

Now we enter into a new phase of growth which is plus 6, which more than 16 and the plus 6, in fact, with 4x6, we reach the 35 gigawatts before to have a new phase beyond '25, which is plus 9, plus 10 gigawatts to reach the 100. So the capacity, all that is not a dream from the CEO, all about our projects where people are working on the ground in many countries to deliver it.

One spectacular project, which will come on stream will be (inaudible) in Qatar, the 800 megawatts. And I think that you will be happy if we invite you not only to go to Qatar to visit the solar plant, but maybe to look to the World Cup in November 2022. It's very serious, by the way, the invitation to our investors. But definitely, I think, it will be good to understand what means to build a 10-kilometer by 10-kilometer solar plants in the middle of the desert.

So not paying football on the solar panels, but just to deliver power to Qatar. And of course, I can tell you, we are all mobilized so that they will have this green power to feed this stadium during the World Cup. The other part of the '22, I would say, new start-ups are in offshore wind. in fact, the field of online in Taiwan began -- started its production, the first generator in '21, but very limited. The real startup is in '22. And there is in Scotland, the first also turbines, which will generate power together with (inaudible) and the Seagreen projects. So that's the program is delivering this growth.

In terms of results and production, which is also important because we are looking carefully to that. This is, obviously, the target is to have a profitable growth. And production will increase by, let's say, 25%, mainly from renewables, by the way, not from CCGT this time. And EBITDA, in terms of what we say, proportional share of EBITDA, you could be surprised that you don't see the translation of the 25% in the EBITDA. It's more than 1.5 million.

It's not because we are prudent because as Jean-Pierre told you, in the $1.4 billion of '21, clearly, there is an exceptional results from our traders in Q4, benefiting from the exceptional level of European power. I hope they will replicate it, but now it's never granted. So we are prudent of planning this type of results. But again, it's begun to be material, EUR 1.5 billion of EBITDA, okay? We have a global EBITDA of $40 billion. But in my view, it's becoming to be a material contribution to the company.

So if I summarize that for 2022, our generation of cash, of course -- and this is a little complex scheme because we tried to show you that, yes, we embarked a EUR 1 billion underlying LNG and power, by the way, because part of it is, obviously, justified by probably $1 billion, which will justify the increase of dividend. But do you read it, you can read that we have, yes, delivered debt-adjusted cash flow in '21 of around $31 billion. If we translate all that in -- at the same environment level, which is $60 Brent, $25 per ton for refining margin and $10 per million Btu for NBP, it would have been around EUR 26 billion. In '22, this same environment will give $27 billion, so an additional $1 billion. But if I'm coming back in a more plausible environment because don't conclude that I'm very pessimistic about oil price, I'm not pessimistic just to make the demonstration, I would have preferred the gray under the blue on the top, but that's the way that's been designed.

If we come back in a more plausible environment, which is $70 per barrel, maybe I'm a little shy; and $20 per million Btu, maybe I'm a little high, would get something like $34 billion. Why? Because you have the metrics -- or $33 million, exactly $33 million, $34 million. We have the metrics for $10 Brent, we have an extra $3.2 billion. For $10 per million BTU of NBP, we have an extra $3 billion. The $3 billion represents the LNG part. I gave you 800 plus. So domestic, the gas, European gas, Norwegian gas, U.K. gas, which is delivering the other $2.2 billion. So this is the metrics.

Of course, you will tell me that you are not there, you are today at 80. We'll see by the end of the year where we will be, but we have room not only in the conclusion of this slide, not only to increase interim dividends, which is sustained by this $1 billion. And I will tell you the math are quite simple, what the Board said, okay, we will give back to the shareholders, 40% of the $1 billion by through the dividend, and that represents an increase of 5%. So it's why you have the 5% announced this morning. And we have also room to share with you part of the surplus extra. And this is the first -- the next first tranche for '22 will be $2 billion. So I'm coming to this slide, but you know very well. It does not change compared to previous slides in terms of, I would say, priorities, CapEx, $14 billion, $15 billion.

The dividend supported by underlying long-term cash flow growth plus 5%, just to explain to you why. The balance sheet credit A rating, Standard & Poor's is even A with positive trend, I think. And gearing under 20%, we are at 15%. So we'll continue to consolidate it. And share buyback, sharing surplus it's from high oil and gas prices before we were giving a guidance on oil prices. So this is a gas pricing. Gas prices are also giving us, I would say, short-term higher revenues. So $2 billion for the first half. It means that it will be executed during the first half and that the Board will consider to reevaluate it according to the actual results for the second part of the year.

So if I just want to make a benchmark of our results and our shareholder returns, I would say that if we look to this (inaudible) chart, you can see that in terms of return on equity, with 17%, I think, we have -- it was -- I would -- we have waited quite a long to see this type of figures, about 15% we are 1 among the majors. By the way, we have also put ESG risk rating, the one by Sustainalytics, don't make a mistake. The lower you are, the better you are, is the way they make the notation. So there, again, we have -- we are well ranked. But for shareholders, we have returned 33% in '21 of the CFFO, which is comparable. There is one competitor which is given a little more, but I think this benchmark is a good benchmark for us.

And in terms of TSR on the last -- on the 3-year TSR with 12%, we are the #2 far above our 2 European competitors. So if I may summarize the investment case and why we qualify it of compelling investment case, I would say that you have one pillar, obviously, is a low-cost, low-emission portfolio, which allow us to capture high energy upside from a high energy prices. You've seen the figures, $10 per barrel, more than $3 billion, $10 per million Btu, $3 billion. So it's -- and we have been -- we have demonstrated in '21, but we are able to capture it.

And that's important, in particular, the oil project -- oil portfolio, but also the LNG portfolio. The second pillar of our investment case is that we consider that the multi-energy integrated model that we are building all gas and electricity is the one which will get, I would say, the best value for our shareholders out of the transition. The transition is a matter of molecules.

Hydrogen, Biogas, CO2, which are clearly at the core of competencies of an oil and gas company, but also of electrons, which is growing power, the use of power is growing. And which means that power being a secondary energy, it's a matter of increasing interconnection in the market and complexity somewhere. In particular, more intermittency coming from renewables, create more volatility in the market. And this is what is underpinning our multi-energy and integrated strategy. And I would add that in our company, the DNA of a large oil and gas company like TotalEnergies, the management complexity is somewhere at the core of it. It's part of the DNA. And so we are well positioned with our know-how, our balance sheet or worldwide footprint to manage that.

Then, of course, we translate that into what is new in the electricity value chain. There again, the more we look to our -- this business, the more we think that we need to develop the integrated approach that we had in oil and gas to be integrated along the world value chain, production, storage, trading, supply. We need also to be ready to leverage our strong balance sheet, which helps us -- which give us the capacity to capture value from volatility in electricity markets.

So you will see the mix of TotalEnergies. In the future, it will not be only about PPAs, but also accepting to take the risk of commodity price because, again, we have the capacity to do it. And thanks to our strong balance sheet that can be also a differentiator from some competitors in that field. Knowing that we continue, and I confirm to you that all the projects in which we invest have to -- we are selective and we reach -- we are targeting more one -- a double-digit return on equity. All that will help -- will contribute to continue to increase the attractive and sustainable shareholder return to shareholders and have already insisted to that.

But I will also end my presentation with what we call that extra financial reporting and progress. We attach great importance. We know that for investors it's more and more important. And this is why -- and that's my final slide. The Board of Directors has decided in line, I would say, with what we proposed last year in the resolution to the AGM -- to the 2021 AGM. We ended the resolutions stating that the Board will report on the progress of TotalEnergies' ambition with respect to sustainable development and energy transition towards carbon neutrality annually. The way we'll do it is that, yes, we will issue a report on March 24 Sustainability and Climate Progress Report 2022.

We'll have the opportunity the same day to make a presentation on the investors and ask sustainability and climate are interestingly linked to strategy. Obviously, we'll review the strategy. This is why we have done -- not done it today again. And the other decision which has been taken is that on May 26, at the next AGM, 2022 AGM, we will submit this progress report to an advisory vote in order to continue, I would say, to have -- to align the company and its shareholders of the trajectory of transformation that we have entered into.

So thank you for your attention. And now with Jean-Pierre and my colleagues, which are in the room -- not behind the desk, but in the room, ready to answer to your questions. Thank you for your attention.

(Operator Instructions) We've got the first question from the line of Irene Himona from Societe Generale.

Congratulations on what were very strong results. I had 2 questions, please, on distribution policy. Firstly, on the buyback, if you could please clarify the timing or the phasing of the $2 billion buyback you announced for the first half of the year? And then in terms of visibility in the future buyback, should we anticipate you announcing the amount twice a year?

My second question on the 5% dividend increase. You had previously indicated last year that dividend increases would depend on a structural increase in cash flows. And today, you attribute the dividend increase to a structural increase in cash flow from LNG and electricity. Can we read into that, that you anticipate LNG and power markets to continue to remain tight throughout 2022?

Thank you, Irene, for your kind words. I would say, first, the timing, I just mentioned it in my speech. Clearly, it will be executing during the first half of 2022 because the Board of Directors was want also to look what is the share price. We will not buy if the shares continue to grow. There is a certain point. So it's why we also want to have a program on the first half. So Jean-Pierre and his team will execute $2 billion in the coming months with the rules, of course, during the windows in which we can intervene in the markets. So that's the first.

Second, I mean, let's -- the Board wants to monitor that according to -- we'll see, we could expect maybe more cash flows coming, more surplus cash flow.

So it will be at least twice a year. It may be -- it could be -- I would say, it depends on the Board. It could be even modified after the first quarter results, but let's see. The technical answer is at least twice a year. So don't consider, but the $2 billion is only for the year. There is no hidden agenda. It's just for first half, and then we'll see. But in the past, each time we have announced a long buyback program, we were interrupted by some events on the market. So let's be prudent, let's execute. So -- but you can consider that if the environment remains as it is, it will be at least the $2 billion for the second part, if not more.

On the dividend, I would say, I mean -- no, again, what means from structural CFFO or underlying long-term CFFO, it means that it comes from some volume increase, from something which is sustainable. It does not come from the actual prices. The impact on the prices, we know that it's volatile, is reported in what we call the surplus cash flow. So when -- if -- and we increased the dividend by 5% because we consider that we are in a growth trajectory. I'll remind you that in September, like we previously reminded you, but we are in a trajectory where the cash flow should grow by $5 billion at the same environment.

And so it's the first tranche of this $5 billion for the next 5 years. If you remind us, as you follow us very carefully, I think in 2018 or 2019, we had already that in mind. Of course, when the events with the crisis have disrupted everything, and we have already announced that if we have an extra $1 billion, we would allocate more or less 5% increase on the dividend. So we are coming back on the trajectory on which we were before. But it's not linked to we believe that the price will remain. It's linked to in, I would say, conservative environment, we consider that, I would say, these -- the 6 million tons extra volume LNG are there for long and even royalty is that we will continue to increase because we have a growth trajectory.

So this is a basis of the increase of the dividend. It's something which can be sustained independently of, I would say, very high oil prices, but in a conservative environment.

Having said that, to answer to your question, I think that the LNG target will remain tight for a few years. If you remind as well, Irene, I knew that in 2018, 2019, people were speaking about oversupply, but they were forgetting is by '24, '25. In fact, we already announced by '22, '23, and I would say even '24 with the COVID impact, we don't see much trends coming on stream. It's easy to anticipate. And we continue to see, by the way, high demand.

The only point on the demand where we have to be prudent for LNG that if the price remains at $20, I'm a little afraid of the negative impact it will have on some emerging markets like Bangladesh, Vietnam, India, even India -- so that's why I'm prudent on the LNG side in terms of anticipation. Because, again, gas is competing for coal. And if gas remains too high, coal will come back despite the climate change or coal will not exit, more exactly.

Next question comes from the line of Mickael Della Vigna from Goldman Sachs.

It's Mickael. Congratulations from my side as well on the results. Two questions, if I may. One on shareholder returns and one on renewables. On shareholder returns, if I look at the dividend, the $2 billion buyback, it's effectively 40% distribution of your cash flow under your conservative assumptions of $60 oil, $10 MMBtu. I was wondering for modeling purposes, if the macro proves to be more generous, which looks likely at this point in time, should we assume that we can continue to have a 40% payout on the incremental cash flow there, which more or less is what you have delivered through the cycle over the last few years.

My second question is on renewable power. It's something I find very difficult to model at the moment because there are so many different forces at play. There's higher power prices on one side with also a repricing of intermittency, but on the other side, much higher costs across the value chain, and there is a beginning of the rate rise cycle with higher cost of capital as well for project financing and each of those pulls the equity returns in different directions. I was just wondering, when you look at your opportunities in renewable power, especially in offshore wind, how do you compare the return on equity and the opportunities there versus where you were seeing them 1 year ago?

Okay. The 40%, again, I just explained that is -- yes, you are right. The way we calculate the dividend is -- the increase of the dividend is plus $1 billion, $400 million. It represents 5% of the $8 billion we distribute. So that's right. So it's a guidance where we think it's a good guidance. Having said that, sometimes like in 2021, we were targeting that, when the price increase quicker than we were able to make the buyback. So we reached 33%. So it's a 35%, 40% is a range which is in the mindset of our Board of Directors. So it's -- if you want to model, you can use it.

On the renewable part, I think, yes, things are moving. And again, it's a matter of -- and this is, for me, something which -- where we have an evolution in the company. Now when we enter into that field, we see maybe it's a secure business, you have these PPAs that's fair. The more we look at it, the more we think that we have more value to create if we accept to, I would say -- and it's like LNG, I would say. LNG historically, we're willing long-term contracts to invest. And then we decided around 2005, let's buy the LNG for ourselves and let's become a player in the market, arbitration, et cetera.

And you've seen the positive results in '21, 15 years after we engaged in the strategy. I think we are looking to more and more renewables and power assets as also a capacity to maybe it's 50%, which will be, I would say, secure, but the other part. We have, because of our balance sheet, the capacity, providing we have also storage capacities, providing we have also trading teams, strong teams to leverage the volatility. And we are, I would say -- the more I'm looking to this market, the more I'm thinking that the electricity price could go higher and higher.

So I think it's better to keep -- so when we analyze an investments like the one you mentioned offshore wind, it's not only one of the key parameters will be the anticipation that you have on the power pricing in 2030 by the way, 2035. And so my view is that, yes, let's keep part of it on PPAs where you secure, I would say, a base return. But do -- we have to accept as well the profitability. We just recruited the Chief Economist outside of our oil and gas markets, in the electricity markets in order to help us to better modelized that.

So for me, and I think this is justifying this view why a company like us is entering into the business, not to secure revenues but to be able to leverage the integration again and the volatility.

Next question comes from the line of Lydia Rainforth from Barclays.

Hopefully, the March 24 presentation, we will manage to see each other in-person. Two questions, if I could. The first one was on the integration side and the Total being multi-energy. Can you actually talk us through the economics of something like the Iraq project? And is that sort of saying the best example of where multi-energy really works for Total.

And then secondly, on the renewable side, you talked about kind of the business now being in over 70 countries. I was wondering at what point do you think that -- how much you need to focus that business and is more geography actually better? Or is there specific areas you kind of think that where you need to focus on. And then just very lastly, just to pick up on the cash return. You mentioned the share price earlier. Is the -- so is the buyback level dependent actually now on the share price?

Last question, yes, there is a level where obviously it become too expensive. So I don't want to cap the share price hike, let's be clear. But there might be an arbitration between having the debt going down, keeping the money. And then because we know the markets will be volatile. The best buybacks for our investors and for the company, the best investment in buybacks is to buy the shares when the share is low -- when the share is very high. So we -- the Board will obviously monitor that. There is no -- I mean, don't ask me a mathematical solution. There is no magic there. It's just a question of monitoring it because I have already met a lot of investors, which criticized us somewhere sometimes when we buy, but it's high. So why not keeping the money and then using it when the share is low. We would have more -- last year, it was not possible. It was a year when the share was at EUR 30 per share. But I know some investors who bought some shares at this level, we are not able to do it as a company. So that's a point where, just a remark.

On the economic benefits on the integration, but there are several ones. One of them in particular, in the case of Iraq, and we are using that in other oil countries, is that when you have developers willing to develop large projects in these emerging countries, they are all asking to -- when you are a small developer, they want some sovereign guarantees. When you are an oil and gas company and you receive revenues from a state, larger revenues, let's be clear, the revenues from oil compared even to what we want to do in Iraq, the magnitude of the power of revenues is not the same. You can find a way to, I would say, guarantee your electricity revenues by the oil revenue.

So there is a link there, which is a good leverage in terms of economic benefits and possibility to make the projects. And so I mean -- and same -- at the end of the day, the gas resources, which we have leveraged are also part of, I would say, an extensive contract service. Contracts, is -- I will not call that. I don't know what is the name of the contract in Iraq. I don't remember. But it's part of -- you can use like, we've done in other countries, like it was done, for example, in Qatar by Shell with GTL. You can use revenues of one to leverage the investment in the other. So that's the beauty of it, if are able to invest in different projects, then it's a question of managing the different parameters of the contract.

Yes. The advantage to be in more countries for renewables is that there are less competitors. I will tell you the advantage is that, first, we are there. We know the country. We have a presence. We have some people working already in marketing and services, in E&P. So we have a knowledge of authorities. They respect us. We have an image. So it's good because we have a trust, I would say, you build on the trust. The second part is that most of the developers have -- of course, the smaller ones, you have some small companies. But the larger, I would say, utilities are focused on some countries, mainly, the large countries, which offer PPAs, which is not the case, of course, of all these emerging countries or the ID what we are is, of course, it's complex in some of the smaller countries, but the profitability can be higher.

So this is what we are looking for to have direct negotiation to be able to leverage, I would say, what it can bring to the country in order to have a better profitability. So -- and I think this is an advantage of a company like TotalEnergies. We are present in many countries. There is longer service relationship, we can leverage it. We call them renewable explorers. They will not replace our real explorers, but they will bring some good profits in the future.

Next question comes from the line of Bertrand Hodee from Kepler Cheuvreux.

Congratulations, again, for the results and also for having the vision to grow your LNG portfolio back in 2018, '19, especially with the acquisition of U.S. LNG portfolio from Engie and Toshiba, at a time where those LNG contracts would have probably provided some losses. So I guess that was a countercyclical and wise strategy, in my view. But now I want to understand more your sensitivity to spot LNG prices. And I fully get that given the structure of your portfolio. You may have surely hedges in place.

For 2022, if I understood well, during the presentation, you stated that a $10 per MBtu move equals to around $3 billion of additional cash flow, $2.2 billion for Upstream and $0.8 billion for LNG. And back in September, I reminded that you also highlighted that a $10 per MBtu move in both NBP and spot LNG, were adding $6 billion to your cash flow by 2025. Should I be right to understand the discrepancy of $3 billion between the 2 sensitivities because of the hedges you have? That is my first question.

And the second question is, should I also be right to assume that if you were to raise your medium-term assumption for both NBP and JKM, so spot LNG in Asia by $5 per MBtu. We could also add $3 billion of structural cash flow to your 2025 plan.

Technical questions. So first, yes, you are right on Toshiba just to tell you that today, we are cash positive after '21 without using the $800 million we received, it's a profitable business. So we have received $800 million, and we are already making more money. So just thank you for reminding that to everybody.

I would say then your point. There is a point, yes. We mentioned in September that when the difference between the JKM and Henry Hub is increasing by $1 per million BTU, then we have extra cash of, if I remember, $600 million. By the way, there is a lag effect there because, yes, it's linked to hedges all that. And so in fact, when you make the hedges the year where you make the hedges because it's a mark-to-market story, you are hedging the year after. So you have the results in the year and you have the cash flow in the year after, if I remember correctly. So you have a discrepancy between the results and the cash.

So in 2022, we'll get the results of the hedges, which were implemented in 2021. But remember that the way we hedge is quarter after quarter. So we did a new in first quarter '21. But the last quarter, we should have waited for the long -- end of the year. Now we were not magicians. We would have done it. We would have waited, but we don't -- do work like that. We hedge quarter after quarter. So in fact, what we embarked in the hedges which will be delivered in 2022, I would say, is only half a year compared to what you could imagine today, just to explain you that. And what we'll do this year, of course, we have today a spread between JKM and Henry Hub, which must be around $15 or $20 per million Btu. This is the decisions that we will engage the hedges we will do in first quarter, for example. You will have some results, but the cash will be in '23, which is good. That's good visibility.

So there is where it's not exactly to plan. So in a permanent regime, your assumption for 2025 is right. So $5 million BTU extra spread will give us in a permanent regime, $3 billion extra cash flow in 2025. It's more difficult to do from 1 year to another year because it depends, of course, it's a permanent regime, but it means the $5 should be the same during -- the spread should be the same along the -- all the years along all the quarters as we, again, hedge quarter after quarter. I think I've been clear to you -- it took me a little time to understand. So I'm trying to translate all that in a -- and if not, you call Jean-Pierre and Stephane, and they will explain you. But fundamentally, yes. The answer is, in '22, we'll receive more cash than '21 from these hedges because in '21, we see the 1 done in 2020, in '22, 2021. But '22 is not a full year, I would say, compared to what could be done '23. So is there something additional to come to us in terms of cash flow.

Next question comes from the line of Christyan Malek from JPMorgan.

Congratulations on this very strong result and seeing the dividend increase as well. Two questions from me. First, just on the project in the Gulf of Mexico that you announced the North Platte deepwater, it's certainly extraordinary in the context of having completed the seed. You've got the semi-submersible production facilities out tender, and Valaris has got 42-month drilling contract. So with that in mind, it's not in its infancy. So can you just walk us through the industrial or financial logic as to why you've done that potentially sort of within the context of U.S. energy policy around Gulf of Mexico? Is there sort of -- should we draw conclusions around your appetite to invest within GoM within that context. So just trying to understand, even from a policy standpoint, how you see the U.S. from an investment standpoint?

And then the second question, it relates to the very welcome sort of sustainability and climate progress report. I mean within the framework of how you deliver this these metrics and then the data around carbon intensity, should we or can we hope for more disclosure at the asset level in terms of carbon intensity, asset or region so we can better understand the relationship between profitability, returns and the carbon intensity of some of the highest carbon-intensive projects in the world.

Thank you, Christyan, for these 2 questions. The first one, no, there is no U.S. policy. It's not -- there is no U.S. policy involved. No consideration of the U.S. policy regarding GoM and all in this decision. It's a pure intrinsic decision linked to the project and linked also to our capital allocation. We look at it. It's honestly at the limit -- at the high limit of the range we gave ourselves. I remind you that we set to investors -- we'll invest in all portfolio, in all greenfield projects, $20 per barrel, $30 of technical cost, CapEx plus OpEx or $30 of breakeven. And North Platte because of its size, in fact, we knew it. It's not a giant field. It's not -- it's really on the high side of these metrics. So that's one point.

And second point, we prefer to invest in Sépia and Atapu in Brazil than in North Platte. So yes, we have done our job because we are -- we were the operator but -- and we want our partner to be able if they wish to do so to hand over in a smooth way. But all in all, at the end, we consider that we had better opportunities in our portfolio to allocate our capital. So there is no politics behind it, just decision at all level and again, in the framework of investment -- inside our investment framework that I just reminded.

I'm not sure we'll report all the assets one by one. We don't report the production one by one. We do it regionally. So I'm considering that. I will take your point. There is no problem for me to be -- to look at it. By the way, we begin. I think if I remember correctly, we have this spread of reporting between the different continents, like we've done for reserves. I think we'll -- at the end of the day, for me, I consider that fundamentally, I don't know what the SEC will issue, but we should report on these emissions like on the financials in the same type of framework.

So we are working on it. And by the way, we are also working not only on Scope 1 and 2 operated emissions but only on the equity emissions. I think this year, we'll be able to do it for Scope 1. We don't have all the data for Scope 2 from all our assets, but it's progress report, so we progress. And I think -- so we will disclose more in our sustainability and climate report and what we have done until now in a way which is more readable for you so that you can better maybe analyze the data. So that's our intent.

The idea for Broad by submitting, by the way, to an advisory vote this report is that to consider that the financial -- the general assembly of shareholders approved the financial reporting that will approve the extra financial reporting, and we think this is a global trend. We've seen at COP26, the ISSB and all these organizations willing to normalize, I would say, the extra financial, and we are willing to contribute to that.

Christyan, just a word, I read your paper this morning. You are pessimistic about our capacity to make buybacks on the year 2022. If we announced $2 billion for first half, I'm not sure will decrease in the second half until our share will range the roof unless the share will raise the roof. Thank you.

Thanks, Patrick, and look forward to the World Cup with you in Qatar. Very excited.

Thank you. And with more buybacks, I know.

Next question comes from the line of Biraj Borkhataria from RBC.

First one, just a clarification on trading. You mentioned $1 billion, I think you referred to integrated gas benefit in 2021. But I recall last quarter, you called out a $500 million benefit. I guess, implying that the trading contribution for gas -- integrated gas was the same in Q4 when I would have expected it to be better. So could you just run through those numbers again? And also, if you could quantify the electricity side trading gain there, that would be helpful.

And then the second question is on Libya. I believe there's a some kind of one-off or catch-up tax payment due in 2022? Is there any details you can provide on that?

Okay. I was wondering -- I mean, catch-up tax payment. Trading in -- no, the one -- what I think just -- have you seen the results from iGRP for Q4 are quite exceptional, I think, $6 billion, if I remember. We just end the warning, but we consider there is somewhere in the $6 billion, it's reported as recurrent results, a $1 billion, which has been clearly given by the, I would say, exceptional trading. I remind you that in Q2 2020 our all trading, we made the same warning. So I just to tell you because the base for me is more 5 for quarter and 6, 5 and 6. So you can consider -- take it like that. And it's gas and power team, which -- because iGRP includes everything. I will not give more detail on that.

And that's the beauty of the integration. The fact that at the same time, we can deliver high performance in terms of gas trading, but also electricity trading as well.

Yes. Libya. Yes, in Libya, there is in our, I would say, working capital.

Yes.

We had an amount of around $1 billion, a positive...

End of '21.

End of '21, I will be very transparent to you, end of December 2021, there is $1 billion, which is in all balance sheet, which has been transferred in Libya to the Libya government. Why it was in our balance sheet? Like it was with all the partners is that there was a debate to which institution we should direct the $1 billion. And obviously, we were all very careful together with our colleagues, partners on the Waha field, not to direct that to the wrong institution. We wanted that to be sure that it was a central bank of Libya and the right account, not to be accused of mismanagement.

So it took a little time to clarify the paperwork, and we received the instruction, a clear and valid instruction in January. So the $1 billion, which is in our working capital has disappeared now, end of March, it will not be somewhere there. But there are other good elements by end of March, margin calls and things like that, which will compensate working capital. So yes, it's true, but it's not a major point. We did not use it to make buybacks, so it's okay.

Next question comes from the line of Lucas Herrmann from Exane.

Two, if I might as well. I wanted to start with Russia. We've been hugely successful. And the value of the assets has obviously increased considerably. But so too is obviously the value of the cash flows. I just wondered if you could give us an indication of what's the dividend that you now received or expect to receive from Novatek? What's the benefit if you can provide it that you derive from the volumes that you take from Yamal LNG?

And I think most importantly, what cash flows or equity cash flows has the company actually received now from the Yamal LNG plant or to what extent are they still directed paying down debt? And second, if I might, probably for you, Jean-Pierre, is just -- when I look at the associate line in iGRP, how much of that now is coming from liquefaction? And how much of the associate line ballpark percentage is coming from the power business or the integrated renewable business?

Perhaps on equity affiliate contributions, I do not have a specific figure from LNG, but globally at the level of the group, 21% of our result is coming from equity affiliates contribution.

The other question was LNG versus renewables, it was the question.

At present time, of course, the main part is coming from LNG. For sure. I mentioned that renewable and electricity, we start seeing contribution 20%, 21% around $600 million or $700 million. Of course, it will grow in the future. So at present time, out of the 20%, 21% result coming from equity affiliates, most of the contribution came from LNG for obvious reason. It is Yamal and these type of businesses, of course.

So I will just give you the global cash flow from Russia because, of course, with the crisis, we look at the figure to know what was the risk is around $1.5 billion in 2021, which honestly, at the size compared to a $30 billion is not -- yes, it's sizable, but it's for 5%. So in the past 1, 1.5 figure, I remember Yamal LNG when it's stopped was around $1 billion per year as well. So we experienced this type of situation. But I hope not because I think for Europe, it's very important. By the way, I can tell you the consequence of any energy sanctions on Russia. I think globally, the company is winning because the impact on the oil prices and gas prices will be huge.

So yes, I would say, our operations in Russia, our assets in Russia might be given us some headaches and to manage it. But having said that, we have been -- by the way, I said $1.5 billion, it's a big mistake. It's EUR 1.3 billion because I must not speak in dollars about Russia, just to give you the magnitude. So it has increased a lot. The dividend. I think the Novatek dividend represent more or less $500 million per year, more or less. I mean it has increased, but it's the idea.

Next question comes from the line of Christopher Kuplent from Bank of America.

I think I might have one for each of you. Patrick, maybe you can give us a wider update on the current security situations. As you see it on the ground, you mentioned Yemen just now. I'd be interested in Mozambique and the prospect for bring back staff.

And perhaps for you, Jean-Pierre, when we talk about -- and many questions have been asked already. I appreciate that on buybacks and shareholder distributions. What should we use as most appropriate metric that you would consider is an appropriate allocation of capital during these relatively high oil and gas price times to shareholders versus to your balance sheet.

Mozambique, I'll let -- I'll give time to Jean-Pierre, a difficult question. Mozambique, I visited Mozambique very -- 10 days ago. I met with President, Nyusi. And some of my people went into Cabo Delgado, not me at this stage. There have been -- let's be clear, it's a war. You have some terrorists. So it's no more a matter of TotalEnergies to be involved in solving that situation. And we will come back -- we could envisage to come back and to restart the project on the nuance there will be peace. I mean, peaceful situation, which means not only having been able to secure security to, I would say, take back the control of the security, but also to have population, the civil population back in the villages and with a normal life. That will be the signal. There is no way for and we will not build a plant in a country where we'll be surrounded by soldiers. It does not work like that.

Having said that, there have been some clear improvement on the ground. Since the involvement and the Mozambique arrangement with the SADC, I would say, [proof], I mean, yes, consortium of different countries, including Rwanda, they managed to get back the security in some key areas around Palma, where we are -- our project is around Mocímboa da Praia who knows Mozambique, I become an expert, but not -- they do not control today to full Cabo Delgado.

And for me, as long as it's not control security. Why it's important? Because the population will come back only when security will be under control and all that is linked for us. But I mean, I have no idea when we can start the project back. But my view is that the conditions under which we could -- we start the projects might be fulfilled, maybe it will take a year, I don't know. We'll see, we observe. And we are -- what is good, we have the same vision with the authorities of Mozambique of what needs to be achieved. There is no pressure for us to exit out of force majeure. And we have established, I would say -- we have frozen a very fewer contractors.

We know that -- when we will say, yes, we can come back, it will take 6 months really to start up again. But again, my priority, it's a matter of sustainability of that and human rights. And so we'll not relaunch the project as long as I see photos from refugee camps around the site. But again, it's not negative. It's still -- it's for me a project, and we are monitoring the situation because we think that the authorities of Mozambique are taking the right decisions in terms of security.

So let's observe. The contribution TotalEnergies today and its partners is mainly to contribute to the social life, I would say. We have engaged with NGOs to see if we could -- because all the stability in this part of Mozambique will also come from giving some few jobs, some prosperity share without waiting the gas to be produced, but we need clearly to help the local populations to see some, I would say, some shared prosperity from the project before.

But by just the agriculture and buying food from these farmers for feeding our teams on the project, but we need to act on the ground and to -- it's a condition of the security for me. So that could take time as well. But the gas is there, the project is there, the LNG demand is there. So now it's a question of passions and in order to be able to execute the project.

And just a quick one. That probably means you've not budgeted a huge amount in your CapEx guidance for '22 as far as Mozambique is concerned.

No, you don't have. And by the way, you don't have for another reason is that, as you know, we have a project financing in place. We stopped if we just -- a day before, it was frozen.

Frozen the financing, yes.

The day after we declared the force majeure. We gave the money back. We stopped the letters. We didn't want to get the financing. So we know that the project financing is in place. And it's easy for us if we reactivate the project to activate the project financing. So in terms of impacting the CapEx, we had more CapEx than expected in '21, in fact. It's why we went a little above the [13] by the way, on the Upstream part, but no in '22.

And on gearing, so honestly, I do not have any magic figure. So we think, once again, that balance sheet is having a -- strong balance sheet is key to face a potential downturn in our environment. It's not obviously the case. We do not -- what we anticipate at the present time. You know all the different elements, the way we will allocate the cash flows. So you know the guidance we gave for discipline and you know that we are disciplined regarding CapEx spend. You know the dividend.

So $8 billion, more or less full cash dividend, so plus 5%, as Patrick mentioned to you. The $2 billion for the first semester. So of course, the balance will go to decrease the gearing. And just to give you perhaps one figure for an additional $1 billion of cash flow, the gearing will be down by 0.6%, more or less. So that means that if we are successful, if the environment continues to be very supportive, of course, the gearing could go below the current level. We have no problem with that.

I have no problem to have -- if gearing is going down, it's good for us. We'll have a reserve of cash for benefit -- to be countercycle when we have to be countercycles.

So but again, on the answer is more for me it's not one, again, the other is shareholder distribution. We showed -- I think I told you we were at 33%. I guided you towards the 40%. So you can see the range of it. And if there's more to come. At this stage, we consider it will be to deleverage the company. And that's another maybe -- I'm sure, mistake we should not do is believing that we are entering into a long high cycle. Each time we have said that the year after, it's a catastrophe. So I'm very prudent on this part. Because it's obvious if price remain high, you will have more investors and more oil coming and it takes 2, 3 years, but then you have the impact.

In the meantime, the best is to strengthen the company and to be ready then to use the balance sheet because opportunities will come in the different energies. And it might be a way, by the way, opportunities come to accelerate the transition.

Understood. I think the 40% is a great answer.

Next question comes from the line of Alastair Syme from Citi.

Patrick, can you talk about unit development costs in the Upstream, and I mean both across oil and gas. If I remember rightly, you used to talk about a figure of about 50,000 barrels per day on unit development costs. And I just wonder if you could update that figure for the current cost and environmental portfolio. And what I'm getting at here is that the Upstream CapEx that you're guiding to in 2022 is well below where it was in '19. So I'm just trying to understand how much of that has changed in emphasis versus lower cost versus any assumptions on disposals that you're making in 2022.

And then the second question, which is a point of a clarification on your reserve replacement ratio because 121% was sitting on the slide labeled oil. I wasn't sure whether that was just for the oil part of the business or that was across the entire Upstream?

You need to listen. The second answer is -- it's in the slide oil, but it's oil and gas, it's a global one. We didn't know where to put it. We put it there yesterday evening because we got the figure quite late. So there was not a perfect position. We could have done it elsewhere. So it's oil and gas. So reverse replacement rate global one 121% on 1 year and 116% on 3 years. So the second answer is this is the first 1. Yes, it's true, but we report in net investments and that clearly, there are some sales on the E&P side embedded in the budget. So the organic part of the CapEx for E&P is higher than the $7 billion, you could -- or $6, billion, $7 billion -- I think it's $8 billion, more or less. And but you fully have an assumption of around $2 billion of sales, more or less. It's more as the metrics, but I think if I remember well, what we have.

Obviously, the $50,000 per barrel per day of flowing barrel is a metric where today, we don't see any inflation in the projects at this stage, a little inflation. We've seen some inflation on steel, I would say, in the Uganda project. I think we -- in the last -- the delay in the last year costed us a little -- some extra, but we are managing that, I think, some flexible contracts. So at this stage, the $50,000 per barrel flowing barrel because we are targeting some low-cost barrel, I would say, is -- you can still consider it.

Next question comes from the line of Paul Cheng from Scotiabank.

Patrick, you mentioned about Suriname that you may be able to identify the oil development by the end of the year. So what exactly we have to do in order for us to reach that space? How far we are from reaching that kind of decision?

And the second point is that on -- second question, on the LNG sales mix that the page in your presentation, it looked like about 40%, 45% of the sales is in spot. So we assume that volume is totally linked to the spot LNG price or that they are still, to a large part, linked to the long-term oil prices.

So Suriname is just drilling. We need to appraise. We have several discoveries. We have a plan. I think we have 1, 2, 3 wells to drill in order to confirm. I mean, we have 3 -- next 3 wells on the self-run pole where we have many different discoveries. I think with the 3 wells we will comfort us capacity to -- again, you know the point is that we are targeting enough oil pool to avoid -- to have -- to find a solution for commercialization of the gas, which might be tricky and delay everything.

So there are 3 wells for me coming, and we intend to drill them, all of them by '22. So I think it's why I was answering end of '22 I hope we'll have high things plan. And I would say, the self-run pole because then we explore on the north as well of the block. But where we have made discoveries mainly on the southern part of the block. For me, after these 3 wells, we have a clarity of what can be done and the size of it engaging towards development. So that's the point where I am today.

If I had to explain you all details, it could take 2 hours because there are plenty of cases, assumptions, et cetera. So we need to drill. Second, and we find hydrocarbon (inaudible) don't worry. But the question is of which oil, of which gas, et cetera.

So on the other part, yes, you are right. It's a 60% long-term and 40% spot. Spot is pure spot. I mean spot is 2 things, in fact. In the spot volume, you have 10 million tons, let's say, as a round figure, which is 20% is [old] deals, which are spot deals, which means we have the vessels, we have the LNG tankers and we buy spot and we sell spot and we make small money on the difference between buying arbitrating. But it's a pure spot. And then in our portfolio of the marketing team, there are contracts which are linked to spot indicator, I would say, either JKM or NBP. And these ones are not oil linked. If they oil linked, they are more in the long-term part. I'm speaking under the eyes of Stephane. If I made a mistake, you raise your -- it's okay? It's okay. So the answer is right. That's my answer.

Patrick, on the second component, you're saying that you're linking to the spot. How big is that volume?

Sorry? How big is the...

You mentioned earlier that that's a portion of the volume that is based on your marketing team and that those is linked to the spot LNG price market. How big is those volume?

Again, you have 44 million tons, if I remember, you deduct 10 million. So we have 34 million tons. And you know the proportion of long term.

So long term is 60% of 34 million. So it makes 26 million. So 36 million minus 26 million makes 10 million tons. So you have -- so it's 10 million, 10 million, more or less and 26 million tons. All that is in the slide. You take your finger, you count.

That was the last question. I would like now to hand back over to the speakers for final remarks.

Thank you. So thank you for your attention. Yes, it's true that the results are, I think, in line with -- more than in line because we beat the consensus by 10%, so stronger delivery, but yet more to come. it's easier, honestly, to monitor the company this year than last year where we had no visibility. Even if -- of course, we must continue to be very focused. And I know all the teams are very focused on the delivery of all these production volumes in marketing, petroleum products in refining petrochemicals.

And I want to invite you to join us on March 24. I don't know if it will be virtual or in-person with this pandemic. We'll let you know that's what we intend to do. If it can be in-person, we'll do it. It will be probably a more presentation than today because we intend to present you the sustainability and climate report but also to come back on the strategy and I think the visibility of where we go in order to prepare the general assembly of shareholders.

So thank you for your attention, and wish you the best for the next month and see you on March 24.