Ladies and gentlemen, thank you for standing by, and welcome to TotalEnergies's 2021 results and 2022 outlook conference call. At this time, all participants are in a listen-only mode. After the speech, there will be a question-and-answer session. To ask a question during the session, you will need to press star one on your telephone. 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 Pouyanné, 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. We are more concerned today as a, I would say, a call on our Q4 and yearly 2021 results and our objective 2022 than as a full presentation. You will understand why at the end of the presentation, because we'll give you a new date for a new meeting soon. We have condensed 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 end of September, which does not change, obviously, even if we benefit from better environments today. 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. 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 and Brittany. 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, no humor from my side there. Really we went from, I would say, a historic bottom in terms of results last year, facing hard times, to a record results and cash flows in 2022. In fact, we entered into 2021. We entered into 2021, I would say, quite prudently with no visibility. It was my message one 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 enter into 2022. In fact, 2021 was also, I would say, marked by 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. We have benefited during the second half of 2021, 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 two 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, has a key role. The demand for gas, because it's a source of electricity, has been huge, and LNG, and the competition between Asia and Europe to get this LNG led to quite high prices, very high prices, exceptional ones. The second lesson that we can derive is that really, again, this energy transition is leading to more complexity, more volatility in energy markets. From this perspective, we are more and more, I would say, convinced that the multi-energy model that we're developing within TotalEnergies is a right way to leverage this complexity and this interconnection between energy markets. The year 2021 will also remain, I would say, for us, of course, an historic year because, not only because of our reserves and cash flow that Jean-Pierre will present you, but also because this is a year where we moved from Total to TotalEnergies. It means a lot to us. It means, in fact, that the whole company, together with its shareholders, who 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, as a demonstration that our new multi-energy model is now in motion, and the 2021 key achievements illustrate that, I would say, this strategy. Of course, oil has provided, as was reported, is providing a record source of cash flow, which is to fund the transition. This is the engine, cash engine. 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 we 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. Clearly, in 2021, we had the benefit of this strategy, leveraging our number two 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 be to record EBITDA, otherwise there will be a problem as we are growing, but $1.4 billion in advance to our plan, which was a little less than a billion. 10 GW of renewable capacity, 6 million electricity customers. Now this segment represent 25% of our CapEx, in line with the allocation, 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 to our net zero emission by diminishing our emissions. We'll come back on it, and including methane. We have 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 new 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. 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 a 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 two 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 exercise. Of course, this has been decided because it's supported by a sustainable underlying cash flow growth, and we'll come back on it. The second decision, as we announced in 2021, is to share the present oil and gas price upside by a new tranche of buyback. We bought back $1.5 billion in the second half of 2021. We increased for the first half of 2022 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 costs portfolio. 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 majors have progressed to an impressive safety standard of less than one recordable injury per million man-hours. Far below, that's what you can see on the slides here. Far below the TRIR, 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. Unfortunately, we had a fatality in 2021 in our operation. An electrician lost his life in Kazakhstan in 2021. This is a grim reminder that we need to implement constant improvement 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 TRIR 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. It will take some time and may have an impact during the integration phase. You can see that the progress that has been done on that field are impressive as well. 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 will 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. 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 quotas, but does not appear to have lots of spare capacity. Years of under investments, I would say since 2015, should lead to tension on supply and should support prices. The 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. No wonder prices are going up. 2021 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 coal, or both. For instance, China, Latin America, and Europe. Supplies were tight, and we saw Europe competing with Asia for LNG cargos. As you know, several major LNG projects have been delayed, many of those due to COVID-19. The LNG oversupply 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 have driven up power prices, as you can see on the slide as well. First, a focus on our Q4 performance. The highest quarter in terms of CFFO, cash flow generated from our operations and net result in the history 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 hitting all-time highs above $30 per million BTU. And at the same time, European power above EUR 100 per megawatt hour. In absolute terms, our leverage to oil prices one, the main, 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. In terms of productive increases, integrated LNG grew by 2.5 times with a 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. Renewable and electricity grew their positive contribution by 1.5 times, 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 hits a record high of close to $30 billion, almost doubling compared to 2020 figure. Upstream was clearly the cash machine with 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 volumes 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. Renewable and electricity, while still in early days, made a positive contribution of close to $1 billion. In this context, no surprise we doubled our EBITDA in 2021 compared to 2020 at $42 billion. As you know, controlling the break-even is at the heart of our sustainability. We have leveled our pre-dividend organic break-even below $25 per barrel. At this level, we are clearly more resilient to potential downturns in the environment, and the low break-evens also increased upside in a rising price environment. That's exactly what we are able to demonstrate last year. Net results and profitability were at record-setting in 2021, but it was not an 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. 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, renewable 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's 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 Petrocedeño to PDVSA in Venezuela. We recorded this one point five billion dollar loss in our statement end of June. This adjustment takes into account as well a $300 million impairment linked to our withdrawal from Myanmar. For the computation of the impairment of potential impairments, we have taken into account the net zero scenarios computed by the IEA for our price trajectory as assumptions. The oil price trajectory converge 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. We have 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-19 crisis, we came up on top of collapsing oil prices. We cut CapEx by 25% from $17 billion in 2019 to $13 billion in 2020. We have established a target range for net investments of $30 billion-$15 billion per year to 2025. 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. 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. Renewable and electricity on one side, LNG and gas on the other side. In fact, renewable and electricity represented more than $3 billion or 25% of our 2021 CapEx. The remaining parts, close to 25% at $3.1 billion, was dedicated to LNG and gas. 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 maintain within our company. We have cut our OPEX in half since 2014 to nearly $5 per barrel equivalents. The upstream Scope 1 and 2 emission intensity 100% on operated assets has been reduced to 17 kilograms CO2 per barrel of oil equivalents. 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. 17% increase from the previous year, but still below pre-COVID level. The impact of lockdowns linked to the pandemic was particularly hard on our refining businesses. Refining suffered due to the drop in demand for road and aviation fuel, and we adjusted runs 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, remain a bright spot, benefiting from the very dynamic polymer markets, which are linked to health and safety products. Marketing and 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 and 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-19 2019 level. That provides us with a strong base we can use to leverage favorable market conditions, 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 exploration part of the business, provides 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 three to six month 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 plant, is the integrated tool we use to leverage and arbitrage volatility and across the global markets. Cash flow from the downstream parts of the business increased by $0.6 billion. $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 regas 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, 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, the renewable and electricity business. Compared to LNG, our renewable and electricity business is at an early stage of development for sure. 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 GW of gross installed renewable power generation capacity. Our portfolio has grown to 43 GW of gross capacity, including this 10 GW of installed capacity, 7 GW under construction, and 26 GW in development. Like LNG, we are building a renewable and electricity business that is integrated along the entire value chain. As illustrated on the slide, with interest in storage, in trading, EVs, mobility, and retail distribution. I will not comment in detail 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 wind. I will just mention, 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 investment. Now, given Adani Green share price increase, this investment is valued at around $8 billion. In 2021, renewable and electricity outperformed our expectations. Net electricity production increased to 21 terawatt-hours, 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 four CCGT plants, two in France and two in Spain, in late 2020. Of course, we benefited from exceptional volatility captured by our electricity trading. Our proportional share of EBITDA for renewable electricity in 2021 was $1.4 billion, about 2.5 times 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. 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 operations were back into the business. We reduced debt and lowered the gearing to 15% at year-end 2021. The gearing I had in mind 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. We allocated one third, 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 + $1.5 billion in buybacks in Q4 2021. Shareholder return is a 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 2021 results, which clearly positioned us quite well. 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 lose our discipline on the investment part, but clearly, we think that 2022 is much more largely de-risked in terms of market environment. Our outlook for 2022 is clearly for another probably strong year in terms of results. A year where the priority for all the teams is again to focus on delivery. Delivering our production, utilization rate of our refineries, delivering our expansion in renewables, delivering on our marketing margins. All that is a key to increase the value and the shareholder returns. We have, as you know, a 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 the commodity market 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 overinvestment 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 pre-pandemic levels, so there is still room for increasing demand for oil products. Again, this is favorable to, I would say, the outlook for 2022. We should not as well forget that the 2021 results demonstrated that we have a clear ability to leverage a favorable environment, and that the year 2020 demonstrating the resilient performance when we have to reverse the harsh environment. Going forward, I really think that we are focusing now on transforming TotalEnergies into a sustainable multi-energy company that can best navigate the transition toward a net zero world. Getting to on 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, almost core value of the company, reducing these emissions. 2021 is another year of decrease. You have there the figures which have been calculated by excluding a specific COVID impact. On Scope 1 and Scope 2, 37 million tons, so reduction from 20% compared to 2015. I remind you that we have a target of -40% by 2030. We are well on the journey to that. That's the first point. I would remind you as well that in this figure is including all the emissions of the CCGT, which were not in the perimeter of 2015. It's 4 million tons. That means that in fact, the efforts done by all the teams in exploration, production, and refining, and chemicals mainly, have already been quite impressive, moving down from 45 to less than 35. Then another metric important when we speak about our emissions and our operated activities is the 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. From 2015- 2021, it's a reduction of almost 50%. 14, we are a little less 49,000 tons per year for the year 2021 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 next to zero for methane emissions as soon as possible. It's important because, of course, our involvement in the natural gas business is strong, so it's a matter of consistency. On the Scope 3, as you can see, we can see that we are driving down on 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 to, I would say, to arbitrate the low margin sales. Our contribution to the Green Deal is clear, -23% on Scope 1, 2, and 3 in Europe. Globally speaking, we said that during the decade 2020-2030, our mission 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 tons figure seems to be the same, but the 410 is 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 the carbon intensity of our sales, which is down by 11% compared to 2015. Our objectives is -20% by 2030. This year, but again, we are well on the way to get the objective. 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. Coming back to 2022, yes, we have announced in September a capital investment strategy of $13 billion-$15 billion. For the year 2022, 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. Fifty percent on the, what I call the oil maintenance. That means that we have no ambition to grow in oil. We want to maintain the oil production upstream and LNGs or refining around 1.3 million barrels per day. This require capital because, as you know, we have a natural decline, around 3%. 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. This 50% are necessary to maintain, to stabilize. The rest, 50%, is to grow, to grow on the two pillars. One pillar is renewable and electricity, which has taken 25% of our global CapEx. We'll go for more for $3-$3.5 billion in 2022. The other pillar is LNG and gas. I would say, and new molecules like, in gas, you could understand also biogas and hydrogen, even if it's yet limited in 2022. Going to end of this field, let's begin by oil. In oil, the program obviously again is to focus on delivery to on organic value creation. We have increased. It's part of the reason why the budget, CapEx budget increased in 2022 compared to 2021. We have reactivated the 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 that there is a limitation, which is a COVID-19 impact on the operation. It's not exactly the level where we were before the pandemic, but it's growing, and it will bring a contribution of around 50,000 barrels per day. Main asset being there, the Block XVII in Angola. I would also remind that we have some startups in 2022, in particular, Mero 1, Brazil. The first of the four Meros is coming on stream by middle of the year, Ikike, Nigeria, and some new fields in the Novatek portfolio. We have also, in terms of organic value creation, continuing to explore. In particular, we have some very high-impact wells. We have three, in fact, being drilled today, one in Brazil, Marolo prospect. Our explorers have good hope. High hope, I would say. Suriname continues to drill to appraise the world potential of the block with in view to identify oil development by end of 2022. Namibia is another high-impact well which is being drilled. That's for the organic part. You know, to upgrade our portfolio and which we also use, I would say, M&A with two clear axes, divesting mature high-emission assets, non-core, that we have done this year in Gabon in Angola, Block XIV. So that's one part, and we sold for $2 billion of assets. I would say it's not because price of oil is high that we must stop this strategy. We must, on the contrary, implement it in 2022, so there is more to come of these mature marginal fields, because probably we get more value from investors in 2022 than before. On the other side, we are acquiring. We continue to have an acquisition of interest in low cost, low emission assets. I would say that I consider we have been very successful in the four auctions end of December by getting access to two giant deepwater fields, Sépia and Atapu surplus PSCs, with quite good returns. We are very happy to be partner of these two giant fields. 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 2025, now it's by 2023 with the additions we have done, and really, that will be some cash engine for oil business in 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 investing in low-cost, low-emission projects to have a reserve replacement rate in 2021 of 123%, the average is 116%. This strategy can work to focus on, again, some low-cost, low-emissions oil and gas fields. For 2022, one figure for the upstream division and Nicolas' teams is 2.9 million barrels of oil per day or equivalent, +2%. There are some plus short cycle, some new productions. There are some minus when we withdraw from Myanmar, obviously, we lose some productions with the gas there. This is a clear focus of all the teams I know in E&P, and thank you for that. Downstream is the same message, in fact. It's on two pillars there. It's a delivery on one side. For refining, it's coming back to, I would say, a decent utilization rate, 680%. As Jean-Pierre said, the year 2021 was rough, for margins were low, energy prices are high, still high. In particular, natural gas is impacting quite a lot the refining. Also we had honestly some operational issues in some plants. Teams are mobilized there, which is good because that means that we have extra cash which might be delivered. The other part of the delivery is our cracker in the U.S. We are expecting it to be also transparent. It suffered from the COVID-19, I would say impact in terms of capacity to deliver it, 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. 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. In terms of integration, it will be economically. It's not too bad. I would say the other part for refining and chemicals is to engage into the transformation on biofuels on one side, and also on circular economy with more polymers being produced from bio and recycled polymers. 100,000 tons per year is the target for 2022. On marketing and 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 non-fuel revenues. This is a source of additional cash. We have a target of 35%. But also at the same time, continuing to be selective on oil product sales by arbitraging the low margins, margin sales. Compared to 2015, the objective is to decrease this type of sales by 20%. 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 may have the same trend than before going to a retail station. There, we need to invest in high-power charging because these are the expectations and will be the focus of investments. All in all, we are expecting another good year, but you know, we have not been disappointed by the downstreams for many years. $5.5 billion in 2021, more than $6 billion in 2022. The extra should come, of course, from refining, which was low. Maybe the petrochemicals or polymer will not be able to redeliver the exceptional year of 2021, that's the market. I think this is again important for the whole company and to fund the transformation. 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 tons, mainly driven by long-term contracts. 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 is for upstream. Volatile, this is what our downstream people like to make arbitration, I would say. It seems to be strange that we like volatility, but in fact, we have some big teams who love that. On the upstream part, we have two information there. 80% of our, I would say, of our production, LNG production, is linked to oil. Of course, we have a leverage to oil, which is quite strong. We have also a leverage to, I would say, spot markets and BP indicators. Before, we are giving you a million dollars at $1 per million BTU. With the volatility, we say, no, we will give it for $10 per million BTU because we plan on $10 as a price on NBP, but maybe it will be 20 like it is, more than 20 since the beginning of the year. It's $800 million extra cash for $10 per million BTU only on the upstream part of the LNG. In fact, another information which is important to us is that, and Jean-Pierre told you, we have a time lag of 3-6 months in our LNG formula. We embark, in fact, in 2022 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 2021. That's important. Again, on the other side, our downstream LNG teams, they have the capacity to arbitrage and to again get benefit from volatility with two key indicators which illustrate their capacity. The first one, they have a global portfolio flexibility of 65%, so they can change the destination of 65% of the, I would say, the sales portfolio they have in their arsenal. Second, remember that we are number one 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. The capacity to arbitrate between China, Asia and Europe, of course, is a strong engine for cash flow. This of course, LNG again like 2021, even 2022 more than 2021, 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, 2022, because we'll go from growing from 3 GW per year to 6 GW per year. In 2019 it was 7 GW. We went from 4 GW - 7 GW in 2020, from 4 GW-7 GW to 10 in 2021, so it was +3, +3. Now we enter into a new phase of growth, which is +6, to which more than 16 and the +6 in fact with four times six, we reach the 35 GW. Before to have a new phase beyond 2025, which is +9, +10 GW to reach the 100. So the capacity, all that is not a dream from the CEO. All that are projects where people are working on the ground in many countries to deliver it. One spectacular project which will come on stream will be Al Kharsaah in Qatar, 800 MW. 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. Definitely, I think it will be good to understand what it means to build a 10-kilometer by 10-kilometer solar plants in the middle of the desert. Not playing football on the solar panels, but just to deliver power to Qatar. Of course, I can tell you we are all mobilized so that they will have this green power to fill this stadium during the World Cup. The other part of the 2022, I would say new, startups are in offshore wind. In fact, the field of Yunlin in Taiwan started production, the first generator in 2021, but very limited. The real startup is in 2022. There is in Scotland the first also turbines, which will generate power together with SSE on the Seagreen projects. 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. Production will increase by, let's say, 25%, mainly from renewables, by the way, not from CCGT this time. EBITDA in terms of what you say, proportional share of EBITDA, you could be surprised that this, you don't see the translation of the 25% in the EBITDA. It's more than 1.5. It's not because we are prudent. It's because, as Jean-Pierre told you, in the $1.4 billion of 2021, clearly there is an exceptional result from our traders in Q4, benefiting from exceptional level of European power. I hope they will replicate it, but you know, it's never granted. We are prudent of planning these type of results. But again, it's begun to be material, $1.5 billion of EBITDA. Of course, we have a global EBITDA of $40 billion. But in my view, it's becoming to be a material contribution to the company. If I summarize that for 2022, our generation of cash, of course, and this is a little complex scheme because we try to show you that, yes, we embed a $1 billion underlying LNG and power, by the way, because part of it is also justified by power, $1 billion, which will justify the increase of dividend. After you read it, you can read that we have, yes, delivered the debt-adjusted cash flow in 2021 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 $26. In 2022, this same environment will give $27, so an additional $1 billion. If I'm coming back in a more plausible environment, because don't conclude that I'm very pessimistic about our price. I'm not pessimistic. Just to make the demonstration, I would have preferred the gray under and the blue on the top, but that's the way it has 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, we would get something like $34 billion. Why? Because you have the metrics of 33, exactly, 33 or 34. We have the metrics for $10 Brent, we have an extra $3.2 billion. For $10 per billion BTU of NBP, we have an extra $3 billion. The $3 billion represent the LNG part, I gave you $800 million, plus the domestic, the gas, European gas, Norwegian gas, UK gas, which is delivering the other $2.2 billion. 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'll be, but we have room. Not only, and the conclusion of this slide, not only to increase the interim dividends, which is sustained by this $1 billion. 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 represent an increase of 5%. It's why you have the 5% announced this morning. We have also room to share with you part of the surplus extra, and this is the first tranche for 2022 will be $2 billion. I'm coming to this slide that 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 +5%, just explain to you why. The balance sheet credit A rating, Standard & Poor's is even A with positive trend, I think. Gearing under 20%, we are at 15%, so we'll continue to consolidate it. Share buyback, sharing surplus. It's from high oil and gas prices, before we were giving a guidance on oil prices. This is a gas pricing. Gas prices are also giving us, I would say, short-term higher revenues. EUR 2 billion for the first half. That 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. If I just want to make a benchmark of our results and our shareholder returns, I would say that if we look to this chart, you can see that in terms of return on equity, with 17%, I think we have waited quite a long to see these type of figures, about 15%. We are number one among the majors. By the way, we have also put there, ESG risk rating, the one by Sustainalytics. Don't make a mistake. The lower you are, the better you are. This is the way they make the notation. There again, we have, well, we are well ranked. For shareholders, we have returned 33% in 2021 of the CFFO, which is comparable. There is one competitor which is giving a little more, but I think this benchmark is a good benchmark for us. In terms of TSR on the last three, on the three-year TSR, with 12%, we are the number two, far above our two European competitors. 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 upsides from high energy prices. You've seen the figures, $10 per barrel, more than $3 billion, $10 per MMBtu, more, $3 billion. It's, we have demonstrated in 2021 that we are able to capture it. That's important in particular with the oil projects, 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, oil, 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 competencies of an oil and gas company, but also of electrons, which is growing power. The use of grid power is growing, 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. This is what is underpinning our multi-energy and integrated strategy. I would add that, you know, in our companies, 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, our worldwide footprint to manage that. 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. You will see the mix of TotalEnergies in the future 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. Thanks to our strong balance sheets, that can be also a differentiator from some competitors in that field. Knowing that we continue, I confirm to you that all the projects in which we invest have to. We are selective and we are rich. We are targeting more than 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 I've already insisted to that. But I will also end my presentation with what we call that about extra-financial ESG reporting and progress. We attach great importance. We know that for investors it's more and more important. 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 our resolution 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 24th, Sustainability and Climate Progress Report 2022. We'll have the opportunity the same day to make a presentation to investors and analysts. Sustainability and climate are intrinsically linked to strategy. Obviously, we'll review the strategy. This is why we have done it, not done it today again. The other decision which has been taken is that on May 25, as 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 on the trajectory of transformation that we have entered into. Thank you for your attention. Now with Jean-Pierre and my colleagues, which are in the room, not they're behind the desk, but in the room, ready to answer to your questions. Thank you for your attention. Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. As a reminder, if you wish to ask a question, please press star one on your telephone and wait for your name to be announced. Please kindly mute any audio sources while asking a question. If you wish to cancel your request, please press the hash key. Once again, please press star one if you wish to ask a question. We've got the first question from the line of Irene Himona from Société Générale. Please go ahead. Thank you very much. Good afternoon. Congratulations on what were very strong results. I had two questions, please, on distribution policy. Firstly, on the buyback, if you could please clarify the timing or the phasing of the EUR 2 billion buyback you announced for the first half of the year. Then in terms of visibility in the future buyback, should we anticipate you announcing the amounts 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 you anticipate LNG and power markets to continue to remain tight throughout 2022? Thank you. Thank you, Irene, for your kind words. I would say first, the timing, I just mentioned it in my speech. Clearly, it will be executed during the first half of 2022 because the board of directors wanted also to look what is the share price. You know, we'll not buy if the shares continue to grow. There is a certain point. It's why we also want to have a program on the first half. Jean-Pierre and his teams will execute the $2 billion in the coming months with the rules, of course, during the windows on which we can intervene on the markets. That's the first. Second, I mean, the board wanted to monitor that according to we'll see. You know, we could expect maybe more cash flows coming, more surplus cash flows. 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 result. Let's see. The technical answer is at least twice a year. Don't consider that the EUR 2 billion is only for the year. No, there is no hidden agenda. It's just for first half, and then we'll see. You know, in the past, each time we have announced a long buyback program, we were interrupted by some events on the market. Let's be prudent. Let's execute. You can consider that if the environment remain as it is, it will be at least the EUR 2 billion for the second part, if not more. On the dividend, I would say, I mean, no. What it means for me structural CFFO are 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, you know. The impact of the prices, we know that it's volatile. It is reported in what we call the surplus cash flow. We increase the dividend by 5% because we consider that we are on a growth trajectory. I remind you that in September, like we previously reminded you, that we are in a trajectory where the cash flow should grow by $5 billion at the same environment. It's the first tranche of this $5 billion for the next five 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, then the events with the crisis have disrupted everything. We have already announced that if we have an extra EUR 1 billion, we would allocate more or less 5% increase on the dividend. 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 a, I would say, conservative environment, we consider that I would say the 6 million tons extra volume LNG are there for long, and even in variety is that they will continue to increase because we have a growth trajectory. This is the 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. Thank you very much. Having said that, in answer to your question, I think that the LNG target will remain tight for a few years. If you remember as well, Irene, I knew that in 2018, 2019 people were speaking about oversupply by 2024, 2025. What they were forgetting is by 2024, 2025. In fact, we already announced by 2022, 2023 and I would say even 2024 with the COVID impact, we don't see much trains coming on stream. You know, 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 is 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. I'm That's why I'm prudent on the LNG side in terms of anticipation because again, gas is competing for coal, and if gas remain too high, coal will come back despite the climate change, or coal will not exit, more exactly. Thank you. Thank you. Next question comes from the line of Michele Della Vigna from Goldman Sachs. Please go ahead. Patrick Pouyanné and Jean-Pierre Sbraire, it's Michele Della Vigna. 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 you know, 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. On the other side, much higher costs across the value chain, and there is a beginning of a rate rise cycle with higher cost of capital as well for project financing. 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, you know, versus where, you know, you were seeing them one year ago? Thank you. Okay. The 40%, again, I just explained that it's. Yes, you are right. The way we calculate the dividend is, the increase of the dividend is plus $1.4 billion. It represent 5% of the $8.8 billion we distribute. That's right. It's a guideline guidance where we think it's a good guidance. Having said that, sometimes like in 2021, we were targeting that when the price increased quicker than we were able to make the buyback, so we reached 33. It's a 35%-40% range which is in the mindset of our board of directors. It's, if you want to model, you can use it. On the renewable part, I think, yes, things are moving. It's a matter of. This is, for me, something which where we have an evolution in the company. You know, when we enter into that field, we see, maybe it's a secure business, you know, you have these PPAs. But fairly, 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 are 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, arbitrage, et cetera. You've seen the positive results in 2021, fifteen years after we engage 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 a balance sheet, the capacity providing we have also storage capacities, providing we have also trading teams, strong teams, to leverage the volatility. 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. I think it's better to keep. When we analyze an investment 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, 2045. My view is that, yes, let's keep part of it on PPAs, where you secure, I would say, a base return, but we have to accept as well the profitability. We just recruited a chief economist outside of our oil and gas markets in the electricity markets in order to help us to better model that. 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. Thank you. Thank you. Next question comes from the line of Lydia Rainforth from Barclays. Please go ahead. Thank you and good afternoon. Hopefully, the March twenty-fourth 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 thing the best example of where multi-energy really works for Total? Secondly, on the renewables side, you talked about 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 you need to focus on? Then just very, very lastly, and just to pick up on the cash return, you mentioned the share price earlier. Is the buyback level dependent actually now on the share price? Thanks. The last question. Yes, there is a level where obviously it could become too expensive, so it, I don't want to cap the share price hike. Let's be clear. There might be an arbitration between having the debt going down, keeping the money, and then, you know, because we know the markets will be volatile. You know, the best buybacks for our investors and for the company, the best investments in buybacks is to buy the shares when the share is low, when the share is very high. The board will obviously monitor that. There is no. I mean, don't ask me the 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 criticize us somewhere, sometime when we buy, when it's high, you know. Why not keeping the money and then using it when the share is low? You know, we would have more. Last year was not possible, was the year when the share was at EUR 30 per share, but I know some investors who bought some shares at this level were not able to do it as a company. That's the point where just a remark. On the economic benefits on the integration, but there are several. One of them, in particular, in the case of Iraq, and we are using that in other oil countries, is that, you know, when you have developers willing to develop large projects in these emerging countries, they are all asking. 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 compare even to what we want to do in Iraq are the magnitude of the power revenues is not the same. You can find a way to, I would say, guarantee your electricity revenues by the oil revenues. There is a link there, which is a good leverage in terms of economic benefits and possibility to make the projects. I mean, and same, you know, at the end of the day, the gas resources which we leverage are also part of, I would say, an extensive contract, service contract. It's, I would not call that, I don't know what is the name of the contract in Iraq. I don't remember. 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 the revenues of one to leverage investment in the other. That's the beauty of it, you know. If I'm able to invest in different projects, then it's a question of managing the different parameters of the contract. Yeah. The advantage to be in more countries for renewable is that there are less competitors, you know. I will tell you the advantage is that first we are there. We know the country. We have a presence. You know, we have some people working already in marketing and services in EMEA. So we have a knowledge of the 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, I would say, on some countries, the main, the large countries which offer PPAs, which is not the case, of course, of all these emerging countries. Or the idea and what we are is, of course, it's complex in some of the smaller countries, but the profitability can be higher. This is what we are looking for, to have direct negotiation, to be able to leverage, I would say, what we can bring to the country in order to have a better profitability. I think this is an advantage of a company like TotalEnergies. We are present in many countries. It's long-established 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. Thank you. Next question comes from the line of Bertrand Hodée from Kepler Cheuvreux. Please go ahead. Hello. Thank you for taking my question. Congratulations again for the result and also for having the vision to grow your LNG portfolio back in 2018, 2019, especially with the acquisition of U.S. LNG portfolio from Engie and Toshiba at the time where those LNG contract would have probably provided some losses. I guess that was a countercyclical and wise strategy in my view. Now I want to understand more your sensitivity to spot LNG prices. 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 MMBtu move equals to around $3 billion of additional cash flow, $2.2 billion for upstream and $0.8 billion for LNG. Back in September, I reminded that you also highlighted that a $10 per MMBtu move in both MVP 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 two sensitivities because of the hedges you have? That is my third question. The second question is, should I also be right to assume that if you were to raise your medium-term assumption for both MVP and JKM, so spot LNG in Asia by $5 per MMBtu, we could also add $3 billion structural cash flow to your 2025 plan? Well, technical questions. First, yes, you are right on Toshiba, just to tell you that, today we are cash positive after 2021 without using the $800 million we receive. It's a profitable business. We have received $800 million, and we are already making more money. Just thank you for reminding that to everybody. I would say then your point. There is a point, yeah. We mentioned in September that when the difference between the JKM and NBP 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. 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. You have the results in the year, and you have the cash flow in the year after, if I remember correctly. You have a discrepancy between the results and the cash. In 2022, we'll get the results of the hedges which were implemented in 2021. Remember that the way we hedge is quarter after quarter. We did a new in first quarter of 2021, but the last quarter we should have waited for the long run of the year. No, we are not magicians. We would have done it, we would have waited, but we don't do work like that. We hedge quarter after quarter. In fact, what we embark 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. What we'll do this year, of course, we have today a spread between JKM and NBP which must be around $15-$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 2023, which is good. You know, that's good visibility. That is where it's not exactly the plan. In a permanent regime, your assumption for 2025 is right. $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 one year to another year because it depends. Of course, it's a permanent regime, but it means your $5 should be the same during. The spread should be the same along 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. If not, you call Jean-Pierre and Stefan, and they will explain to you. Fundamentally, yes, the answer is in 2022, we'll receive more cash than in 2021 from these hedges, because in 2021 we see the downturn in 2020, in 2022, 2020-2021, but 2022 is not a full year, I would say, compared to what could be done 2023. Yeah, is there something additional to come to us in terms of cash flow? Many thanks. Thank you. Next question comes from the line of Christyan Malek from JP Morgan. Please go ahead. Yeah. Hi, gentlemen. Thank you for the opportunity to ask questions and, honestly, 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 so certainly extraordinary in the context of having completed the FEED. You've got the semi- sub production facilities out to tender, and Valaris has got a 42-month drilling contract. With that in mind, it's clearly not in its infancy. 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? Should we draw conclusions around your appetite to invest within GOM within that context? Just trying to understand even from a policy standpoint how you see the U.S. from sort of investment standpoint. The second question relates to the very welcome sort of sustainability and climate progress report. I mean, within the framework of how you deliver these metrics and 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 you know some of the highest carbon intensive projects in the world? Thank you. Thank you, Christyan, for the two questions. 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 oil in this decision. It's a pure intrinsic decision linked to the project and linked also to our capital allocation. You know, we look at it's honestly at the limit, at the high limit of the range we gave ourselves. I remind you that we said to our to investors, we'll invest in oil portfolio, in oil greenfield projects, $20 per barrel, $30 of technical cost, CapEx plus OPEX, or $30 of break even. North Platte, because of its size, in fact, we knew it's not a giant field. It's not. It's really on the high side of these metrics, you know? That's one point. Second point, you know, we prefer to invest in Sépia and Atapu in Brazil than in North Platte. Yes, we have done our job because we were the operator, and we want our partner to be able, if they wish to do so, to hand over in a smooth way. All in all, at the end, we consider that we have better opportunities in our portfolio to allocate our capital. There is no politics behind it, just a 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 asset one by one. You know, 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 look at it. By the way, we begin, I think if I remember correctly, we have a 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. We are working on it. 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 for more assets, but you know, it's progress report, so we progress. I think we'll disclose more in our Sustainability and Climate Report than what we have done until now in a way which is more readable for you so that you can better maybe analyze the data. That's our intent. The idea for the board by submitting, by the way, to an advisory vote this report is that to consider that the same general assembly of shareholders approves the financial reporting that will approve the extra-financial reporting. We think this is a global trend we've seen after COP26, the ISSB and all these organizations willing to normalize, I would say the extra financial and we are willing to part 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 announce EUR 2 billion for first half, I'm not sure we'll decrease on the second half until our share will reach the roof. Unless the share will raise the roof. Thank you. Thanks, Patrick Pouyanné, and I look forward to the World Cup with you in Qatar. Very excited. Thank you. With more buybacks, I know. Thank you. Next question comes from the line of Biraj Borkhataria from RBC. Please go ahead. Hi. Thanks for taking my question. The first one is just a clarification on trading. You mentioned a $1 billion, I think you referred to integrated gas benefit in 2021, but I recall last quarter, you called out $500 million benefit, I guess implying that the trading contribution for gas, integrated gas was the same in Q4. Would have expected it to be better. 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 some kind of one-off or catch-up tax payment due in 2022. Is there any details you can provide on that? Thank you. Okay. I was wondering, I mean, what I think, have you seen the results from iGRP for Q4? They are quite exceptional. I think $6 billion, if I remember. Yes. Yep. We just sent a warning, but we consider it somewhere in this $6 billion. It's reported as recurring results, a $1 billion which has been clearly given by the, I would say, exceptional trading. I remind you that in Q2 2020 our oil trading, we made the same warning. I just to tell you, because the base for me is more $5 billion for a quarter than $6 billion. $5 billion and $6 billion. $5 billion and $6 billion. You can consider take it like that. It's gas and power team, which because iGRP includes everywhere, everything. I will not give more detail on that. That's the beauty of the integration. Oh, yeah. Pardon me? That's the beauty of the integration. The fact that at the same time, you can deliver high performance in terms of gas trading, but also on electricity trading as well. Yes. Libya. Yes, in Libya, there is in all, I would say, working capital. Yes. We add an amount of around $1 billion. End of. End of 2021. I will be very transparent to you. End of December 2021, there is $1 billion which is in all balance sheets. Balance sheets, yes. Which has been transferred in Libya to the Libyan 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. Obviously, we are 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. It took a little time to clarify the paperwork, and we received the instruction, a clear and valid instruction in January. The $1 billion, which is in our working capital, has disappeared now. End of March, it will not be anywhere there. there are other good elements by end of March, margin calls and things like that, which will compensate, you know, working capital. yes, it's true, but it's not a major point. We did not use it to make buybacks, so it's okay. Understood. Thank you. Thank you. Next question comes from the line of Lucas Herrmann from Exane. Please go ahead. Patrick Pouyanné, Jean-Pierre, thanks very much for your time. Patrick Pouyanné, it's nice to see you looking very well. Too, if I might as well. I want to start with Russia. You'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, you know, what’s the dividend that you now receive or expect to receive from Novatek? What’s the benefit, if you can provide it, that you derive from, you know, the volumes that you take from Yamal? I think the Yamal LNG, and I think most importantly, what cash flows or equity cash flows does the company actually receive now, from, you know, the Yamal LNG plant? Or to what extent are they still directed, you know, at paying down debt? The second, if I might, probably for you, Jean-Pierre. It's 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? Thanks very much. Perhaps on equity affiliate contributions. I do not have specific figure for, from LNG, but globally, at the level of the group, 21% of our result is coming from equity affiliates contribution. The question was LNG versus renewables, you know. It was the question. At present time, of course, the main part is coming from LNG. Yeah. For sure. I mentioned that renewable and electricity we start seeing contribution 2021 around $600 million-$700 million. Of course, it will grow in the future. At present time, out of the 21% result coming from equity affiliates, most of the contribution came from LNG for obvious reason. NLNG, Yamal, and this type of businesses, of course. I would 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 it's sizable, but it's 5%. You know, in the past, $1.5. I think I remember Yemen LNG when it stopped was around $1 billion per year as well. We experienced this type of situation and 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 oil prices and gas prices will be huge. Yes, I would say our operations in Russia, our assets in Russia might be giving us some headaches and to manage it. But having said that, we have been put. By the way, I said $1.5 billion, it's big mistake. It's EUR 1.3 billion, you know, because I must not speak in dollars about Russia. It just to give you the magnitude. It has increased a lot, the dividend. I think the Novatek dividends represent more or less $500 million per year, more or less. I mean, yeah, it has increased, but it's the idea. Okay? Okay. Thank you, Lucas. No, thank you very much. Thank you. Next question comes from the line of Christopher Kuplent from Bank of America. Please go ahead. Hello there. Good afternoon. Thanks for taking my questions. 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 bringing back staff. 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? Thank you. Mozambique. I'll give time to Jean-Pierre. Difficult question. Mozambique. I visited Mozambique 10 days ago. I met with President Nyusi, and some of my people went into Cabo Delgado, not me at this stage. You know. 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. We will come back. We could envisage to come back and to restart the projects only once there will be peace. I mean, a peaceful situation, which means not only having been able to secure the security to, I would say, take back the control of the security, but also to have populations, the civil population back in the villages and, with a normal life. That will be the signal. There is no way forward. We will not build a plant in a country where we'll be, surrounded by soldiers. You know, it does not work like that. Having said that, there have been some clear improvements on the ground, since the involvement and the Mozambique arrangement with the SADC, I would say, troops, I mean, or 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 Mocimboa da Praia, for those who knows Mozambique, have become an expert. They do not control today the full Cabo Delgado. For me, as long as it's not controlled 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. I mean, I have no idea when we can start the project back, but my view is that the conditions under which we could restart the projects might be fulfilled. Maybe it will take a year. I don't know. We'll see, we observe. 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, but we're out of force majeure. We have established, I would say, we have frozen every flow of contractors. We know that when we say, "Yes, we can come back," it will take six months really to start up again. My priority, it's a matter of sustainability, all that, and human rights, you know? We'll not relaunch the project as long as I see photos from refugee camps around the site. It's not negative. It still is 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. Let's observe. The contribution of 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 shared prosperity without waiting the gas to be produced before. That might just be agriculture and buying foods from these farmers for feeding our teams on the project, but we need to act on the ground. It's a condition of the security for me. That could take time as well. The gas is there, the project is there, the energy demand is there. Now it's a question of patience and in order to be able to execute the project. Thank you, Patrick. Sure. Just a quick one. That probably means you've not budgeted a huge amount in your CapEx guidance for 2022. Yes As far as Mozambique is concerned. No, we don't have. By the way, you don't have for another reason, is that, as you know, we have a project financing in place. We stopped just a day before it was frozen. Was frozen. It was frozen. 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. 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. In terms of impact in the CapEx, we had more CapEx than expected in 2021, in fact. It's why we went a little above the EUR 13 billion, by the way, on the upstream part, but no, in 2022. Okay. Thank you. On gearing, honestly, I do not have any magic figures. We think once again that having a strong balance sheet is key to face a potential downturn in our environment. It's not obviously the case, not what we anticipate at the present time. You know all the different elements, the way we will allocate the cash flows. You know the guidance we gave for discipline, and you know that we are disciplined regarding CapEx spends. You know the dividends, eight billion more or less full cash dividends, plus 5%, as Patrick mentioned to you. The two billion for the first semester, of course the balance will go to decrease the gearing. Just to give you perhaps one figure, for an additional EUR 1 billion of cash flow, the gearing will be down by 0.6%, more or less. That means that if we are successful, if the environment continue to be very supportive, of course the gearing could go below the current level. We have no problem with that. Again, I have no problem to have. If gearing is going down, it's good for us. We'll have a reserve of cash for benefiting to be countercyclical when we'll have to be countercyclical. But again, on the answer is more for me, it's not one view, again, it is shareholder distribution, which should, 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 it's more to come, at this stage, we consider it will be to leverage the company. And that's another mistake we should not do is believing that we are entering into a long high cycle. You know, each time we have said that, the year after, it's a catastrophe. I'm very prudent on this part because it's obvious, you know, if price remain high, you will have more investors and more oil coming, and it takes two, three years, but then you have the impact. In the meantime, the best is to strengthen the company. Balance sheet To be ready then to use the balance sheet because opportunities will come in the different energies. It might be a way, by the way, if opportunities come, to accelerate the transition. Understood. I think the 40% is a great answer. Thank you. Thank you. Next question comes from the line of Alastair Syme from Citi. Please go ahead. Thank you. Patrick, can you talk about unit development costs in the upstream? 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. I just want to. If you could update that figure for the current costs, environment, and portfolio. 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 2019. I'm just trying to understand how much of that is change in emphasis versus lower cost versus any assumptions on disposals that you're making in 2022. The second question, which is a point of clarification on your reserve replacement ratio, because it, 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. Thank you. You need to listen. The second answer is easy. It's in the slide on 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 get the figure quite late. There was not a perfect position. We could have done it as well. It's oil and gas. It's a reserve replacement rate, global, 121% on one year and 116% on three year. The second answer is easy. The first one, yes, it's true that we report in net investments and that clearly there are some sales on the E&P side embedded in the budget. 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. It seemed to. I think it's $8 billion, more or less. You fully have an assumption around $2 billion of sales, more or less. It's more or less the metrics that I think, if I remember well, what we have. Obviously, the 50,000 barrel per thousand dollar per barrel per day of flowing barrel is a metric where today we don't see an 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 in the last year the delay cost us a little some extra, but we are managing that, having some flexible contracts. At this stage, the $50,000 per barrel flowing barrel, because we are targeting some low-cost barrel, I would say you can still consider it. Thank you very much. Thank you. Next question comes from the line of Paul Cheng from Scotiabank. Please go ahead. Thank you. Good morning or good afternoon, gentlemen. Patrick, you mentioned about Suriname that you may be able to identify the oil development by the end of the year. What exactly we have to do in order for us to reach that stage? How far we are from reaching that kind of decision? The 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. Should 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? Thank you. Suriname is just drilling. We need to appraise. We have several discoveries. We have a plan. I think we have one to three wells to drill in order to confirm. I mean, with the next three wells on the southern block where we have made different discoveries. I think with the three wells, we will confirm to us the capacity to. Again, you know, the point is that we are targeting enough oil pool to avoid having to find a solution for commercialization of the gas, which might be tricky and delay everything. There are three wells for me coming, and we intend to drill them, all of them by 2022. I think that's why I was answering end of 2022, I hope we'll have. I think the plan on, I would say, the south end 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 the three wells, we have a clarity of, what can be done and the size of it and engaging towards the development. That's the point where I am today. If I had to explain to you the whole details, it could take two hours because there are plenty of cases, assumptions, et cetera. We need to drill. Second, we find hydrocarbons each time we drill. Don't worry, but the question is how much oil, how much gas and et cetera. 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 two things, in fact. In the spot volume, you have 10 million tons, let's say, as a round figure, which is 20%. 20% is real 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 a small money on the difference between buying, arbitraging. That's the pure spot. And then in our portfolio of the marketing team, there are some contracts which are linked to spot indicator. I would say either JKM or NBP. And these ones are not all linked. If they are all linked, are more in the long-term part. I'm speaking under the eyes of Stéphane. If I made a mistake, it's okay? It's okay. The answer is right. That's my answer. Patrick, on the second component, you're saying that that is linked to the spot. How big is that volume? Sorry. You mentioned earlier that. How big is the? That the 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, so 34 million tons and you know the proportion of long-term. Long-term is 60% of 34, so it makes 26. 36 minus 26 makes 10 million tons. You have 10-10 more or less than 26. All that is in the slide. You take your finger, you count. Good. Thank you, Paul. That was the last question. I would like now to hand back over to the speakers for final remarks. Thank you. Thank you for your attention. Yes, it's true that results are, I think, more than in line because we beat the consensus by 10%, so stronger with delivery. 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 and refining petrochemicals. I invite you to join us on March 24. I don't know if it will be virtual or in-person. You know, 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 more presentation than today because we intend to present you the sustainability collaborative 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. Thank you for your attention and wish you the best for the next month, and see you on March 24.