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Operator: Good morning. Welcome, and thank you for joining the TotalEnergies 2022 Results and 2023 Objectives Webcast. At this time, I would like to turn the conference over to Mr. Patrick Pouyanne, TotalEnergies Chairman and Chief Executive Officer; and Jean-Pierre Sbraire, TotalEnergies Chief Financial Officer. Please go ahead, sir.

Renaud Lions: Good morning, good afternoon, wherever you are. Welcome to TotalEnergies 2022 results and 2023 objectives. We are presenting from Paris in all virtual mode. Our program today, we will start with a safety moment with Thierry Pflimlin, our President, Marketing & Services. And then Patrick and Jean-Pierre will drive us through the results of last year and the objectives set for 2023. And then we’ll have a Q&A session. But for now, a safety moment with Thierry.

Thierry Pflimlin: Good morning. I’ve chosen a safety moment to speak about the fatal accident, which happened during rebranding work at service station in Burkina Faso last year, but let’s start with a description of the sad accident. On April 27, in our service station in Ouagadougou, 2 operators from a contracted company moved the mobile scaffolding between the totem and the station canopy in proximity of a 15,000 volts overhead power line. The third operator, who was the sole victim, helped them, but his leg hit a security barrier at the same time, and it became a conductor of the current when the electrical arch occurred. This third operator collapsed due to electrocution. He died on the spot, despite the cardiac massages performed.

Kader was 26 years old. The in-depth inquiry made following this dramatic accident showed that the work procedure was — were inspected before the start of the work, including previsit and risk analysis, pointing on the nearby presence of overhead power lines and the need to move the scaffolding in unmounted position. On the day of the accident, the specific work permit had been signed. So what went wrong? The investigation of the accident identified 2 key noncompliances with the work statement: inappropriate decision by the operator to reduce the height of the scaffolding rather than dismantle it in order to go safely under the power line; and failing supervision at the moment of the accident because the person in charge of this supervision was distracted in a phone conversation.

How did we react? We immediately suspended rebranding work worldwide on the site with presence of overhead power lines. A written was issued and explained to define the conditions for restarting the works with 4 main points. First, the obligation to always consider, as a priority, isolation by the electrical network company. Second, the guarantee of minimum lateral safety distances with specific surveillance. Third, the strict control with competent supervisors. And the last one, which most probably is the most important one, no scaffolding under live power lines. However, this fatal accident showed that we must push further the appropriation in the field of our safety rules and programs. And this has to be applied to our teams and to our partner companies.

I’m convinced that we must pursue in this way to improve our safety culture. Thank you for your attention.

Patrick Pouyanne: Thank you, Thierry, for this safety moment. I will come back, obviously, on safety. But before, just to introduce this presentation this morning about our results in 2022 and the objectives for ’23, I just would like to underline that, in fact, this year 2022 has demonstrated once again the consistency of the multi-energy strategy that we are following consistently within TotalEnergies for many years. On oil, we continue to invest in oil in order to maintain our production to capture opportunities like the one in Brazil. We are of course driven by the fundamental objective for many years to keep or breakeven under $25 per barrel. It was $24. And at $100 per barrel, like it was the price last year, we had the full benefit.

On LNG and gas, we embarked in a bold strategy in order to become a very large player. We have, by the way, in 2022, managed 48 million tonnes of LNG, which is more than 10% of the market, which was 400 million tonnes, 12% exactly, with strong positions in Europe. And this strategy is delivering. Of course, this integrated strategy is integrated, of course, results in an exceptionally high gas price environment, which was around $200 per barrel. Integration is about also refining , exceptional refining margins, but the high utilization rate, 82%, and the benefit is there. And last but not least, electricity, which I’ve demonstrated, there is room for price increase in these markets as well in which we are investing for the future. Consistency, resiliency, integrations are the key of our strategy.

And today, in order to continue to demonstrate that we are transparent and with profitability we want to deliver to all our investors, we are announcing that you will have from this beginning of ’23 a clear transparency on 2 segments, which are the pillars of our growth, integrated LNG on one side, integrated power on the other side. I would like to underline also in this introduction the, I would say, superior results that TotalEnergies is delivering. We’ll come back on it, but you will notice that we have the strongest net cash flow per share increase among all the majors and by far. And we have the strongest return on average capital employed of more than 28%, which demonstrates that we can combine profitability — strong profitability and transition to new energies.

I would also say that this year is giving us — we’ll come back on it, but a strong guarantee for the future by the deleveraging of the balance sheet, which allow us to express a very clear framework of return to shareholders in last September, which is a clear framework of return to shareholders through the cycles. We announced 35%, 40%. We delivered 37% of cash payout to shareholders in 2022. Thanks to policy, which is clear and which we — the Board of Directors has decided to even reinforce. First, a support to the ordinary dividend through the cycles, thanks to the buybacks we execute, but also to the underlying cash flow growth. And we have announced that we will increase by more than — by 7.25% the residual — the final dividend quarter and the next quarterly dividends in ’23, but also continuing our buyback program with $2 billion.

As previously quarter, no decrease despite a lower environment. And final, last but not least, room for special dividend, like we’ve done in ’22, if we have super — I would say, super profits like before said. So no zigzag in our strategy, consistency and that’s the key for, I would say, the future results and profitability, and this is what we will demonstrate today together with Jean-Pierre. So if I move over at first on safety after the safety moment. Of course, at TotalEnergies, we repeat this message very often. Safety is a core value and comes first because safety requires discipline, and discipline is at the core of operational excellence. So that’s this continuum that we insist on. I would say that on the one hand, we can be proud of implementing for the company our safety culture, which has led to a significant decrease in the accident rate, as measured and shown here by the — what we call the total recordable injury rate, and we are today managed in the last decade to become among the best in the major, if not the best, but, there is a big but.

However, on the other hand, we report with deep regret that there were 3 fatalities in 2022, which I consider unacceptable, and that see as a — and we see as a sign that we must do more to strengthen our safety culture. But to be sure that this culture is really embedded all over the world in all our operations, wherever they are, whatever they are. We purposely show on this slide the details of the 3 fatalities as well as the steps we are taking on a continuous basis to address and mitigate these ever present risks. We will talk today about our strong 2022 results. It’s a fact, but understand that we carry the knowledge of this facility like the weight on our shoulders. And therefore, we as a company, and I as a leader, cannot be completely satisfied, but we were as successful last year as we should have been.

2022 is definitely a year, as I said, where we have managed to get the most out of our assets in different businesses. Of course, first, this year was a year of LNG, I would say, which become a star in many — around the world because, suddenly, because of invasion of Ukraine by Russia and the impact on the European gas. We — European markets needs more gas. We were in a strong position, the first U.S. exporter, the first Europe regas order. And we have used a lot with regasification capacities in Europe, 86%. And we have increased our LNG sales by 15%, 48 million tonnes. Integrated, the other success, as I said, is a very strong utilization rate of our refining system, more than 80%, 82% in the market, which was really quite high, thanks in particular to distillate.

We managed to capture a very high refining margin and our downstream business as — which showed record cash flow generation. But we have also been able to consolidate these assets through some smart M&A like the one we’ve done in Brazil at the end of ’21, where in a year after, it generated more than $700 million of cash flow. Throughout ’22, success is also to prepare the future in all these operations. Preparing the future is, yes, of course, and you will not see in this presentation the word Russia. Russia is behind us, but we have been able to build the future in LNG through the successes of becoming the largest international player in North Field East and North Field South Qatar projects. We also, I would say, underline the success that we had in exploration — oil exploration.

We’ll come back on it in Namibia and Suriname. So that’s also part of our future and future profits. And last but not least, smart M&A to consolidate on — our integrated power businesses. Why is this smart M&A? Because both are characterized by the fact that it’s direct negotiations to obtain attractive conditions, strong position in the U.S. on the one side with Clearway Energy in Brazil with other site. All these successes is about growing our production, growing our energies. It’s — also, we keep in mind that we have, at the same time, to lower our emissions. And you will see the results knowing that we’ll come back end of March with our sustainability climate report deeply in details of our, I would say, net 0 ambition. So at the end, this is a slide we introduced in September, but which is, for me, the results and give me again the strong comfort for the future is that, yes, we had a record cash generation, but what is important to me is that we compare the ’22 cash generation to 10 years ago, 2012, with even a higher oil price, we have increased our cash generation by more than 50%, thanks to the strong decrease of the breakeven.

And the challenge now is to maintain this breakeven under $25 per barrel by the selection of assets, by the action on cost, despite some inflationary environment, and we’ll manage it. And of course, thanks to these cash flows, we allocate quite a lot, like Jean-Pierre will tell you, to deleverage the company, and that’s the best guarantee for the future. I will then leave the floor to Jean-Pierre to describe in detail these ’22 results.

Jean-Pierre Sbraire: Thank you, Patrick. So I will concentrate my comments on 2022, a year when we established new records, thanks to perfect match between, on one side, our well-positioned assets. And with no surprise, we’ll talk about gas and energy. And on the other side, very favorable markets, which have set new records in 2022. The 2022 environment provided favorable tailwinds for all our activities. Normally, there is a mix of positive and negative. It was not obviously the case in 2022. And so we were able to fully leverage the strength of our global integrated portfolio. Patrick will cover the macro later on, so I will not come back on the rationale. Our oil price sensitivity is sometimes underestimated. But clearly, in 2022, we benefited strongly for the rise in oil prices, thanks to our low breakeven low-cost portfolio, which allow us to capture this price increase.

Please note, as Patrick already mentioned, that in 2022, we had the strongest increase of net cash flow per shares among major. I will show you the data later on. Refining margins are linked to oil, but we saw in 2022 massive supply disruption, particularly affecting middle distillates related to sanction in Russia and, more recently, to the European embargoes on both crude and oil products. For gas and LNG, it is a similar story. The Russia-Ukraine war drove gas and LNG prices to never before seen levels, as Europe scrambled to cut, to decouple from Russian pipe gas by importing additional 50 million tonnes of LNG last year. This represents more than 10% of the market. So clearly, across all our business in 2022, markets were favorable. Here you see the list of key metrics demonstrating that for 2022, we talk the talk, we walk the walk.

A slight miss on production mainly due to security issues in Nigeria and Libya, some delays in projects and the price effect on our . Better-than-expected performance for refining, you see 82% utilization rate in 2022. LNG sales were 4 million-ton targets — 4 million tonnes above targets because of intense LNG spot business in Europe, and we maximized the value of our regas capacities and, of course, renewable as well while, at the same time, meeting our Scope 1 plus 2 emission reductions, despite high utilization of CCGTs in Europe. As announced in July, investment came in above ’22 objective at $16.3 billion. This reflects increased short-cycle activity to benefit from the strong price environment, higher net acquisitions mainly for in Brazil and renewable in the U.S., but no meaningful impact from inflation.

And I think a great bottom line for shareholders, plus $1 billion of underlying cash flow growth, a key element, as you know, supporting dividend growth, and $47 billion of debt-adjusted cash flow in 2022. So let’s move to iGRP results. So iGRP adjusted net operating income was $12 billion in 2022, almost doubling compared to 2021, thanks, again, to fully integrated LNG, which position us to maximize the capture of the high price environment, but also thanks to strong growth in integrated power generation. Cash flow globally at the level of iGRP was $11 billion, up 76% year-on-year. You have here a very important message on that slide to provide a better understanding of the growth strategy of LNG on one side and electricity renewable on the other side.

The Board has decided to split iGRP into 2 new segments from the first quarter ’23. That means that from that date, we will report separately integrated LNG and integrated power. So integrated LNG is comprised of our LNG assets, gas and energy trading, plus biogas and hydrogen. And integrated power is comprised of renewable and flexible power generation, power trading, plus power and gas marketing. We provide you here with some metrics for these 2 segments, ’22 versus ’21. For iLNG, sales were up 15% to 48 million tonnes in 2022, thanks to our #1 position in European regas, which allowed increased spot purchases and sales in the context of record LNG demand in Europe. Cash flow increased to $10 billion, up nearly 80%. And adjusted net operating income was $11 million, doubling the contribution compared to ’21.

iPower generated $1 billion of cash flow and earnings over 2022. Production was 33 terawatt hour, up 57%, thanks to higher utilization rate of CCGTs in Europe and a 53% increase in power generation from renewables. At year-end 2022, we had 17 gigawatts of renewable capacity installed. A lot of you have been asking for the split to better understand our 2 fastest growing activity, LNG and integrated power. We are happy to do it from 2023. In nearly everywhere, 2022 was a record-setting year for TotalEnergies, benefiting from the favorable environment, the increase in LNG sales, plus 15%. And thanks to our unique position in Europe, TotalEnergies generated a very positive adjusted income at $36.2 billion in 2022. Including nearly $15 billion of impairment related to our Russian upstream assets, our reported IFRS net income was $20.5 billion in 2022.

Return on equity was 32%. And ROCE, return on capital employed, 28% in 2022. This demonstrating again the quality of our portfolio and the capacity of TotalEnergies to benefit from price increase. Along with record earnings, TotalEnergies generated $46 billion of cash flow in 2022, an all-time high shown on the left side of the slide, split by segment. All segments made stronger cash flow contribution in 2022; $26 million from E&P, up 39% on higher oil and gas prices and despite the U.K. windfall tax profit, which represents — which has represented in 2022, $1 billion. $10 billion from LNG, a record high that we covered on the previous slides. $10 billion from downstream driven by the contribution from refining of close to $8 billion, more than 2.5x contribution in 2021, thanks to higher refining utilization rates that allow us to capture high margins.

And $1 billion, an important milestone for integrated power. On the right, we show the cash flow allocations, which was pretty evenly divided among shareholders, investments and debt reduction. $17 billion return to shareholders, representing 37.2% payouts, delivering on our 35%, 40% commitments, comprised of $7.3 billion for the ordinary dividends, plus $7 billion of buybacks and $2.7 billion of special dividends that was paid in December. $16.3 billion for investments, but I will cover that in the next slide. And $14.5 billion of net debt reduction, which cuts our gearing by more than half, 7% end of 2022 compared to 15.3% end of 2021. The 2022 environment allowed us for all our segments to demonstrate their strong underlying potential. Typically, with an integrated model, we count on strength in one activity to offset possible market challenges in .

But in 2022, each segment had a chance to shine. Capital investments came in at $16.3 billion in 2022, above the guidance, $14 billion to $15 billion, mainly due to an acceleration of short-cycle projects in West African countries, but also in the North Sea in order to benefit in 2023, 2024 from a good environment; and $5.9 billion of smart acquisition, notably in Brazil, for oil and in the U.S. for integrated power. Also included here are divestment for $1.4 billion mainly from ongoing farm-down activities, which is key to the profitability of integrated power. For example, in that figure, you have the farm down of 50% of 30 — 230 megawatts portfolio of renewable in France, but also partial sales of our CCGT Landivisiau, also in France. In that figure, you have also the sales of some E&P mature assets, notably our interest in Block 14 in Angola, but also the Sarsang field in Iraq.

Important to note that inflation did not have meaningful impact on 2022 increase in CapEx. We remain disciplined on capital with strict criteria for sanctioning projects. I will give you more about that on the next slide. But important to say that we determined last year, particularly in light of the rapid strengthening of our balance sheet, that passing on the opportunities noted here will not serve our shareholders’ best interest. To the right, we split 2022 investments by type of activity. Oil generated most of our cash flow, and we allocated about 60% of CapEx to it, split — with the split between 60%, 40% between maintenance and growth. And a big piece, $2.8 billion, of that growth was for Sepia and Atapu, the deep offshore field in Brazil.

Integrated power and low carbon energy including, of course, the Clearway acquisition was $4 billion, representing 25% globally of the CapEx in 2022. Integrated LNG represented the balance of roughly $2 billion, reflecting the timing of FX , as Qatar NFE and Qatar NFS was not recording in 2022. It will be the case in the first quarter of 2023. When prices increase, cost might follow. However, 2022 cost inflation was not so severe in our key regions and activities, except, of course, energy costs, but we benefited of price increases. There are some upward pressure shown on the right in that slide, but we effectively controlled it in 2022. Using ASC 932 OpEx as a benchmark, TotalEnergies continues to be the low-cost — the lowest cost producer among the major at about $5.5 per barrel equivalent.

On an ongoing basis, we benefit from a high-quality global portfolio that allow us to leverage on purchases power, to negotiate favorable contracts with suppliers and service companies. On deep offshore rates, we signed medium-duration contracts that largely insulates us from inflation in 2022. But nearly, all of our rates are set at about the same level for 2023, with option taking us into ’24 at good prices. For new projects, we adhere to strict selection criteria, shown on the right, to maintain the high quality of the portfolio in terms of average cost, but also in terms of emission per barrel as well. Important to note that our criteria on emission per barrel will be more severe in the future as the portfolio average has lowered to 19 kilograms CO2 per barrel equipment.

In terms of the constant progress of high grading the portfolio, for example, adding low-cost barrels in Brazil last year at Atapu and Sepia, implementing the spinoff of our E&P subsidiaries in Canada with higher cost barrels this year will reduce our overall cost per barrel in the future. To conclude the 2022 result presentation, what you have here are the benchmark of performance of TotalEnergies versus the other 4 super majors. In terms of growing net cash flow per share, you see here the data, we were the strongest by far, doubling in to almost $13 per share. Similarly, TotalEnergies was best-in-class for profitability with 28% return on capital employed. For the 3 years’ return to shareholders, we outperformed our European peers by maintaining the dividend in 2020.

We haven’t cut the dividend in the middle of the COVID crisis and ended up trailing our U.S. peers. And to conclude, based on the Sustainalytics ranking, TotalEnergies has the highest ESG rating among the super majors. We consider that this continues to be an important factor in terms of ESG leadership through this period of growth and transformation. In summary, a historic year for the company, a big step-up in terms of financial strength and flexibility, in large part due to the strategies that position us to fully benefit from the 2022 favorable market environment. And with that, I leave the floor to Patrick. Thank you.

Patrick Pouyanne: Yes. And this slide demonstrates that you can really deliver, at the same time, superior results and sustainability. There is no opposition between both of us. So executive strategy, of course, will be the motto for 2023. And just some words about the environment. Of course, the price today of oil is no more — at $100, but more around $80. But I would say, when we look to the trends of the old markets, for me, there are — there is some uncertainty on the demand, in particular, because there is a feeling — even this feeling maybe is disappearing a little of the risk of what we call recession, global economy slowdown. But again, this feeling today is a little erased because of what we observed in China. And of course, on the energy markets, either oil or gas, the Chinese recovery — economy recovery will be fundamental, easing of lockdown restrictions.

What is clear, by the way, and I know that in our world of oil and gas, there is a new bible, which is a net zero scenario of IEA, which is supposed to decrease the demand every year and to increase the supply is that for 2023, all experts, including IEA, are announcing a higher demand for oil, around 102 million barrel of oil per day, which will be a record year. So the reality of our world is that the oil demand continue to grow, and that we need to face, in fact, we have the supply. On the supply side, we don’t see a lot of, I would say, margin. We see we are entering into this year with very low inventories of products, in particular, very low compared to the last 10 years. We have the impact of the sanctions on Russian crude and refined products.

The crude oil — Russian crude oil is finding its place in the market, China, India. But the refined products of Russia, it’s less obvious where the diesel will go, Africa, South America, that’s a mystery. And by the way, we have also, of course, the supply side is clearly supported by the OPEC discipline, with the cut which happened, and the OPEC countries wants to maintain the oil above $80 per barrel, we’ll take actions. And the other, we could have expected more supply from the U.S. shale, but as it was the case, previous to COVID, but it’s no more the case. Shareholders want some returns and today are more speaking about returns than growth. So that means that when you look to this landscape, I think, from our perspective, there is more support to, I would say, a higher price than $80 and a lower one.

And so looking to — we’d not be surprised to see $100 per barrel coming back. By the way, the oil market, and this is very important to understand, is also for me, today, there is no more a world oil market, in fact, and that’s for a big lesson of what’s happening. We are splitting the market between Europe, which . There are some cap on the prices. So we have today several markets, which does not help, obviously, to ease the price. And I think we did not have seen all the consequences of the growing gray markets and — for these — the supply of this — of oil. On the gas side, this slide is a little complex, but just today, we can have a better vision, better view and maybe even draw some lessons for what could happen in ’23. In Europe, as obviously, the European gas is driving the LNG and power markets for Europe.

So you have on this slide what happened in ’22 compared to ’21. First, production in ’21 and supply-demand was around 380 million tonnes. It grows to 400 million tonnes by end ’22, so plus 20 million tonnes. But at the same time, the European demand for LNG has grown by $50 million. You can see on the graph on the right corner — bottom corner that the demand of gas, and we have all translated in this slide in of LNG. The demand for — in 2021 for gas in Europe was the equivalent of 170 million tonnes. In fact, 100 million tonnes was delivered by pipe gas. It is a famous one, the 130 Bcm from Russia. But we had already importing 67 million tonnes in ’21. For ’22, the Russian gas has been divided by more than 2. We received the equivalent of 44 million tonnes of LNG.

And so we had, to add on it, 1 more LNG, and there is an increase of up to 115 million tonnes of LNG. You can see, by the way, that the bar of ’22 is a little lower than the bar of ’21 because there was a decrease of demand, around 15%, because of the high prices. So to do that, we have done it at the expense of other regions, I would say. And as you can see, there was a sort of supply gaps. So to attract this 50 million tonnes to Europe, we had, in fact, taken out 15 million tonnes, 16 million tonnes exactly, from China. China probably has — because there was a slowdown in the Chinese economy, which went down from 80 million tonnes to 65 million tonnes, more or less, but also from other countries like Bangladesh . So in fact, the supplies of Europe has been possible because we took all the LNG out of other countries, which, by the way, have shifted to coal.

So yes, the security of supply of Europe has been secured, but at the expense somewhere of the emissions of other countries. Of course, we have done that with a very higher price in order to attract this LNG. So what is the perspective for ’23? I might be wrong, but there are some fundamentals. First fundamental is that we expect the Russian gas to be lower in ’23 than ’22 because, in fact, we have been supplied by Russian gas and Nord Stream pipelines up until middle of the year in ’22, and these pipelines are down today. So we expect, I would say, half, maybe up to 20 BCM only mainly by the Ukrainian pipeline. And so if — even if there is a potential again destruction of demand, we expect more LNG being required by Europe than in ’23 than ’22, 15 million, 25 million tonnes are our expectations, depending on demand.

The increase of supply in ’23 compared to ’22 is only 10 million tonnes, 410 million tonnes. So this 15 million tonnes to 25 million tonnes, we see it’s more than what will be supplied worldwide. And we could expect as well, against the same question mark, a recovery by China and an acceleration of the economy in China, recovering part of all of the 15 million tonnes that we acquired last week. We derived — we extracted from China. So the supply gap is there again. And so it’s why we think there will be some tension. Of course, on the gas, there is one element which is different, which is a small note on the bottom right corner, which is the storage level. So storage level were 54% last year by end of January. Today, they are 85% in Europe.

We cannot store more because there is a limited capacity of storage in Europe. This Is why today the prices are lower. But again, we will consume this gas. And so we think that some tensions will appear by middle of the year between the different markets for LNG. So ’23, our activity in front of this environment, we’ll continue to deploy our strategy. We have already announced, of course, on the LNG side, we are adding some regas capacity in Europe. The one in Germany has been opened. It’s operational. We have put FSRU in Lubmin, which is the point where the Nord Stream is landing, which is a perfect access to the German market. So our LNG traders are quite happy with this infrastructure. We have booked half of the infrastructure for our own business.

We are adding another one in France where we intend also to book half of it. So that’s LNG. And there we continue, of course, to chase opportunities in LNG. As you know, we have ambition in the U.S., and we’ll come back to you later. The second part of deploying our strategy, and it’s important, Refining & Chemicals, where we have Bernard and its team have worked hard during years to consolidate this Jubail platform, the SATORP platforms. Our strategy is expanding fundamentally in an integrated way. We have been happy to make — to take the FID of the Amiral project, which is $11 billion world-class petrochemical integrated complex, which will come on stream in 2027. It will consolidate the profitability of our integrated downstream business.

And last but not least, integrated power, which is the other pillar of the growth, will benefit in ’23 from the acquisition of 70% remaining shares of Total Eren. We have exercised our options. It was, as you know, a transaction where the negotiation took place in 2016, at a time where the multiples were — on renewable assets were reasonable. So that’s already there. So it gives some work to our teams, but there is more to come. Of course, we’ll not just sleep during the year, but we’ll continue to find smart developments in all our projects. We’re lowering, of course, our emissions. It’s always — our motto is more energy, less emissions. So growing our energies for sure, and our delivery for energy, lowering our emissions. In particular, we have announced in September that we have launched a worldwide energy saving plan in the company.

The teams have been super reactive. So the $1 billion has been distributed at an average, by the way, cost of $50 per ton. It will — it begins to be spent in ’23 for $400 million spread over the 2 years. And it will allow us, by the way, to lower our targets on Scope 1 and 2 emissions by 2 million tonnes for 2025. We’ll come back on that in March. Second point of ’23, and I think it’s important for all the investors, is our cash allocation priorities. There is a scheme now that has been put in place. I remind you that we want to deliver 35%, 40% of cash payout for the cycles, 37.2% in ’22. So we have taken some first decisions with the Board of Directors on this first dividend that we begin to call ordinary dividend to differentiate it from the special dividend.

We want it to be sustainable. And this, of course, the increase of 7.25%. We have announced yesterday for the ’22 final dividend and the ’23 interim dividends is at EUR 74 per share, is supported by both the share buybacks, which we have done last year, which we are representing almost 5% of capital. So of course, this 5% is a return to shareholders only if we translate that in an increase of dividend, which we’ll do. And we do more, we go up because there is also an increase of the underlying cash flow growth. So this is the reason why we’ve done this increase, which is a larger one than the one we have decided for the full year 2022, 6.5%. I would like to remind to all of you that the difference of some of the peers, we didn’t cut the dividend in 2020.

And so we have — maybe, we have less room to increase this year, but we increased the dividend year after year, ’22, 6.5%. So basis was more than 7% in ’23. And so that’s our commitment. So CapEx, I will come back on it. We gave you a range of 14%, 18% in September. It will be 16%, 18% in high part, of course, $5 billion in low-carbon energies. So balance sheet, difficult to express a target for the gearing. It’s down to 7%. So it will be strange to you to say minus, I don’t know what. So we express our ambition in another way, which is to continue to strengthen the balance sheet because it’s a guarantee for the future. Today, we are A+. I think we want to target better AA credit rating. It’s an ambition for — it’s the objective of my CFO.

So he told me it’s aspirational. I told him, “No, it’s a real objective for you and your team.” So — and I think it’s true — it’s because, again, for me, that is the best answer to ensure you that all our strategy in CapEx and return to shareholders will be delivered through the cycles. And the surplus cash flows are, of course, allocated part of it first to buybacks. And last year, we were at an average of a little bit less than $2 billion. It was $1.75 billion. We increased it to $2 billion than in the last quarter for this 2023 in an environment of $80, which is lower than the one of last year at $100 per barrel. So I think it’s a commitment to this buyback. And the special dividend, it’s only in case of super profits. We will come back on it, even if — as I will explain you, there will be — the shareholders of TotalEnergies will be rewarded with a special dividend in kind, as we will organize the spin-off of our Canada upstream assets.

I will come back on it. So I think this is a full program, which demonstrates the real way we think to the future. When you look to, in fact, the column 1 and 4 are for the shareholders. Column 2 and 3 are for the company. And we think to that. Of course, we have to — we’ll come back to the other stakeholders. So the capital investment of ’23 will support the transition, $16 billion, $18 billion, at which — out of which, $5 billion for low-carbon energies, let’s say, quarter 4 for integrated power and more than before on the new molecules because we grow our ambition in the various segments. In particular, in carbon capture storage, we have been awarded new projects in Denmark. So we have Norway, Denmark, Netherlands. So we build, I would say, our position in this business.

Also included in this part is energy savings, let me say, the negative emissions that we can do. And you can see that we have also new projects, of course, coming into our hydrocarbon businesses, oil and gas. In gas, it’s growing because it’s a Qatari project. There is no Russian LNG, no — and more in our spending, but which was — of course, it was less investments in ’22. But the Qatar projects are there. We’ll have the Cameron project. We have the PNG projects. PNG is targeting FID by the end of the year. Cameron is targeting FID by September. So there is a lot of work on LNG but, of course, on oil as well because we have some new projects on which we work. Like in particular, in Brazil, we have — Mero 2 will come on stream. We will have Atapu 2 and Sepia 2 to sanction this year.

We have also Uganda. So we have new projects coming. You can see that, by the way, we have as much new projects on both sides, a little less nitro carbons and low-carbon energies. And we have the rest of the CapEx is maintenance, and we need to invest, more or less, $7 billion to $8 billion each year to maintain, I would say, the whole system. So the ’23 production will grow more energy, will grow mainly coming from LNG. Again, there is no new project coming onstream as last year we had some, I would say, not a full utilization of Snøhvit, which came back on stream by middle of the year. And from — it is because there were some big overhaul in Ichthys, so 9% more of production of LNG and pipe gas to Europe. Oil will benefit from the full year of Brazil, plus 5%, so it’s good in this environment.

So production will grow only by 2% because, at the same time, we have some perimeter effect on domestic gas. We have exited from Myanmar. We have exited from Termokarstovoye. We have — and we will exit from Thailand. Honestly, these are domestic gas. They don’t have — there is no — why did we differentiate them from the rest of the gas is that there is no upside on this type of gas or limited upside linked to the gas price — international gas price or international oil price. So it’s — in terms of economic impacts, we don’t have the volume, but the upside is more limited. So at the end, so what is more important for me, what we do in LNG and pipe gas to Europe because there, you see the upside of this market, plus the oil. Startups in Oman, Block 10 has started; Mero 2, Brazil, middle of the year; and Absheron in Azerbaijan for gas.

Just to mention that we are quite — in our company, we don’t speak about decrease of oil or decrease of gas. We speak about stabilizing, growing, continuing to supply the market, being a key player of energy supply and taking our role, even if we are not a very large player, but we do our role, which means that we continue to focus as well on reserve replacement. You can see by the ’22 reserve replacement ratio in the year are quite good. 108% at the same price, 85% with the price effect, around 100%. There are not so many major companies, which have been able in these last years to maintain their replacement rate at 100%, and we are one of them. Without Russia, which was, of course, for us a source of reserves, but we can do it — without it as it has been done in 2022.

So let’s continue. Integrated LNG portfolio, the ambition, as I just mentioned, more production. So it helps — it will help our colleagues of the downstream LNG to sell more. Of course, there is a spot uncertainty. But our position, as I said before, is strong in regas in Europe. We are increasing our regas capacity in Europe, thanks to the Lubmin and the le Havre FSRUs. So we have more than 20 million tonnes of LNG regas capacity, which is good, which is strong. It will help us to continue to monetize these capacities. As we can see the split on this slide, which is important, we split it into, I would say, 3 pockets according to the margins. There is a pocket of, I would say, long-term Asia, Latin America portfolio, which is fundamentally giving us results and cash.

It’s a difference between Brent and the cost of production. That’s the idea. Then we have the European and flexible markets where we, in fact, we supply the le Havre gas LNG from the U.S. to the spot index. So where the profit will be, I would say, spot minus in le Havre. So today, it’s $20 more or less per million BTU, minus 3 or little less than 3. So you can see the margin. And then you have the spot ones where, in fact, gives some sense of margins, but this activity help us, of course, to, by the way, absorb the cost of the regas and to contribute to security of supply. We have put at the top Yamal because there is always — today, Yamal, by the way, to be clear, we have only — we have stopped — we have all the volume, the 4 million tonnes of volume of the long-term contract on which we are committed, but we are strictly only these volumes, as all the activity which was linked to spot extra volumes, we don’t take them anymore as per our commitment vis-a-vis the Russia business.

Integrated power, we will continue to grow clear because we — of course, the gigawatt of capacity, as it was said by Jean-Pierre, we have managed more than the 16 gigawatt per — by end of ’22 capacity — growth capacity. We are at 16%, 17% — 16.8%, 17%. By the way, I would like to tell you that there are not so many companies able to grow their renewable business by 7 gigawatt in a year. You can look around. We are among the top. And so, again, when we do things in Total, we are consistent. We do that seriously, and we intend to deliver not only growth, but value because this is why. And this is the fundamental reason why we have decided to anticipate the split of iGRP into 2 reporting segments. By the way, there is no split of organization.

Stephane is leading the whole businesses. Just to be clear, it’s a reporting. We have done it because I think now it’s time not only — it’s not only to speak about volume, but value. And the best way to deliver the value is to report the results and to show it as we will improve it. Of course, we have quite a lot of capital unemployed today, but it will come on stream year after year. So we target an increase of production by around 30% mainly from renewables. We benefit today from a very high rate of user utilization rate of the gas-fired power plant in Europe, but there are also some capture of special taxes in Europe on this gas-fired power plant. Having said that, we expect an increase of our integrated power cash flow from $1 billion to, let’s say, plus 30%, 40%, we’ll see.

But these capacities will move, and we have — we will have to deliver this growth. The year 2023, coming back on oil, and I think it’s important to tell you that we have decided to mobilize most — at least, most 50% of our exploration budget on Namibia. We are maybe today in TotalEnergies, and I hope it’s true, and I don’t have words, but only plastic here, but it’s really — maybe at the helm of — it’s clearly according to, by the way, for Wood Mackenzie, it’s the largest discovery, which has been done in 2022. We are maybe at the helm of a new golden block. So we decided to mobilize 2 rigs and $300 million in TotalEnergies share to, I would say, , return the cards. We have 1, 2, 3 rigs — wells, plus tests and to have dynamic test to really know what we have in our hand.

And with the idea that we — to accelerate the time to market, not to appraise everything and to be — I would say, to know everything. But if we have the chance to really confirm the volumes, which seems to have been discovered, there will be room to make fast track developments like we’ve done on Block 17 25 years ago. And so this is from my perspective, very important, because this could be a new chapter of the oil business in the company. So we mobilize the teams and all E&P teams, and there’s supervision of Nicolas. And also the One Tech teams are on these important projects. At the same time, we will divest some oil, the expensive oil. We know we have clearly set 2 years ago. We made some impairments, but we — not only Canadian assets are not in line with our climate strategy.

But fundamentally, there are high OpEx assets, and we are not fitting with our old strategy and our old portfolio. So we look to various options, and we confirm today that we consider that the best way is to maximize value for shareholders is to introduce this independent Canadian company in the market. The idea is to do it — the objective — the project is to list it on the Toronto Stock Exchange by — in the second half of the year. By the way, you can see the metrics of this independent company of 2022. It was a company which produced 110,000 barrels per day, which delivered more than $1.5 billion of cash flow and — from operations and almost $1.3 billion of free cash flow. So it’s quite interesting metrics. We have appointed a leadership team from a Canadian lady, which was the work — you see working in the company will become CEO of this company and Chairmanship as well by an executive of the company, who knows very well Canada.

The idea after that is that in order to manage, I would say, the backflow in this type of listing operation, we will maintain more or less 30%, not more. It will be for some years in order to stabilize the company. But fundamentally, the idea is it will not be a company controlled by TotalEnergies, not at all. We think we’ll have to take maybe one Director out of it. But it has to be — it will be managed as an independent company. By the way, this is the reason why we just preempted for this company, not for TotalEnergies, I would say, for SpinCo, 6% of Fort Hills. There was a transaction between Suncor and Teck, and we considered that if we were in charge of this independent company, obviously, because these were attractive conditions, we would have to preempt.

So we’ve done it in order to strengthen the company before its listing. So for shareholders of TotalEnergies, they will have to approve this spin-off at the AGM of 2023 in May, and they would receive a distribution in kind, so a special dividend in kind of this new SpinCo company. We will report to you, of course, along the coming months on the progress of this project. Coming back to the 2023 objective, which is important, is the cash flow generation. I’m happy to tell you, with the support of the growth in integrated LNG, in integrated power, but also on the oil production, the underlying cash flow growth will grow by another $1 billion. We have announced 1 billion per year. It is the case. This $1 billion is feeding the growth of the dividend.

You can see that we gave you there on this chart, I would say, an indication of what could be the cash flow from operation expected at $80, $100 per barrel. We are navigating in both. And you can compare to ’22 at $100 per barrel. In the same condition, we expect $1 billion more. If $80 per barrel, you have the sensitivity on the right. It’s $3 billion extra cash for $10 per Brent. It’s a little lower than last year at 3.2% because of the impact of the U.K. taxation. And also because we have consolidated, I would say, Novatek, which part in Yamal so — and because Yamal is linked to Brent, more or less. So — or we keep our shares in Yamal, but we have deconsolidated our accounts all the share of Novatek in Yamal. So that’s why the sensitivity is a little lower.

The $0.4 billion for $2 per million BTU is also lower than last year because of the U.K. taxation fundamentally. And for the margin sensitivity on the refining margin, I would say, it didn’t change. Just to remind you that — and I would like to insist is that there is, obviously, for the TotalEnergies sales quite a good potential for stock rating. Free cash flow yield in ’22 was at 19.4%, and we have enterprise value per DACF ratio of only less than 4 — multiple less than 4. So this, we are expecting. We hope that these strong results will be translated in the value of the company. Finally, I would like to tell you that, of course, the company, I’ve shown you before that we are allocating our cash flow to the company by cap investments and debt reduction in a large way, but also to the shareholders by way of the ordinary dividend, special dividends, buybacks.

We are also thinking to our stakeholder. There is one stakeholder missing on this slide, which are the states. The states are benefiting a lot of the oil and gas profits, and people are complaining from time to time. But for TotalEnergies, we have doubled — more than doubled the taxes and — but we will — we’ll have paid to states around the world $16 billion in 2022, $33 billion in 2023. Of course, they are mainly paid to producing countries. But the countries like the U.K., it’s $3.7 billion, $7 billion, and not to the consuming countries, that’s clear. But this is a strong contribution, I think, to, I would say, the public good for the taxes we deliver. We are also thinking to our customers and to our employees. Our employees are, of course, very — are the engine of all these results.

We should never forget that it’s not only the strategy, what is — our 100,000 worldwide employees, which are delivering the strategy. We are rewarded them via a special 1-month salary bonus. We are taking into account the inflation in each country to increase the salary. So we share the value of those salaries, which are also, by the way, shareholders and which 7% of the capital is the property of our employees. So they are also receiving their part of the dividend. For the customers, we have been probably followed a different route than some of the peers. We have decided to make proactively some sharing profit with our customers in order to, I would say, take part of the pain of these high prices — high energy prices. The 2022 was, in many of our countries, a debate of energy, which was dominated by security of supply, but of course, affordability.

So we have put in place some few rebates program, a massive one, more than EUR 500 million for benefit of customers in France. We’ll have to — in ’23, we have to face some also other energy crisis, like the SMEs customers — or SME customers suffering of very high electricity prices, which were contracts because of the increase of electricity price to the sky in Europe second half of 2022. So we take actions, and we continue to take actions because we consider that it’s part of our social responsibility to take care of all our stakeholders, of course the shareholders, the company, the employees, the states and also our customers. So I will stop there, and thank you for the attention. We’ll be happy to answer to your question.

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Operator: . The first question is from Oswald Clint of Bernstein.

Oswald Clint: Could I ask, please, Patrick, just on the dividend again? I mean, 7.25% increase, you said you couldn’t do more. That’s understandable. It’s helped by the buyback. We understand that, too. But in the context of the last — the long term where you’ve done, let’s say, 5% or 6% growth for the last 1, 2, 3 decades is if we can sustain the dividend and the commodity view cooperates, as you seem to indicate, could 6% to 7% or 7% to 8% become a new trend line at least for that ordinary dividend is the first question? And then thinking about future profits in Namibia, interesting slide you have. So do you think we could get some proper resource numbers in 2023? And when you talk about fast tracking, if successful, what does that mean in terms of time?

And a linked question. Obviously, Shell’s Jonker well has come in, which might give you confidence on an Easterly extension of , but does also pose some unitization risks further down the line that actually could delay things.

Patrick Pouyanne: Okay. On the dividend, we didn’t tell you we couldn’t do more. We have decided to do it at 7.5%, which is, yes, you are right, a change of the past trends. But I think, again, for me, it’s also the translation of the fact that we have increased the buyback. So as we have bought back almost 5%, it gives some comfort. I think when people speak about return to shareholders through buybacks, if we don’t translate it in a higher increase of dividend, I don’t understand why it’s a return to shareholder. It’s a saving for the company of dividend, for sure. So that’s logic. I think I’ve been very logic with what we declared, and the Board is logic. We’ll — we have — and as long as we can allocate some cash to these buybacks, because we have more cash flows, and we are — again, we continue — we did not decrease the buyback rate.

We maintained it, despite a lower environment. And I’ve seen some of our peers have decreased the buyback program for the first quarter. We don’t do that. We maintain it, and that’s proven. So the answer is — to you, maintaining this buyback program, yes, will help us to support a new normal, which might be 7% to 8% and will — in the future, so that’s in the future years. But again, there are 2 engine to fit the increase of the dividend. On one side, these buybacks. On the other side, it is the underlying cash flow growth. And I am announcing and again that we target $1 billion. By the way, I understand that the Board, among the new criteria for the variable pay of the CEO, has to decide to introduce the underlying cash flow growth. So it’s — we walk the talk in the company.

And so that’s what I can answer to you. And again, don’t forget, and then like you can compare it to companies who have increased by 10%, but these companies are divided by 2 or more in 2020, which we will give more room to maneuver to increase. We didn’t decrease at all. So we are also starting from a much higher point from this perspective. You spoke about Namibia, and let’s keep — Namibia, we have a program. I just tell you, we have 1 well, 1 well. People are super excited. They speak to me about billions of barrels, but we don’t have the data. We have no dynamic data. We all know that as long as we don’t have a test and dynamic test, maybe there is no good permeability. It could be complex. So let’s — I’m — we are excited. It’s clear, as we mobilize and we have decided to mobilize a lot of our exploration resource this year to Namibia, because we want to know what we have.

And if it’s true that we have this type of size of resources, obviously, there will be a lot of room to develop. Honestly, unitization, we will not need it. We speak about billions. We can make a first project on our side. We are making complex stories. Having said that, I can tell you on this project specifically there is a very good cooperation between to Shell and TotalEnergies teams. We had to share the data as we have an agreement. So we will discuss together. But the idea, it’s really big, is not to be a super optimization to appraise all the discoveries — or there is a number idea. Like we’ve done in Angola, let’s see if there is a first development. Then we’ll have time to optimize. I’ll also remind you that there is the same partner on both sides of the license, which is QatarEnergy.

We are happy to do it. So let’s see. It’s premature to speak of the size. What I hope is that when we have drilled all this program, which has been organized in order to have 3 wells and free test, in fact, with 2 rigs, then we’ll have a better clarity. And we can speak to you about resources. Today, it’s premature. Let’s do the job, and we’ll come back to you. But I can tell you that as a CEO of the company, we are quite excited like we were when I entered the company. I was lucky. I was assigned in Angola on the Block 17. So I hope we’ll have the same in our hand for the next 25 years.

Operator: The next question is from Christyan Malek of JPMorgan.

Christyan Malek: It’s Christyan Malek from JPMorgan. Two questions, Patrick. First, I know that we’ve shared a fairly similar view on a sort of super cycle prospects in oil over the coming years and your position for that in the context of your portfolio. So can you walk us through where you see your growth prospects on a 3- to 5-year view? I mean, coming back when you had the best-in-class growth rate for oil, up at sort of 5% to 6%, do you envisage a situation where you could lean into that growth and sanction projects? I know you’re moving to short cycle as one of the basis of your increasing CapEx. But if you can provide us with what would be the upside risk on your volume growth if you were to choose to sanction more projects and take a longer-term view around investing in FIDs, a term that I think has become quite rare in this industry.

And the second question linked to that and linked to your Canada IPO, do you think this is a template going forward if the market is not going to recognize the value associated with oil, whether it’s because of ESG, because of net zero? Could this be a rollout of other projects or other regions going forward where, ultimately, your IPO, your oil business, in a way that it generates better value for shareholders?

Patrick Pouyanne: I can tell you just so we — if we can sanction projects, we’ll do it. And we have in ’23, 3 big projects to sanction in the company, oil projects. We have the Block 20, 21 in Angola; Cameia, Golfinho. We have the offers, and we are working on it very hard in order to manage the cost of the projects. That’s a key issue, but we’ll do it. We have in Brazil, because of the acquisition we’ve done, we have 2 projects to sanction. One is Atapu 2. The other one is Sepia 2. So this will feed the growth, and we are looking to opportunities to grow our portfolio with always the same motto. It has to be resilient through the cycle of less than $20 per barrel or $30 of cost — technical cost of $30 breakeven and less than 19 kilograms per barrel of emissions.

Now as we lowered it because it’s the average of the portfolio. So again, we’re consistent. And there are opportunities, and I hope we’ll be able to announce you smart opportunities in the coming weeks, in the next weeks. So — and again, by the way, we have also in our portfolio Suriname and Namibia. I just described Namibia. Suriname, as you know, is a little more complex, but there was a good news by the end of the year because the Sapakara South appraisal is positive. So we have at least a first pool — oil pool of potential projects. Half of it is confirmed. We are drilling wells on Krabdagu and ran discoveries, 2 wells. I think we have accelerated as well. And I hope that by middle of the year, we’ll be able to confirm that we have the oil pool that we are looking for in Suriname.

So there is also the short-cycle projects. I think this is what has been done in 2022, to accelerate the mobilization of rigs. Angola, in particular, is delivering a lot, Nigeria, Congo. So these are the — because there, we have already some infrastructures, FPSO, so we can build adding wells on the infrastructure. So that’s the way we look at it. So the answer is a super cycle. But what we will not do is investing in expensive oil just because, today, in the short term, the price is good, okay? So this is the second question on Canada. It’s why we think, by the way, that it’s the right time. I don’t know if the market will fully recognize the value, but I’m sure that’s it’s probably the best time to recognize it, so — with the figures that we just announced.

And so, no, we have been — people knows that we want to divest these assets. They are not fitting with the strategy. We make money this year, but this could disappear. So we have the ambition to get a good value out of it. The various acquisition offer we received were not in line with expectations. And so I will say, but we are optimistic about the capacity of the market, which is, for us, the best way to monetize these assets. And is it a model to roll out other E&P assets? No. It’s a specific model because, again, these assets are high costs. They are not fitting our strategy. And we are not the best shareholder. But the reality, there is a potential to grow in these assets. Surmont is a very high-quality assets. Fort Hills suffered, but could deliver more.

But we are not the best ones because we don’t want to put CapEx. Why should we keep in our portfolio assets on which we are not the best shareholder? But the other assets, which we have in our portfolio, we are very happy shareholders. So in particular, I’m quite happy to have directly access to the cash of all the North Sea assets in TotalEnergies today.

Operator: The next question is from Irene Himona of Societe Generale.

Irene Himona: My first question is on the balance sheet. You obviously enjoy an exceptional balance sheet already with only 7% gearing. And you seem to want to strengthen it further with reference to reaching AA credit rating. I wonder what is the real significance of a AA credit rating, please? And then my second question on LNG sales, up very strongly last year, 22% in Q4. You’re still selling Yamal cargos, obviously. Can you let us know, please, how are you getting paid exactly in the middle of these sanctions?

Patrick Pouyanne: Okay. Balance sheet, why is this important? I think just — I’m trying to fill the gaps with the valuation of some of our peers. So we are quite systematic. We look to the difference. There is one gap which is that our U.S. peers are rated AA. We are not yet rated AA. And when I look, and when I compare the metrics and the results of TotalEnergies with at least one of both, I see very similar metrics. So maybe, there is something missing. So I think — again, I think it’s also a message because for me, that means that AA would mean that you — our shareholders and new investors could really believe in the future and the guarantee of the future return to shareholders. So I think it’s a strong signal. Again, it’s a way with the Board we discussed, can we express again a new objective of gearing.

It seems to be difficult, why minus 5%, why minus 10%. Keeping the minus 15% would be odd to you today. So we think that there is room to go to another step and, again, giving some challenge to Jean-Pierre. But no, I think it’s — again, I think it’s — it would be a translation of a very strong strength of the company. So let’s work. We’ll see if we can convince. LNG, Yamal. First, Yamal, which is the only asset remaining, is a source of 2 cash flows. There is the direct interest in Yamal as an asset, 20%, and this company sell is LNG to different buyers, one of them being TotalEnergies on Brent basis. It is true that we have received some dividends from Yamal in 2022, but some — it’s a little — it’s becoming more complex. We have, by the way, decided to book the cash flow from Yamal only when we receive really the dividend.

By the way, this is one of the explanation, because I’ve seen a question mark coming why there is a gap on the iGRP cash flow. There is no — on LNG cash flow. It’s because we don’t book the full result. We have decided to be prudent. We book in our accounts cash flow from Yamal when we see the dividend in Paris or somewhere in our pockets. We are prudent. But — because, again, there is a strengthening of sanctions. So that’s the first part of the Yamal cash. But there is another part, which is this long-term LNG contract, which the teams of Stephane and , they acquire this LNG on a Brent basis, and they sell it at the TTF price when it comes to Europe or the JKM if you go to . So that’s also quite a large source of cash. And by the way, it’s even better — maybe better — or this is — we don’t hedge anymore of this contract because — why?

We do the decision because we are not sure that sanctions on one side of the other side, by the way, could not derail this volume. So that means that, in fact, most of LNG volumes are age 1 year in advance. But Yamal, and Yamal will really — these volumes — these 4 million tonnes will reflect in our accounts the reality of the TTF spot market or the JKM spot market, compared to the Brent in the year ’23. So in fact, Stephane, most of his business is already done. He has hedged a lot and he can optimize around the hedging, but he has this amount of these contracts, which could deliver. And this is not Russian money. This is a European contract. So this long-term contract and the cash we derive from this Yamal is today, in Europe, there is no constraint and is reported in our account, like the other long-term contract that we managed in our portfolio.

I hope it’s clear where we are today.

Operator: The next question is from Christopher Kuplent of Bank of America.

Christopher Kuplent: Two quick ones, please, if I may. Patrick, Jean-Pierre, if you’re looking at your CapEx outlook, can you maybe give us a little more granularity in terms of your assumptions embedded in that $16 billion to $18 billion number for 2023, particularly looking for your assumptions regarding underlying inflation? Jean-Pierre, you said there wasn’t really any to report in 2022. Just wondering what you’re assuming for ’23. And if you can, maybe give us a hint, as you usually do, about how much of that you think will be inorganic. And then lastly, on your point, Patrick, regarding the iPower, the new disclosure. Maybe you could give us, if you had, a view on, as you rightly said, a lot of unemployed capital that we will see growing in the next few years.

So maybe you could tell us where you see capital employed going for that integrated power business because you’ve got access to that pipeline you’ve worked hard to achieve. I think that would be probably a more important figure than your earnings progression into 2023 here.

Patrick Pouyanne: Okay. CapEx inflation embedded for inflation, you see on the short term, it’s quite low. I think maybe it’s a 2% to 5%, which has been mentioned by — but on the short term, there is no real impact on CapEx. The CapEx — the inflation for us, the — a deck each for Nicolas and Namita are more about the new projects because, of course, the contractors want to embed higher costs in the new projects, and we don’t want. So this is fundamentally the debate for the execution of the projects, which are — and most of the CapEx of the year are more of the old projects, which are already sanctioned than the new ones. The new ones generally are impacting quite — will impact the next years. And so there is no real inflation, I would say.

And the rig could be one of them. But as Jean-Pierre explained for 2023, we are covered by good — I mean, good rates. So for me, there is a debate about inflation. With contractors, it is more for these new projects we want to sanction that I mentioned to you. That’s a point on which we need to be all serious. Otherwise, we’ll wait because we’ll not repeat the mistake we’ve done in 2010, 2014, which is to sanction whatever the cost is. I will not do that. So M&A, I think there is a net assumptions of inorganic, which is around $1 billion to $2 billion. That’s okay. It’s a matter of buying and selling. And we have some different options in the portfolio to buy and sell in — and so we’ll keep you aware, but this is, I would say — and it’s part why we keep the range because, of course, when we don’t — the range is, for me, sometimes you have divestments which are done, but you — for example, Dunga, we’re during 1 year, but we will receive the proceeds only in ’23, not in ’22.

So we might have some time of execution, which in this type of divestments. So that’s the idea. So most of the CapEx we gave you are organic, in fact, to be clear, most of it. On iPower, it’s a new reporting, so we will have a full reporting by — you have to be a little patient because Jean-Pierre and his teams are working. And so from first quarter 2023, in April or end of March — in April, sorry, end of April, we’ll deliver to you not only the quarterly results, but the previous years. We will restate the 3 previous years. So you will have some indication. It’s a business where most of the CMO — we have some capital employed, of course, and productive because — but the cycle is quicker than in oil and gas because, normally, to build an onshore solar plant or an onshore wind farm, it’s more 2 years than 5 — 4 years, I would say.

So normally, the cycle is quicker. Having said that, we also have offshore wind, and offshore wind is more like an exploration cycle than an E&P cycle on a short cycle — I mean, an onshore renewable cycle. We have also in our — as we make some acquisition, we have also some unamortized, I would say, value. I don’t have the precise figures, and I don’t want to introduce something wrong, but you have the idea that it seems the capital employed of this iPower is around, today, $15 billion. We’ll confirm that to you. This is what I have seen in some first figures. And I think you have maybe probably 1/3 of it, which might be unproductive. Just run figures, okay? We will — but I think the exercise to oblige ourselves to make this new reporting is very important.

I know that there are question marks about the profitability of this business, and we have to deliver to you. And when you report, you focus on it, and you will improve. That’s what I learned from refining and chemicals. And I said to Stephane, you go to Bernard, you ask him, “Have we improved the Refining & Chemicals profitability from 5% to 20% today or 15%?” So I think focusing is important, and this is the answer. And we intend clearly to be consistent with this strategy. And integrated power, all the words are important. It’s not only renewables. Again, it’s really the capacity to deliver value from a volatile market and from price which will go upwards because we need more and more electricity. So that’s my answer.

Operator: The next question is from Lydia Rainforth of Barclays.

Lydia Rainforth: Two questions, if I could. Patrick, thank you for the very comprehensive update around what you’re seeing on the commodity markets at the moment. Given everything you said in the kind of cash payout ratio, do you expect that you’ll be in a position or Total will be in a position to pay a special dividend this year later on in the year? And then secondly, if I could come back to Adani, clearly, it’s relatively small amounts of capital employed there, but does it change anything in terms of how you think about your approach to renewables in certain countries or JVs within that and the growth prospect?

Patrick Pouyanne: Well first, there will be a special dividend, which is a special dividend in kind with the spin-off of Canada. So — and it’s not 0. It’s — when I see the figures, it might represent not far from $1 per share. So don’t underestimate that value. So it will come for shareholders. Again, the special dividends, we are very clear. We told you the priority to buy back. And then if we have, again, an environment like we had last year, we might consider that. But it’s — that’s my answer to you. It’s premature — or by the way, it’s premature because today, what they observed since the beginning of the year is $80 per barrel. So I don’t see — and less than $20 per MBTU. So there is no reason at this type of environment we will not have a special dividend.

We prefer the buybacks. This is why we maintained the $2 billion. We don’t increase it. If we come back to an environment like last year, we might consider that. But again, there will be a special dividend for the — in kind for the Canada spinoff. Adani, no, it does not change. I think — again, first, on Adani, I see a lot of papers, and I thank some of you for having trying to calm down these markets. We have an exposure, which is quite limited at $3 billion — $3.1 billion. Obviously, the hydrogen projects, which was discussed, will be put on hold as long as we don’t have a clarity on all that fight. I’m confident in the fact that Adani and geothermal energy is taking care of this business in a smart way. But as TotalEnergies, of course, we have to form a prudence to understand.

We are there. By the way, all the companies of Adani in which we invest, we looked yesterday to Adani Green, for example, is a very safe company. They generate $1 billion per year of revenues. We have a debt of $5 billion. So it could — it’s sustainable, sustainable border. Maybe this will — could impair the growth, I’m not sure. But again, at the end, the equation is more a strategic one. Do we need to do it by our own or not? Honestly, doing by our own, renewable business in India or even in Brazil, I think it’s too complex. So I think I preferred — and again, I think finding the right partners is the right way. We have been pleased, by the way, that Adani has delivered. Again, Adani Green Energy Limited or Adani-Total Gas Limited are companies which are managed by independent CEO, smart PEOs. We are happy with them, and we are happy also with the partnership with Adani.

And of course, then it’s Adani to explain what is the way they finance all that. But again, for me, fundamentally, no, it does not change the approach we have. It’s true that — and again, we knew that electricity is not really again renewable. Electricity business is more local, so you take more local risk. But maybe it’s also local opportunities. So I don’t want to be too — don’t look to the glass half empty. Half full is better. So again, we’ll work on this one.

Operator: The next question is from Michele Vigna of Goldman Sachs.

Michele Vigna: I had two questions, if I may. The first one is on your low carbon strategy, and I was wondering how much the IRA has changed your capital allocation. It feels like the renewable molecules businesses, like bioenergy carbon capture, hydrogen, are becoming increasingly attractive, while renewable electrons are perhaps lagging a little bit behind, especially in a higher interest rate environment. And I wonder if that is reflected in your green CapEx allocation as well into the coming years. And then second question, I wanted to come back for a moment on the comments you made about your exposure to spot LNG. It’s very clear, your exposure to spot gas in Europe, TTF and NBP, $200 million for $1 per Mcf. I was wondering if you could give us a sensitivity to spot LNG as well, also including what you’ve actually hedged over the next 12 months.

Patrick Pouyanne: Okay, the IRA is good for everybody, not only for molecules, but also for renewables. So don’t — maybe you don’t follow that carefully, but there is some advantage linked to the IRA, but we benefit for more. In particular, there was a production tax credit, which was mainly in favor of wind, which became for the IRA technology neutral and which solar will benefit. So solar projects are now eligible to this type of tax credit. And so it’s also another advantage. In fact, the IRA is an extensive law in order to support all green infrastructures, including renewable projects, including, by the way, storage projects. Storage as well is supported. And when we speak about — for us, it’s very important because we speak renewables.

We want to be integrated. So capacity to build some battery storage capacities is important, energy storage capacity. So the IRA is also supportive of that. So it’s reinforced. In fact, the IRA has given even more value to the Clearway acquisition we have done this year. So it’s a happy news for me because we have — we didn’t integrate, obviously, this type of support to the full portfolio of Clearway, and we benefit from it. So it’s an upside, which will really materialize because we have a very large portfolio. Having said that, coming back to the molecule business, of course, when you speak about hydrogen today, I was asked by the French Minister of Economy in Abu Dhabi, “Do you want to invest in hydrogen?” I answered to him, “Yes, in the U.S.” He was not so happy with my questions — my answer.

But that’s the reality. I mean, you have $3 per kilogram. Having said that, the question is not to make projects if you have no demand. So the rush to infrastructure is good, but we need to find the demand. And I would like to be sure that the demand will follow beyond what is obvious. And I think — because you have 2 types of demand for hydrogen, green hydrogen or blue hydrogen, whatever it is. It is, I would say the industry, the refining industry, the local industry where we need to make local projects because we have local customers, where there is a market for decarbonization. This one, I understand, and we’ll look to that. And we are investing, and we have less assets in the U.S., but we could — we are looking with Bernard to see if we could benefit from it for decarbonizing , for example, it’s obvious.

And then you have the export market, so it’s a massive market, which does not exist for the time being. So I would like to see where it is before to speak about it. Having said that, we begin to see if we could leverage the IRA. For example, we are looking to make sense to make e-methane projects in the U.S. in order to export synthetic methane in the future for liquefaction plans. That could be a nice answer to have these long-term investments, and the U.S. might be the place to make some e-methane. So that type of things that we are working. We are working at CCS. There is another point. Makes sense to look if there are some projects. I think the direct capture projects today, obviously, is to try to test this technology in the U.S., thanks to this IRA.

So it’s part of the technology investments we need to do to coping with our ambition of net zero. What I hope, by the way, is that Europe, instead of complaining, should do the same. That’s all. We need to have — if we are serious about global net zero ambition of the world to make this type of support to invest in green infrastructure all over the world. That’s the answer to do. So I think — so I took it as a comfort to not only our, I would say, electricity strategy, but also, of course, to develop the new molecules. You’ve seen in our budget, it’s coming upwards. I didn’t mention, of course, the sustainable aviation fuel, which is the obvious market that everybody is rushing to, to the point that there were too many projects but — because there is not an infinite demand.

The question, honestly, is not only demand is demand, not only in volume, but also an affordable demand, accepting to pay more, and regulations will be necessary for that. Exposure to spot LNG, you — we gave you some sensitivity on our — but it’s more of the upstream asset. I don’t — I’m not sure you have the LNG sensitivity in the figure we gave. Do we have it?

Jean-Pierre Sbraire: Yes.

Patrick Pouyanne: Okay. So Jean-Pierre will answer to that.

Jean-Pierre Sbraire: The figures we gave for the sensitivity is a global sensitivity. So on oil portfolio, but the impact on the LNG portfolio as well, the portion that is linked to oil and the same for NBP. So the gas pipe, plus the portion of the LNG sold on NANDEX gas.

Patrick Pouyanne: In another way, what we hedged, let’s keep. You take the 48 billion tonnes. You deduct the amount of 4 million tonnes. You deduct the 13 million tones spot. So it makes 30 million tonnes. So if I’m not wrong, I see Stephane. We have hedged more or less this 30 million tonnes of LNG, which we have a long-term supply, either from the assets or from the long-term supply agreements, the contracts in the U.S. The rest is not hedged. So this is why I made a comment on Yamal. Yamal is sensitive to TTF minus Brent.

Operator: The next question is from Bertrand Hodee of Kepler Cheuvreux.

Bertrand Hodee: Two questions, if I may. So first is coming back on the cash distribution to shareholders. I understand the 35%, 40% through cycle commitment is very clear. But when thinking about 2023, given your balance sheet and if oil price there where they are, $80 plus, strong refining margin, what could refrain the Board to go above 40% cash distribution to shareholders? And my second question is a follow-up on LNG. You indicated that you generally hedge over a 1-year period. Last year, my belief was that you had probably hedged at lower prices than the forward curve. Now given the recent fall in natural gas spot prices and LNG prices and the forward curve, how should we think of your hedging position over the next 12 months?

Patrick Pouyanne: First one, the Board, I’m Chairman of the Board, so I had to convince myself. And so just to answer fully, the Board — I’m the Chairman of the Board, so I’m fully consistent with myself, I would say. And of course, we — there is — we — no, I think, honestly, don’t be — again, don’t — I mean, we are very consistent through the cycle. We did not reduce this dividend at a time where there are many reasons to do it in 2020, more reason to do it than to maintain it. We do it because we want to demonstrate our consistency, and that we are fundamentally resilient. So if you compare the increase of 7% to 8% that we proposed today to people who have got the dividend. You say it’s less. Yes, it’s less. But okay, that’s a game that I will not play.

I prefer to be consistent for the cycle. And again, I think it’s an increase. So you should look to that as it was asked to me by — I think, it was Oswald, the first question, if I remember, long time, we were more at under 5%. We go in years, and so we recognize it. But again, for me, it’s very important that it has to be supported for cycles, and we don’t want to come to banks anymore. The balance sheet, you’re right, give us more to support it. This is why we go up. But again, I think we have also the buybacks to continue to feed this superior — this higher in the future. Let’s see what — it’s difficult to anticipate what will happen fully in ’23. So we have already good news to you and to your shareholders. You’ve seen that last year, we did not hesitate to give a special dividend.

We’ll see what will be the price in ’23. LNG was hedged in ’22 with price. And I hope not. Otherwise, I will be super unhappy with Stephane and his team because the price in ’22 were incredibly high. So normally, ’23 will benefit from this hedging. Or I don’t understand. By the way, today, we are lower — the present TTF level is lower than the average of last year. So I should have more returns from ’23 from this hedging in ’22. I mean — so I don’t fully understand your question. And we’ll continue. We have a policy, which is not to hedge everything. But we hedge, and we want to hedge. So why don’t we hedge everything? Because we experienced in ’22 the free port interruption on which we had to take. Because hedging is fine, unless you have a physical issue.

So we don’t hedge all the volumes. And in fact, in ’22, we’re quite lucky because we managed to be — when production was interrupted, but we had some new edge on other volume, so we managed to get it. But it’s — so we hedge a certain — I think it’s 90% — 80% to 90%, and when we keep the rest open. But honestly, ’22 with this price is still good. And as I described, the anticipation we have on the LNG market, it’s a little slow — low today, not low. I mean, I know, for Jean-Pierre, it’s not low at all. It’s $20 per barrel. The $20 per million BTU is quite good. In fact, it’s — we would have told that 2 years or 3 years ago. I would tell you we’d have signed immediately. We don’t even dream it. So I think it’s a policy that we need to manage these positions.

We have long-term contracts. We have exposures to spot markets, and we want to manage this exposure, not to keep it fully on our balance sheet because then you have mark-to-market stories and all that, so we prefer to — so we are fine with the policy, and we will continue to implement it. ’23 will benefit from the hedging of ’22, and ’24 might also benefit from the hedging of 2023.

Operator: The next question is from Amy Wong of Credit Suisse.

Amy Wong: I had a question about your emissions targets. Recall in September 2022, you guys increased low-carbon CapEx and then you teased us with the potential to introduce a Scope 3 worldwide emission reduction target by 2025 and also a revision of the Scope 1, 2 net emission target. Now Patrick, in your prepared remarks, you did mention a few numbers. And could I push you just to talk a bit more about what those emission targets can look like in 2025? And more importantly, I’d love to hear how you think about returns on that specific CapEx, where it’s going towards reducing emissions.

Patrick Pouyanne: What the targets look like. What is the second question? I did not catch your second question.

Amy Wong: I’d love to think about, when your emphasis on your CapEx is always on the value over volume and very high hurdle rates for your capital investment. So for something like low-carbon CapEx that goes specifically to reducing CO2, I’d love to hear about how you think about the returns there.

Patrick Pouyanne: Okay. The emission targets, first, when we speak about for ’25, to be clear, the previous target was 40 million tonnes, Scope 1 and 2. I just mentioned that the plan of energy savings that we have put in place should deliver 2 million tonnes lower. So that means that the target will be reduced from 40 million tonnes to 38 million tonnes. I mean, I’m anticipating on the Board decision, but I think there is a logic there by ’25. So we’ll improve the target by ’25 by 2 million tonnes. But we are reviewing not only this one. We are reviewing, like always, year-over-year, what is the status on the various intensity in order to monitor that properly. So I don’t want to anticipate the decision will be taken. This is on Scope 1 and 2, I’m quite clear on this criteria.

Look, let me be clear, but these emission targets that we have today, lowering our emission today is not a matter of carbon capture by ’25. It’s a matter of a lot of projects, which are just being more efficient. There’s some technology to implement on on everything. So we could describe to you at a point the type of projects. Maybe it will be a good idea by — in September, we’ll have a strategic day to come back on this topic if you are — if most of you are interested in it. So carbon capture are more for 2030-plus targets, where we will need to have implemented. Within criteria for carbon capture, it’s just a matter of price of CO2. That’s why, I think, in the U.S., you have the IRA. In Europe, you have this $100 per tonne price. So when you compare both, at the end, it is — more or less it gives another economy.

And from this perspective, as Europe seems to be very serious about CO2 pricing, I think, on the long term, it’s something which is maybe more sustainable, but fiscal incentive, which could — which is sustainable for 10 years. It could disappear afterwards. The key on CCS will be, of course, the size of the market. We need to — because there is some infrastructures to amortize. So my view is that you need to reach at least 10 million tonnes, 50 million tonnes per year of storage if you want to have a profitable model. That means proposing transport and storage services to cement industry of less than $50 per tonne. Because they capture costs, they could go around $50 per tonne. So if you speak about $50 per tonne, you need to split it between both.

It works, again, if the support for infrastructure is key, if you have enough tonnes to put in those projects. From this perspective, you know the Denmark project is well located, not far from Germany. It’s shorter to make a pipeline from German industries to Denmark, one from German, so Norway. Just looking to a map. So that might be a bit of volumes. Now the Dutch project is good because you have the Rotterdam and larger industrial platforms, which could give some customers to these Dutch projects, Aramis, and what we are working on. So that’s the idea. Return criteria, again, it’s — we have to look to — we have to do it because it’s — by the way, for me, for the oil and gas industry, it’s a question of permit to operate, all right? We have to be serious about lowering our Scope 1 and 2 emissions.

You know that I’m not very a big fan of the Scope 3 debate. But of Scope 1 and 2, I’m very serious because it is a duty for us to do it. We have technologies. We have capacity. So it’s a cost. It might become an opportunity if we can commercialize the technology to third parties, and this is — or one B2B entity is trying to develop that. We have a first project with Holcim in Belgium on these type of things. But again, for me, we will develop first this project because we have to do it for our own emissions. It’s a question of permit to operate. And in oil and gas industry, this is embedded in the global strategy of the company. But as I show you, we can be very profitable. Like we are among the best and, at the same time, having CapEx for low-carbon energies, carbon capture, we do it in a large way.

It’s possible. It’s building the future of the company. The $5 billion that we have mentioned for 2023, I think, is a level, which will be maintained for the following 3 years. We don’t intend to grow it very much higher. I think it’s a good level. If we want now to combine growth and profitability, if — and we want to do it, so it’s not if we want to do it. So I think it’s a good level, and it’s — it obliges us to be selective, but selective in a large way. So we have room for improvement for deploying these. Why I say that, it was just because we are not — in 2022, we have managed our 6 gigawatt per year with this type of amount. So for me, I have enough CapEx to make my 6 gigawatt per year, which is more or less the objective, which are assigned to the teams of Stephane.

So I should not — yes, and the only point is coming back to Michele’s question is what is the size of the ambition is the new molecules. And for me, the question on hydrogen and all that is more about where is the market, which will drive our expansion of CapEx.

Operator: The next question is from Jason Gabelman of Cowen.

Jason Gabelman: This is Jason Gabelman from Cowen. I have a couple of questions. The first is you press released last week that you had farmed down a position in the renewal power asset at a high multiple, but it was a low overall cash contribution, one that I wouldn’t have guess the materiality of press release. It was a few hundred million dollars. And I’m wondering why you decided the press release was given. The thought was you have been farming down these assets all along. And if that potentially indicates that given the market environment, you’re possibly accelerating the farm downs of the developed renewable power business over the next year and what type of cash flow contribution that could bring. My second question is on the LNG portfolio.

You’re obviously undergoing the review in Mozambique, but there’s also been some reporting that you could take a large stake, either offtake or equity in a U.S. LNG project. And I’m wondering, if your case of growth in the U.S. LNG market is at all dependent on what happens in Mozambique and if you’ll still continue to view the U.S. LNG market as one in which you want to grow in.

Patrick Pouyanne: Jason, you have complex question, but easy to answer. First, no, there is no acceleration at all. We have been always very clear. But to reach the double-digit profitability we want to have in renewables, we’ll have to integrate farm downs. It’s part of the business model. This is why we have some growth capacity objectives that is 35 gigawatt growth. But at the end, we’ll keep more or less half of it. This is very clear. We stated that 3 or 5 years ago when we began the strategy, and we implement it. So there is no acceleration. It came on our desk. There was some assets in France, which were part of to being farmed down. It has been done in a very good way. And thanks to this farm down, we have on these assets more than a double-digit return, much better.

We don’t give all the details because there are also a counterpart, but that’s clear. So it’s — to be clear, and we have embedded in the strategies a fact that maybe we developed a 100% project. But when we farm down. And by the way, I always explain to you several times, it’s not only a matter for me of profitability. It’s a matter of managing the risk. I prefer to have 2x 50% of 2 projects, and 1x 100%. It’s just a matter of things could happen. So that’s — yes, I can tell you, by the way, it was 16x EBITDA, if somebody gives me an indication, 16x EBITDA. So I think 16x EBITDA, I can tell you, no problem. I can’t continue to develop my renewable business with this type of returns of 50% of my portfolio. And this gives the cash also to recirculate the cash and risk this project.

So I think it’s a smart way, and we’ll stick on this strategy. No, there is no link between Mozambique and the U.S. We like both. We like LNG, okay? We want to continue to grow in a growing business, which is LNG. LNG is good. LNG is international gas. LNG is a way to decarbonize the coal-fired power plants in Asia and elsewhere. So there is no fear about it. Maybe, there may be some cycles. Today, it’s at the top. It could go down because we are not able in the industry, of course, to plan all the plans very smartly. We invest, but — so we are — we think that the U.S. on the long term is competitive because you have the U.S. gas price is about the lowest in the world, so $3 to $5. Even at $5 per million BTU, it will be very, very profitable.

So that’s the reason why. So yes, we have Cameron LNG. Yes, we have ECA in Baja, California, Phase I, which is being built, and Phase II may be in the near future. We are looking over opportunities in the U.S., and it’s independently of Mozambique. Mozambique, just to make — to answer your question, I spent a day last week, Friday, a day in Cabo Delgado because my — that — my company, I said there is no way for me to envisage any restart of Mozambique as not as you don’t allow me to visit Cabo Delgado. And I can travel around with a car, not an army, but alone. So we are only 3 of us, 2 cars. I want to go there. I want to check. I want, in fact, to go to see what if life is back to normal. I can tell you what I’ve seen from a security point of view is good.

Even life is back to normal. Villages, people are back. But it’s one step. There is more steps to be done. The 2 next steps, it varies and I — because there have been some, I would say, controversies about human rights, about the — around the project, not because of us. We inherited that from Anadarko acquisition. So I want a clear view on these human rights issues, which is a salient issue for me. It’s important. I have given a mission to — especially to human rights, a very well-known doctor in France, was accepted. He’s making his job, so I’m waiting to see his report to understand exactly what is, I would say, these — what are these issues. If there are things to be done, we’ll execute the recommendation. We’ll be transparent on it.

We will share obviously with our partners because it’s a Mozambique LNG decision to restart. It’s not a TotalEnergies decision. It’s — all the partners should be on board. And there is a third step, which I can use this question to deliver is that, of course, we have to reengage with the contractors. And one key condition to restart will be to maintain the costs that we had. If I see the costs going up and up, we’ll wait. We have waited. We can continue to wait. And the contractors will wait as well. So I’m not in a hurry in this condition to restart. Don’t — so there are conditions, I think, are okay. Human rights, I need the report. Costs, we will need another report from my teams. We will — probably, I will ask them to reengage, but smoothly.

No hurry. Again, I can wait on Mozambique LNG. If costs increase, we will wait, and we’ll take the time. So that’s where we are on these projects. So my message is positive, but it will take time. And it’s not in competition with the U.S. We are ready to finance both. We have the capacity to finance both within our $16 billion, $18 billion. These are 2 good projects. It did all that — by the way, on the U.S. projects, we could say the same. What I see when we discuss with some project developers is that costs are increasing also. So it’s good to rush for volumes. But if you destroy the value because costs are too high, we know what is the impact at the end, and we experience it. So that’s the same for me, debate. It’s more a question today on — we are very convinced by the U.S. and by the LNG market, but we need to have cost efficiency in the project.

Operator: The next question is from Lucas Herrmann of Exane.

Lucas Herrmann: Patrick, simple one for you. I think contracting LNG long term, not into portfolio, but out of portfolio, I mean you’ve waited sometime, I’d say, too, for the cycle to turn in terms of oil-linked contracts. Pricing has obviously improved quite significantly. Should we be expecting you to offload an increasing amount of your unhedged — or not unhedged is the wrong word, uncontracted volumes in to customers and give us a greater visibility and ways on duration and long-term people and oil linkage into the future with it?

Patrick Pouyanne: You’re right, Lucas. We can employ you if you want to manage my LNG business. It’s the right time to contract long term. Of course, the buyers, there is a little more willingness by the way of buyers because, suddenly, they see some value. Of course, when you contract long term, it’s linked to brand sometimes. So it’s an arbitration between and — I mean, gas spot index and Brent. Where it is one projects on which we want to balance the risk, it’s PNG, Papua LNG. We said — of course, my team today, we would like to keep a volume. So we’ll have right to keep a volume, but most of the volume will be contracted in the long term because it’s — again, it makes a little sense to contract when you have some 11% — or 10%, 11% Brent proposal from customers.

When you are going up to above 13%, you can consider you are again there. So that’s the right time. Having said that, I think a philosophy for us is more to keep this balance of 70% long term, 30% spot. We have the balance sheet. We can use our balance sheet to keep part of the risk. Okay, when you keep an exposure to spot index, you take the risk like in 2020, but you take — you keep the upside like these years. So I think this is, for me, the core of the business model of a company like TotalEnergies. So strong balance sheet must allow us to take these type of risks — spot risks. But the 70-30, okay, it’s not a bible. It’s more or less we are comfortable with that in terms of management of risk in the company as we grow. So today, there are some projects on which we will lose long-term contracts.

And again, it’s like — by the way, we can also develop some project being spot, knowing that we can use this window of opportunities to then sign long-term contracts. This is what we say even to our renewable people. You want PPAs, but sometimes you could — we could accept to develop projects not with a PPA merchant projects with the idea that, tomorrow, when we have the right opportunities, we will cover part of the exposure with a long-term PPA. So that’s the beauty of the balance sheet.

Operator: The next question is from Paul Cheng of Scotiabank.

Paul Cheng: Patrick, both BP and Shell have recently made a pretty large acquisition in the biogas area to jump start their operation and also to grow in that area. Just curious that you did mention that you guys have a largest unit of the biogas in France that you just start out. You also have a venture — or joint venture that — to manage you — to developing some biogas project in the U.S. Do you think biogas would be a more important part of your low-carbon energy business going forward? And if so, do you think you need to have a larger platform maybe through an acquisition that — to accelerate the growth there? That’s the first question. The second question, first, thank you for breaking out the integrated power business starting in the first quarter.

Can you tell us that what is the return on that basis that currently that you achieved? Your peers, I think BP and Shell, seems to stop questioning the overall return on that business. And just want to see that what’s your view — or what you guys have been able to achieve so far.

Patrick Pouyanne: Biogas, honestly, M&A is a way to grow if you can deliver the value you pay. And I have difficulty to be convinced to put several billion dollars in biogas. Why? Because then, we are doing things, and we have — we bought a platform in France. We just bought a new platform. It will be announced soon in Poland. Why? Because it’s quite a local business. It’s like renewables. The way you manage — the technology is not high tech. Okay, you can do larger ones, but there is no rocket science. So then it’s becoming a question of local development. And I’m sorry to tell you, this is not because you are good in a Nordic country to develop biogas, but you can be good in France, where the agriculture organization, the agricultural ecosystem is quite different.

And so at this stage, we have not been convinced, and we have studied some of these files. But really, these platforms will give us the edge to grow beyond the core country. Just — so we prefer — maybe we are wrong to go step by step, not bringing a lot of noise with billion dollars, but we prefer, by the way, to make smart direct negotiation, but bidding with banks, which, of course, push price up in order to do that. There is a country where, obviously, we have more size is the U.S. The U.S. is more attractive for this perspective because, by the way, the system, the — all the CFS system and all that is more liquid. So you can not only produce, but you can imagine to get more value of trading, the volumes and mixing the biogas with others.

So the systems, the carbon systems markets in the U.S. give more liquidity to that. In Europe, it’s fragmented. All the regulations are not the same. It’s one of my advocacy when I go to Brussels to tell them that if they want this business to be developed, it could — should have a unique — you want European market and not — the rules are different in all the countries, so it does not help to grow it. So when you are in the gas, you look to biogas. In particular, because our customers are looking for that. They want to — if you have customers, we have made the bet to go to LNG for transportation, which we would love to have, bio LNG. So volume is not there. So there is a good momentum for selling these molecules. Then the question is scalability of all that, to be clear, and that’s a question mark.

So we are looking to — we have some options in our portfolio. We grow it more locally. If we do something larger, it will be probably in the U.S., rather than in Europe, but that’s part of it. On — I mean, I listen to my peers. And again, I respect them, but I think being consistent in the strategy is just fundamental. And we have decided a strategy, which is clear. Again, we are — with the business model I described, we will be able to deliver a double-digit business, and that’s the commitment we took. There’s no reason for me today to derive from this objective and from the capacity to do it. Of course, we have to build that. We have to be — we make very good projects. Some are not as good. But I don’t see what we should — and I think if we make zigzag on the strategy, we’ll do nothing at the end of the day.

So I prefer to keep on my strategy, which is — and again, we are very consistent, by the way. I think the decision, I have proposed to the Board to accelerate this segment, this reporting of the IP power — integrated power business because having discussed with our shareholders after our roadshows in — after the presentation in New York in October and November, it is clear that there is a legitimate request from them. You invest this amount of money in this business. We want you to demonstrate to clarity — given clarity of these businesses. So I think this is a question. But I’ve been CEO for 9 years now. I think it’s — listen, is you need to stick on the strategy and not to be — otherwise, in this new low carbon business we will not — never reach the size, and I prefer to reach a size which is consistent.

We will become a key player. And again, being able to grow our renewable business by 6, 7 gigawatt per year, we are among the largest one compared to the large — and so I think we can — and we’re mixing that with our capacity to use the balance sheet to integrate that in a larger platform, trading, et cetera, will allow us to deliver this profitability. So it’s a commitment. It’s also part, by the way, of our net zero ambition that we have and on which we are serious about it. But at the end, for me, is positioning the company on the long term on a profitable business because we are convinced that the world will need more electricity, and more electricity means higher prices.

Operator: The next question is from Alessandro Pozzi of Mediobanca.

Alessandro Pozzi: I have two. Going back to the emissions, I think they became — they came in below target in ’22, but they were still up year-on-year. Part of it, I think — most of it was driven by CCGT. And I was wondering if you can give us perhaps a target for 2023, how you see Scope 1 and Scope 2 emission evolving. And also — I’m also seeing that Scope 3 have come down, and I was wondering what are the main drivers for the reduction in Scope 3. That’s the first question. The second question is on refining. Of course, the EU ban came into effect on the 5th of February. I was wondering how you see the market for diesel in Europe with the ban. Will we be able to source more diesel from somewhere else or it’s going to be as tight as — especially in the second part of last year? And also on refining, of course, we are seeing protest in France. Is that going to have an impact on Q1 margins? That’s all for me.

Patrick Pouyanne: Okay. Emission targets for ’23, as I announced that we will lower the 25% target to 38%. I think the target for ’23 should be something like under 40 million tonnes. So we’ll have to repeat at least and lower the same performance in ’22. No increase. So we are accelerating the target. There was — the Board has made a linear decrease, I think. So probably 39.8% exactly, if you want the figure. Jean-Pierre is putting that on the paper. On refining, diesel market, honestly, it’s — the source of the product is diesel. There is a strange machine, which is organized in the world, which is . You — India and China are buying Russian crude and they transform it in an Indian and Chinese diesel, which will come to Europe.

I’m not sure it’s good for the climate. It’s not good for the cost. It’s not good for the customers, but that will happen. So I’m not worried about finding diesel. It will be just more expensive, but it’s a cost. So question for is it real — does it has — does the market has already anticipated or not the disruption of the Russian diesel in the spread of the diesel, which were quite high? By the question mark, I mean, it’s difficult to answer to this. Normally, they anticipate, but there is a cost issue of transportation cost. The margin for the time being, I don’t know. It’s difficult for me to predict on Q1 ’23. What I have observed since the beginning of the year is that the margin in January were higher than in the last quarter. They came back probably because the market was anticipating again distress.

So we see increasing . I think we are today at an average since the beginning of the year above $100 per tonne probably. So again, this market is still strong. It’s weakening. And so we’ll see. But again, as — it’s difficult to understand what the operators in the market are taking into account or not, but this is what I think.

Operator: The next question is from Henri Patricot of UBS.

Henri Patricot: Just one question left. On your comments around the global LNG market and European gas in ’23, when you show European LNG imports potentially up to 25 million tonnes for this year, can you expand on the assumptions around European gas demand? It seems like this will imply quite a rebound this year. So where do you see that coming from?

Patrick Pouyanne: I’m not sure I have understood the question. Is the European gas demand — yes, in 2022, I think what we have observed is more or less minus 15%. I mean, this is the figures I have in mind. I mean, I’m controlling — stephane confirms. As your question for me, will it be accelerated in ’23 because we see a trend, it was a shift mainly from gas, by the way, to oil. A central number of manufacturing industries shifted from gas to fuel, which we can understand. The gas was at $200 per barrel, and the fuel was probably at $120 per barrel. So there was an arbitration down. Part of it has been coal, but less than what we were thinking. What will happen in ’23, I think, again, this price still today is $120 per barrel , $2 per million BTU, it’s still high, so it could damage it.

We gave you, I think, in the slide, we are quite clear about what our expectation. We think that EU LNG imports will be higher in ’23 than in ’22 by 15 million, 25 million tonnes. Maybe part of the demand disruption will come back. I’m not fully convinced it’s really linked to the price. So that — and again, I think people today, we are entering into a new world in Europe where energy prices are high. Energy costs are high. For energy consumers, I think the idea that they should be serious about the way they consume energy will be deeper in their mind, and they will invest like we do. By the way, I think this is the only advice we can give to them. If you want to lower your energy invoice, you have to consume less, and so to be efficient, like we are doing in TotalEnergies with our energy saving platform, refineries, et cetera.

Operator: This was the last question. Back to you for the conclusion.

Patrick Pouyanne: Emma, thank you. Thank you to all of you. I’ve seen that we have a good attendance to this presentation. So next meeting will be in March, either the 21st or 23rd. We’ll confirm you the date very soon, to make this presentation on strategic sustainability and climate based around our sustainability and climate report, like we’ve done last year. It will be live. It will be live in London, and no more with Teams because we like also to have the opportunity to have more discussions, informal discussions with all of you. So thank you for attending this presentation and supporting again the rating of the TotalEnergies shares. Thank you.