Ladies and gentlemen, welcome to TotalEnergies First Quarter 2023 Results Conference Call. I now hand over to Patrick Pouyanné, CEO; and Jean-Pierre Sbraire, CFO, who will lead you through this call. Sir, please go ahead.

Hello, everyone. Good morning or good afternoon, wherever you are. I'm here today together with Jean-Pierre. We'll give you a review of what I would say, is a very good quarter that we had in the first quarter of 2023. I just wanted to, as an introduction, comment on the news that came this morning around dawn regarding the future of our Canadian assets. As you know, we explained that in September at our CMD, we are planning to organize the spin-off of our Canadian assets. We went through the process and, in the meantime, because fundamentally, I think we are very serious about making this spin-off a reality, we attracted some unsolicited offers in the last months. One of them has materialized, and I think at a value which is quite attractive, CAD5.5 billion cash plus CAD600 million of additional payments under certain conditions. The value is fitting with the expectations of the initial quotation, which were given to us between CAD5 billion and CAD6 billion. Of course, it's coming from Suncor, which knows very well one of our two assets. Suncor will comment later in the day on his own view of the deal. For us, it fits the value. It's a straightforward way to divest the assets as we planned to do straight away. So, from the company and shareholders' point of view, the Board considered that this alternative was worth considering and approved yesterday to move forward with this transaction. The most important part of the discussion was about the distribution to shareholders because, as you know, the spin-off was meant to be a distribution in kind of shares of the NewCo. We more perfectly had that in mind, and the guidance we decided to give to our shareholders today is that last year, we provided a higher guidance of the payout to shareholders of 35% to 40% of cash flow from operations. That was down in 2022 to 37%, but because we will have additional proceeds from these sales, the divestment, the guidance we give you today is at least 40%. That means, by the way, I told you before that there was no ceiling; the 35% to 40% was the target range. Today, we told you the Board decided to enhance, for 2023, this distribution to shareholders with at least 40%. So consider 40% plus. You have to include the plus, meaning at least 40% of cash flow from operations in 2023, which I think is good news for our shareholders, and which, of course, maintains the course of the company. You have noticed that in the first quarter, we maintained a buyback of $2 billion, like in last year's last quarter. In the second quarter, we repeated the $2 billion. This guidance for the distribution to shareholders for 2023 of at least 40% of our cash flow from operations should give you some comfort about the Board's will to maintain or even develop an attractive return for shareholders. I will not take longer. I think I will give the floor to Jean-Pierre, who will be happy to present the results for the first time of – today, we disclosed the Integrated LNG and Integrated Power segment results.

Thank you, Patrick. So, 2023 is off to a good start. Once again, I think we demonstrate our ability to generate strong results even amidst technical difficulty. Quarter-to-quarter, Brent was down 9% to $81 per barrel and European gas dropped by 50% to $16 per million Btu. In this context, TotalEnergies reported first quarter 2023 adjusted net income of $6.5 billion, a decrease of only 13%, and a strong cash conversion with a debt adjusted cash flow (DACF) close to $10 billion. With Brent above $80 per barrel and European gas above $15 per million Btu, still high by historical standards, we are continuing to deliver excellent profitability with 25% margins in the first quarter. Commodity prices have been volatile, albeit still at high levels. Oil prices did fall briefly below $75 per barrel in March, largely due to concerns about an economic slowdown before rebounding in April on OPEC+ quota reductions. Refining margins have eased down after several quarters of extremely high diesel cracks in the same context of fears of economic slowdown, high product inventories, largely fueled by Chinese exports, and the quicker-than-expected reorganization of Russian flows following the European sanctions. Gas prices fell due to mild weather and we expect prices to remain stable, especially as we restart operations beginning in the second half of the year. Future markets are anticipating prices next to $20 per million Btu for this winter. For the first time, we are reporting Integrated LNG and Integrated Power as independent segments. These two growing segments are at the core of our transition strategy. The restated historical data for 2021 full year and 2022 quarters is available in the results package. In terms of scale, integration and performance, we remain unmatched among our peers in both ROV activities. We have achieved our position as the largest lifter of low-cost U.S. LNG with over 10 million tonnes, and the largest regas provider in premium priced European markets with about 20 million tonnes following the recent start-up of FSRU in Germany. Our unmatched access to the European market creates a competitive advantage for our trading operations and makes us more competitive as a partner in securing future resources. For example, we launched the fees for Papua LNG this quarter, and this will contribute to the future growth of our portfolio with close to 2 million tonnes of equity production. Last year, with LNG sales of 48 million tonnes, this business generated $10 billion of cash flow. In the first quarter, sales were 11 million tonnes and cash flow was $2.1 billion. In the first quarter of 2023, LNG sales were down 70% quarter-to-quarter and 13% year-on-year, reflecting mainly a decrease in spot sales due to lower LNG demand in Europe linked to the mild weather. Integrated LNG generated adjusted net operating income of $2.1 billion, down only by 10% compared to the previous quarter, excluding Novatek, mainly due to lower prices. Given the evolution of oil and gas prices in recent months and the lagged effect on price formulas, we anticipate that our average LNG selling price might decrease by another 10% to 15% in the second quarter because of this time lag, versus $13.3 per million Btu this quarter. Operationally, we expect benefits from the restart of Freeport LNG in our Q2 2023 LNG sales. As for the two new segments, Integrated Power is the newer business activity in the company. Mainly through the smart acquisition of early-stage development projects, we have grown this business to 18 gigawatts of gross installed renewable power generation, our two largest markets being Europe and the U.S. We are solidly on track to reach 38 gigawatts by 2025 and then 100 gigawatts by 2030. Our flexible power generation capacity and growing positions in energy storage are fully integrated into the business strategy, allowing our traders to maximize our performance. Last year, we met a power production of 33 terawatt hours. This business generated about $1 million of cash flow. For the 12 months ended March 2023, Integrated Power generated or overachieved 9.9%, close to 10%, consistent with our stated objective to achieve double-digit profitability for this activity. Moving into the details of the results of these new segments now, renewable power generation capacity was 18 gigawatts at the end of this quarter, an increase of more than 1 gigawatt quarter-to-quarter, thanks to 0.6 gigawatts from the acquisition of Casa dos Ventos in Brazil and 0.3 gigawatts from the connection of the Seagreen offshore wind farm in the UK. For the Integrated Power results, the best reference for comparison in Q1 2022 is the Marketing and Services business, where the Gas and Power marketing business remains. Net electricity generation was 8.4 terawatt hours in the first quarter, up 10% year-on-year due to growing electricity generation from renewables, offsetting the lower generation from flexible capacity in the context of lower demand. Integrated Power posted adjusted net operating income of $170 million. This figure is significantly higher compared to the first quarter of 2022, which had an adjusted net operating income that was negative at minus $82 million. Last year was heavily impacted by a huge increase in supply costs. This year, all segments have done better. Gas-fired power plants, renewable supply, and trading despite the negative impact of winter seasonality in the power marketing business; higher cost of supply in winter versus equal invoicing throughout the year for many customers. Now, moving to the oil parts of our business. Operationally, our oil and gas production was 2.52 million barrels of oil equivalent per day, up 2% quarter-to-quarter, excluding Novatek. This includes the acquisition of a 20% interest in the already producing oil field in the Emirates, starting from mid-March. The production also benefits from new projects, notably the startup of gas production of blockchain in Oman and the ramp-up of production in Norway. Production for Q2 2023 is expected at around 2.5 million equivalent barrels per day. Exploration and Production reported adjusted net operating income of $2.7 billion, down 22% quarter-over-quarter excluding Novatek, due to lower oil and gas prices. In the Downstream now, Refining & Chemicals contributed $1.6 billion of adjusted net operating income, up 9% quarter-to-quarter and 44% year-on-year despite ongoing pension protests in France at the end of the quarter, thanks to strong refining margins. Refined utilization rate was at 78%. For Q2 2023, we expect the refining utilization rate to increase above 80%, given the end of strikes in France. Marketing and Services results are stabilizing at around $300 million of adjusted net operating income, $280 million for the first quarter of 2023, up 3% year-on-year despite sales being 6% lower, demonstrating that our strategy of value over volume is working. Overall, at the company level, pre-working capital was $9.6 billion in the first quarter, plus 5% quarter-on-quarter despite the lower price environment I already commented on as the fourth quarter of 2022 was impacted by exceptional taxes, notably the $1.1 billion European severance contribution, mainly impacting LNG and Exploration & Production to a lesser extent. There was a $4.5 billion working capital build in this first quarter of 2023. This is exceptionally high for the first quarter mainly related to higher crude and petroleum product inventories, which are due to the impact of the pension law protest in France. This exceptional element explains $1.4 billion of working capital build and will disappear next quarter. The second factor is the seasonality of the gas and power marketing businesses, which creates a gap between the seasonal cost of supply and the fixed monthly payments from B2C clients. Additionally, the usual effects of lower prices on tax and trade payables contribute to this working capital build in the first quarter of 2023. Much of this working capital build will reverse in the next quarter, particularly the higher inventories associated with protests in France and the seasonal impact on the gas and power marketing business. There was also a higher net investment in the first quarter at $6.4 billion, which includes $3.3 billion for acquisitions, notably the purchase of a 20% interest in the SARB and Umm Lulu concession, payments related to the acquisition of a stake in the Northeast project in Qatar, and a stake in the joint venture with Casa dos Ventos in Brazil. Our guidance for 2023 net investments remains unchanged at $16 billion to $18 billion, which includes acquisitions and divestments. The sale of petroleum assets that Patrick mentioned for $4.1 billion, with closing expected in Q3, should fit within this range. We also announced a sale for $3.1 billion, which is expected to close by year-end. Encouraged by the strong first quarter results, the Board confirmed a 7.25% increase for the first interim in 2023 to €0.74 per share, along with a $2 billion share repurchase in the second quarter of 2023. And I think now we can go to the Q&A with Patrick.

Thank you, everyone. We will now begin the question-and-answer session. The first question is from Oswald Clint of Bernstein. Please, go ahead.

Good afternoon and thank you very much for the time. I'm happy to guess the plus on the 40%. And if I was to go up into the mid-40s, I guess, I see the issues. But the range becomes...

No, no, no, no. At least 40, at least 40. Forget the plus. At least 40. I think some of your colleagues can find what it means, so you can guess.

But, I guess the question is, is the 40% a number we could think about when you have good divestments topping it up? And if not, should we think more around the 35%. And then, just related to that, is there any Novatek dividends included here? I know Novatek declared a dividend last week, and it's up quite materially. Do Total expect to get anything in 2023 in terms of cash flow? And then, the second one is just, Mozambique LNG, lots of momentum, lots of discussion from the President recently. I think you're still hoping to secure some of the favorable cost terms, construction terms. Any update you could provide us on that side of it, please? Thank you.

Okay. We provided guidance of 35 to 40, indicating that there is no upper limit, but it’s not a confirmed minimum. Last year, we achieved 37. This suggests that there are no strict figures being monitored. The significant update today is the Board's announcement of a spin-off, which constitutes a dividend in kind. We are committed to our shareholders, particularly since we chose the direct sales approach to reward them. The decision made yesterday indicates we are uncertain if we will allocate funds for buybacks or special dividends at this time. We need to assess our progress throughout the year before making that determination, but we see this as an opportunity linked to the spin-off through a kind of dividend. We anticipate going beyond what we've announced, targeting at least 40%. Discussions will follow regarding either buybacks or dividends. For now, we’ve maintained a $2 billion buyback each quarter for the first half of the year, despite a softened environment, and there's a possibility of sustaining this throughout the year. If you calculate based on this, you might see results exceeding 40%. Regarding Novatek, the situation remains unclear due to ongoing developments from Russia. The Russian authorities have shown intentions to sanction more European companies, complicating our position. As we are no longer consolidated with Novatek in our accounts, the dividend decision there is noted. Regarding Mozambique LNG, we are approaching the final steps before restarting. However, we require our contractors to provide reasonable terms, and some have not been reasonable, which may force us to reevaluate certain contracts due to unacceptable new costs. We have paid what we had to pay because we stopped the project, and we need to restart the project, which obviously had an impact due to the stop and restart. We don't see why we should pay more than what we’ve already paid. That's where we progress. When we are ready, we'll come back to you on the cost agreements, but we think it is premature again because our teams, the project team is negotiating with the contractors to be able to announce the project, but under the conditions that the costs are controlled. That's fundamental to us.

Excellent. Thank you.

The next question is from Christopher Kuplent of Bank of America. Please go ahead.

Thank you very much. Patrick, I'm going to ask you probably the same question again, if you don't mind. I think what I've heard looking for clarification is the decision before the disposal to Suncor was to basically give proceeds to shareholders directly. Is that a principle we should continue to talk about and to consider the $4 billion as effectively an add-on? And then we can run our cash flow from operations payout numbers as long as we like. So that's my question, just looking for confirmation. And lastly, second question, slightly connected to that. You've done, as you've highlighted, more than $3 billion of acquisitions in the first quarter. You’ve announced disposals that go well beyond this, but if we accept that the $4 billion disposals ought to be distributed to shareholders, you're kind of running on an even number for the full year. And I appreciate you're not likely to give us a number, but I wonder how big the Total Eren completion looms, and whether you can confirm that it is baked into your $16 billion to $18 billion guidance. That would be it. Thank you.

No, Chris, I need to clarify. We never stated that the $4 billion would be returned to shareholders. Additionally, that was not the situation during the spin-off. If you recall, the enterprise value was approximately CAD5 billion to CAD6 billion; let’s estimate it at CAD4 billion to CAD5 billion, which would account for the company's debt and leave proceeds for the company before we proceeded with the spin-off, maintaining 30% on all sides. If you calculate that, you arrive at around $5 billion, likely $4 billion. Once more, that's not how we articulated it. We have consistently maintained that the Board's decision is that proceeds from sales do not affect cash flow from operations. The cash flow from operations is reported on a reduced basis in all communications regarding our results and accounts, excluding cash from divestments. Thus, we have a certain cash flow from operations. As you know, last year, we recorded $46 billion at $100 per barrel, and at $80, I expect it to be between $45 billion and $40 billion. If we achieve four quarters at $9.5 billion, it will total $28 billion. If you achieve more than 40%, you can estimate the payout guidance for shareholders. You subtract the dividend, which you already have information on. You can even calculate it for all quarters. The only uncertainty is the euro-dollar exchange rate. Then you can determine the potential amount. The Board is considering whether to execute a full buyback of shares, conduct share buybacks, or issue special dividends. This will be addressed and monitored throughout the year. Our feedback indicates that the company's stock is undervalued compared to some US peers, and there is potential for improvement. Maintaining a share buyback, without increasing it, is likely a wise investment that reflects our confidence in our shareholders and the company's future. Regarding your other question, while there have been some acquisitions this year, we cannot track them on a quarterly basis. Additionally, there were two significant announcements involving the sale and divestment of the European network, as well as the Canadian divestment, which will bring in proceeds. TotalEnergies is included in the $16 billion guidance, and we will not alter this guidance because I'm not entirely certain about all the proceeds. I believe the Canadian proceeds should come in this year, as it is a straightforward process, but the European network has more complexities related to carbon energy and other factors. Everyone is working to close the deal before year-end, and both parties want to do it. So you know, sometimes, you have entities, so TotalEnergies integrated and Total Eren, I think in cash is around $1.5 billion to $2 billion that I think we already mentioned.

That's great. Thank you very much, Patrick, for the clarification. May I add one quick follow-up? Could you give us the details around the carrying value of your Canadian assets that are to be sold?

What is a value? You mean the capital employed in our balance sheet? It's around $5 billion.

Perfect. Thank you.

And there will be a capital gain. I mean, there will be a positive result in our account, but I would say it's an exceptional result.

Yes, it will be treated as an adjustment in our accounts.

Thanks.

The next question is from Irene Himona of Société Générale. Please go ahead.

Thank you very much. Good afternoon. Two questions. First of all, on your E&P tax rate, please, which increased in the quarter. Can you remind us what is included in the first quarter in terms of upstream windfall taxes? And then, at current price levels, what should we anticipate for that average E&P tax for the full year? And then secondly, you referred to the significant inflation in renewables. Could you possibly talk around inflationary pressures you're seeing in your upstream operations, please? Thank you.

Patrick will take this question regarding the tax rate. So, of course, the Q1 has been prepared the same way as the 2022 accounts. At that time, I explained that the E&P tax profit in the UK is treated in the adjusted net income. So it has an impact in the 22% tax rate, and of course, it has an impact in the Q1 2023 tax rate. The amounts representing this start at $0.4 billion, just to give you one figure. On the opposite, all the exceptional contributions in relation to the European decision to implement an exceptional contribution in 2022 were treated in '22 as an exceptional element. Of course, we continue this treatment not impacting the tax rate in the first quarter of 2023.

Cost inflation in the industry. I mean, again, I think our timing of OpEx per barrel is at $5.5 per barrel. In our operations, I do not see much impact. By the way, we had very good performance from the team. On the rigs, yes, we know that the departure rigs are more expensive, but we are benefiting from the fact that we had quite a number of long-term, medium-term contracts. So we have seen some impact, but it's limited. Where we have seen some inflation was more on the steel last year. We resisted, by the way, we are right because the steel went down again. The question is more that we are facing the will of some contractors to get some money back from what I would say were bad years. We looked at our results, and they want to try to get their share of the cake. But again, it's a question of supply and demand for me in the end. There is no reason to accept to pay more if supply and demand are not stretched. For me, there is not a stretch on many elements. This is why I was mentioning Mozambique. We will go to bid when we feel that the contractor awarded the contract is trying to benefit from the situation, but we are not in that area, and we know where the market is best to go to tender. I don't see much inflation today, even if we have to resist, which by the way is a good message to Aptiv, which is simplifying the projects, and that's good for everybody. Okay.

The next question is from Martijn Rats of Morgan Stanley. Please go ahead.

Hi. Hello. I wanted to ask if you could outline a bit the sort of triggers or the drivers that would lead to the full payment in the disposal to Suncor. I've noticed that the press release wasn't all that clear about it. If you could say a few words about that, that would be helpful. Additionally, I wanted to ask if you could perhaps share some thoughts on the global LNG market. I noticed that on Thursday and Friday last week, Europe enjoyed all-time high LNG imports, which is, of course, a little surprising given that the price has been going lower, and yet the LNG keeps coming. It doesn't look like Asian demand is picking up all that much either, at least based on the data available to us. Perhaps in your business, you have earlier insight. Could you clarify if you're seeing anything in terms of an Asian demand pickup, for example? Thank you.

The additional payments, yes, to be honest, it's quite nothing is classic, I would say. There is a price threshold, where if we reach a monthly payment or monthly calculation, the price of WCS reaches a certain level, then there is a multiplier effect with the $1 per barrel depending also on the production. So it's quite a classical CVR. What is good, from my point of view, is that we have five years for this. It’s 60 months, I would say, as you know, there is a good chance to get some of it. Just to let you know a calculation, if we would have a year like 2022, we would have reached the full $600 million. That's important.

Okay.

As I said, regarding the global energy market, the benefit today is our mix of operations. We've seen at the beginning of the quarter some short-term demand pick up. The pricing is clear, but today the market is better. It’s a good time to try to sign some long-term contracts, and we are back to a better percentage of Brent than in the last years. This is what we want to do on PNG LNG. As you know, we are benefiting from marketing PNG LNG in this type of environment; it’s a good timing for us. We had a delay, but we benefit from that. I think we are targeting to finalize some long-term sales contracts to cover our share of PNG LNG. On the other side, in the global market, Europe was softened compared to last year because the weather was mild in the winter. The storage is limited in capacity. So when the storage is full, putting more in becomes difficult. That creates a problem for Europe, as we don't have a very large capacity of underground storage. That's why you see that in the figures of TotalEnergies; there were fewer spot deals being done. There was another reason, which was due to strikes in France, where our terminal energy retail was shut down, but we were inaccessible for most of the month. If your question is about Chinese demand, it’s not too clear to me, to be honest. There is more than last year, but are we back to the 2021 levels of Chinese LNG demand? It’s a little premature to answer you positively. So we are in between, I would say, at this stage between 2022 and 2021 for this Asian demand. More appetite from many players remains, and it’s important to note that the Chinese players have signed some long-term contracts with Qatar. They are really willing to ensure security of supply. China imports 40% of its natural gas; it’s a good opportunity, and Qatar is benefiting from it, and we are working with them to secure long-term supply of natural gas. So it’s good for LNG.

Wonderful. Thank you.

The next question is from Biraj Borkhataria from RBC. Please go ahead.

Hi. Thanks for taking my questions. So two questions on the Upstream, please. The first one, just on Mozambique. I appreciate you're restarting there. On the other side, it seems like the operator was considering a second floating facility. I was just wondering from the Total point of view, is that something you've looked at or considered? And then the second question is, could you walk me through the plans for 2023 for both Namibia and Suriname? What are the next steps there heading towards development? Thank you.

No, I mean, honestly, when you have Mozambique LNG, which has huge reserves, the question for us is to develop a scheme where we can truly have the potential to take the most of these reserves. The floating LNG concept is not fully adapted; I think it was quite that, that is the first development, because it was part of the reservoir, which was not related to the big reservoir we want to develop. For us, in terms of capital allocation, if I want to allocate capital to LNG, I prefer to allocate it to projects with the potential for upside because you create much more value with additional points on a brownfield than on a greenfield project. The limitation for me on the floating LNG scheme is that you have the CapEx and then you cannot expand it; we cannot benefit from the additional reserves. There are enough projects in our portfolio not to allocate capital to floating LNG because we don’t see the upside. Regarding Namibia, we are currently drilling. In 2023, we have spent $300 million for three wells. Typically, we are using two rigs: three wells, three tests. So it's a pretty good year. We are making a second exploratory well, then we will do an appraisal of the first discovery and potentially another appraisal well either on the first or second discovery if it's a discovery. The plan is, with all this data, to have by the end of 2023 a good idea of what we have in hand and whether we can accelerate the time to market for the first discovery. In Suriname, the last appraisal well is just being drilled. The good news is that we are trying to develop an oil pool. The challenge in Suriname is that the oil-to-gas ratio is quite high, so we are keen to identify a low oil-to-gas ratio in order to enable efficient development. The first appraisal well for these two discoveries has been positive, leading to a pool of around 500 million barrels of oil. We are waiting for the last oil well results to reach 650 million peak barrels, then it will be time to move to development after the appraisal wells.

Thank you for the details.

The next question is from Michele della Vigna of Goldman Sachs. Please go ahead.

Patrick and Jean-Pierre, congratulations on the strong results despite the deteriorating macro. I really had one question. We've seen a major shift in the renewable power strategies of both oil companies, some of whom are deemphasizing that investment, but also from the utilities who are focusing more on financial delivery. I'm wondering whether you're seeing signs that this shift is starting to restore better profitability, especially in wind and solar, and perhaps opening up better opportunities for you as well?

I believe it's a bit too early to make that assessment. Currently, we are experiencing higher costs from the supply chain, and with rising interest rates, the industry is heavily leveraged. To regain profitability, it's necessary to increase prices, which is a positive development. For companies like ours, this will certainly create opportunities. We've noticed in some tenders that certain prices in offshore markets are excessively low and don't seem justified, which makes things challenging to address. However, we are observing higher prices in the negotiation of corporate power purchase agreements (PPAs) in the U.S., which is encouraging as people seem to be more realistic in their expectations. In corporate PPAs, we are working to recover some of our profitability by moving beyond just fixed-price agreements for 10 to 15 years. We are incorporating elements of merchant options to share both risks and rewards with customers, which aligns well with TotalEnergies' business model. Overall, I think the market is shifting towards prioritizing value over volume, similar to changes we've seen in the shale oil sector.

Thank you.

The next question is from Lydia Rainforth of Barclays. Please go ahead.

Thank you, and good afternoon. Two questions, if I could. I wanted to come back to the Suncor divestment proceeds. Given that you've kept the net investment number the same, is this effect giving you more acquisition capacity? I just wanted to check where we are on that. And then the second one was coming back to the Integrated Power business. Obviously, you've given us lots of helpful data that shows that out. It has been very volatile. So, when we're looking at the business, kind of what are the key things that you actually want us to think about from that side? Thanks.

On the first question, I would say yes and no. When we set our budget for 2023, we anticipated the spin-off. TotalEnergies planned to allocate approximately $2 billion of debt to the spin-off, which was included in our budget. This has changed over the month, but our guidance for capital expenditures remains between $16 billion and $18 billion. We definitely have room for both divestments and acquisitions. We expected higher proceeds from divestments this year, and we have already invested some money in acquisitions, including a deal in Abu Dhabi, as well as upcoming renewable projects, with the Qatar deal potentially being finalized this year. In 2023, we will have NFE delayed until January and possibly NFS as well. All of this is interconnected. Please do not consider the $4.5 billion of proceeds from Canada as additional; it is accounted for from that angle. The Board will also determine how to reward shareholders based on a commitment previously made. Regarding the second matter, yes, the situation is volatile. However, compared to 2022, the supply side was quite complex due to European governance that aimed to impose ceilings, which affected our accounts. When supply constraints occurred, it resulted in uneven quarter-to-quarter results last year. This year, my sense is that we are experiencing more stability, even though governments continue to implement various schemes. I anticipate more stability this year in the supply business than we had last year. The renewable sector is expanding, so I expect better performance in 2023 compared to 2022. The part that could be volatile is linked to the gas prices for plants, which last year ran at a very high rate. This first quarter was good, but not as high as last year due to the mild weather. We’ll see, moving forward to give you more insights on the matter, what Jean-Pierre and his teams have achieved. I think at the end of the press release, we restated the year 2021 and also the quarters of 2022 in this segment. It’s good to engage with my IR team, who will be happy to give you more insights or maybe not, just to support you in seeing what they can explain. I think the volatility will be less moving forward as we grow and develop the business. This is the case for this business segment. Almost $400 million is quite sizable; I think $317 million is quite large. The results are even larger than the Gas Marketing Services. After five years of development, it’s a good achievement and a source of growth. So, we look at that positively, and it’s a good source of cash flow for the future.

Okay. Thanks very much.

The next question is from Lucas Herrmann of Exane. Please go ahead.

Yes, thanks very much and thanks for the opportunity. Patrick, I wanted to ask you two questions on the LNG business. The first, there’s clearly been increasing talk in Europe of banning or doing something to stop Russian LNG imports into Europe. But I wonder whether you could make some observations around your understanding and interpretation and whether you are obliged to take volumes into Europe to regasify through the original contract anyway? The second question on LNG goes back to Mozambique, where you have had agreements signed for pretty much all of the offtake from Mozambique. How is that impacted, if at all, by pushouts, redoing feed, retendering, etc.? Thank you.

The Mozambique LNG contracts have not been affected until now. Those buyers are still maintaining all commitments, and we did not reach a date where we will commit to something. I think, my view is, you know that the buyers look to different consumers. We have a good contract, but that remains in the market. We are not affected at this stage by this delay on the LNG sales contracts. By the way, TotalEnergies, we only today have one of the contracts being discussed or renegotiated, but TotalEnergies took some volumes, and we stood ready to take more Mozambique LNG on our side. Regarding Russian imports, I want to emphasize that we have some long-term contracts, with part of these contracts having destination clauses specifically for Europe. Out of the 5 million tonnes of long-term contracts we committed to, at least three or four are designated for destinations near Europe. There is also a force majeure clause, which indicates that if a ban on LNG imports from Russia is enacted, we will utilize this clause and halt our imports from Russia to Europe. It appears to me, based on my readings, that European leaders are currently taking steps to facilitate future contracts. There is no consensus on this matter, as some countries express more concern than others. The current discussions, as I understand them, revolve around regulations that will be presented to the European Parliament, which may take time since sanctions require unanimous agreement and full sanctions are unlikely. There is no unity on this issue. However, if the discussion primarily aims at regulating the capacity of Russian players to transfer some regas capacity in Western Europe, then it is not a ban and will not significantly impact our position. We are monitoring the situation closely, and we do not hedge for these LNG contracts because we are well aware that we may have to stop importing.

I’m sorry, just to go back to Mozambique and the volumes that you've now taken in the portfolio, can you quantify that number?

At this stage, I think it's something like 0.7 million tonnes for TotalEnergies. But again, if some buyers tell us that they prefer to grow, we are ready to take more. We are open to that. Some Japanese buyers are also keen. Mozambique LNG isn't just a huge reserve; it’s well positioned, being directly on the Indian Ocean, to deliver to some Asian countries. It’s also attractive to Indian players. So, I'm not concerned about starting to sell this Mozambique LNG. The buyers have not exercised a close vis-a-vis the project.

Okay. Thank you.

The next question is from Matt Lofting of JPMorgan. Please go ahead.

Hi. Thanks for taking the questions. Two, if I could, please. First, on demand, Patrick, I think you talked LNG specifically earlier, but to the extent financial markets are putting something of a burden of proof on the resilience of global oil and energy demand more broadly here. Are there any areas or subsectors through Total's extensive global downstream business where you are seeing any early warning signs on the rate of change in demand manifesting? Secondly, could you share any sense of the strength of contribution from the oil and products trading business within the first quarter refining & chemicals reserve and how you see that trending moving forward?

Honestly, there are no early warning signs. What we observed in Europe was, of course, some energy savings and energy efficiency due to last year's high prices. So I would say Europe saved 15% of energy demand because the rates were high, but a lot of industries were saving energy voluntarily. Also, B2C customers enjoyed concessions where we shared profits from forward supplies with them in France. More than a million customers responded by saving an average of 15%. It's the same for manufacturing on the industry side. So, there was an impact on energy savings. We last, I think this was so truly a reaction to high prices; gas prices were almost $200 per barrel last year in Europe. So today, they have softened, and we begin to see some demand coming back. The demand is fundamental, and it’s not clear. Regarding the second question about shares, the surprise in the trading environment is the quick dilution of Russian diesel to Africa and South America; that was noticeable because these were the two importing markets, but also to the Middle East. Some producing countries prefer buying discounted diesel to safely serve coal without discounts. The issue we see here is that the diesel crack is softening clearly because of higher inventories, but Russian diesel is coming back quickly. The Chinese refineries are operating at full speed because they benefit from discounted Russian crude. This is a surprise in the market. I would say that in total, there are strong results in trading, but it’s clear that there have been observable trends.

Very good. Thank you.

The next question is from Kim Fustier of HSBC. Please go ahead.

Hi, good afternoon, and thank you for taking my question. I've got two, if I may. First, I appreciate that you don't comment on rumors, but I'm curious to hear any thoughts that you can share on the attractiveness of corporate upstream M&A and particularly for producing assets, given that Total has recently been linked to a certain private E&P company. I guess another way of asking that question is, hypothetically, what would you need to see in order to pull the trigger on, let's say, a $5 billion deal in the upstream? My second question is on Iraq. I just wondered if you could walk us through the updated Iraq integrated energy deal that was announced earlier this month. It seems to be a $10 billion headline investment, but just how is that CapEx going to be phased over the years?

On Iraq, yes, that was good news after my comments in London. I don't know if some people listened to my comments, but clearly, the government of Iraq confirmed the contract with no modifications at all. I would say, sanctity of contract when the government changed was, for me, fundamental. That was more than good news. Secondly, we reached an agreement about how the participating interest could be allocated to an Iraqi party. We have seen that we will invite partners from Qatar Energy to join us. That I think it's a good setup. We are finalizing all paperwork with the government. The $10 billion we will spend will be phased over around four years with ramp-up from production. Note that for M&A, I don't believe all rumors. People love using our name. We have proven able to make good deals when prices are right. So it's a combination of acquisition price and synergies. Of course, it’s important the deal makes sense and fits into our strategic portfolio. We'll see, but don’t believe all rumors.

The next question is from Amy Wong of Credit Suisse. Please go ahead.

Hi, good afternoon. And thanks for taking my questions. I have two, please. One of them is just continuing along the lines of M&A strategy. You've made quite a few chunky, pretty large acquisitions this quarter, an interesting mix across E&P, power, integrated gas. So can we take that as an indication of how you're thinking along those lines in the near future? As a follow-up to that is just tying that with your Scope 1, 2, and 3 emission targets you've talked about — how are those targets at all restricting the way you're looking at acquisitions at the moment to meet some of those 2025 or 2030 targets?

The second question is easy. There are no constraints of absolute value. We have commitments, particularly with hydrocarbons. Any project, whether it’s organic or through acquisition, must have a Scope 1 and 2 intensity of CO2 below the average for the company from 2019. Any M&A should improve the carbon intensity position. We can manage the overall CO2 budget with other projects. I think we’ve demonstrated our ability to have not only acquired assets like we are doing today but also exit some segments. By the way, the exit of Canadian wholesale gives space for carbon budget, but it’s clear this pertains more to developing our integrated power strategy. It’s essential. We continue looking into both M&A and organically developing all segments of the company, given good opportunities.

The next question is from Paul Cheng of Scotiabank. Please, go ahead.

Hi, thank you. Patrick, just if you don't mind, I want to go back to asset sales. Is that competitive or a gas and solar offer that you have put out, or is that clearly coming from other people? Have you looked at breaking up the asset and selling them individually?

No, it's clear. I mean, everything is in the statement. The activities are detailed there, Paul. We mentioned in our statement that we launched the spin-off. There was no bid overnight at all, and we received favorable unsolicited offers from several players, not just one. We only considered these offers in the last month when Suncor reached a level we felt was comfortable enough to present to the Board. We had an offer in the range of CAD 5.5 billion to CAD 6 billion. Additionally, I spent a week in Toronto recently to meet with some stock exchange management teams, so we are actively working on this. We had a good sense of what could be expected from one side—there are few alternatives, and our job is to push the price up.

Okay. And previously you commented on trading, but we haven't seen mention of it in the first quarter. Should we just assume trading results are more or less average, and nothing spectacular upside or downside?

You understand, when it’s spectacular, we warn you because in the statement. If we say nothing, that means it’s very good, but nothing spectacular.

The next question is from Henri Patricot of UBS. Please go ahead.

Thank you for taking my question. I have one more. Regarding biofuels, there have been some ambitious targets announced by the EU recently, including this week for South. Looking at your 2030 targets, you mentioned a 10% market share with 1.5 million tonnes. Could these figures increase both for the overall market size and your capacity, or are there too many limitations, such as those related to feedstocks?

Yes, you're right. With 10%, the volume was two million tonnes, which was actually a target of 2 million for the US with Europe on one side, the US on the other. There is a plan to develop various projects both in the US — where the high rate is providing an interested framework. We have plans in Europe like Grand Prix and others, and we’re looking at opportunities to develop in both markets. While it is attractive, the constraint is mainly on feedstocks, as you need to work with a circular economy model for waste or second-generation feedstocks. Our colleagues believe that achieving this target of around 2 million tonnes by 2030 is possible.

Thank you.

The next question is from Giacomo Romeo of Jefferies. Please go ahead.

Yes, thank you. First question is just trying to understand the rationale that led you to increase payout as a result of the Canadian divestments rather than committing to a fixed payout. The other question I have is more general — and it's around the emerging legislation in France where I'd like to hear your thoughts about tightening investment criteria for Article 9 projects and the explicit exclusion of investments in fossil fuels. Just trying to understand if you are involved in discussions with the government to make any changes here.

On the first question, I think it's—again, I explained why the Board. We planned the spin-off, and it's a commitment to our shareholders. We don't do the distribution in kind. We have a form of commitment. We can agree to meet shareholders through either buybacks or special dividends. That’s why it’s quite logical to translate this commitment into a positive increase for shareholders of at least 40%. That demonstrates the Board is really committed to returns to shareholders, like stated last year. The second question, I think this is a debate. I’m not sure that exclusions would make progress towards the transition, in particular, because I’m convinced players like TotalEnergies are well positioned to reallocate part of our cash flows to accelerate this transition. If people want to exclude, that’s for them. The only argument I ask is to separate companies. Those that are transitioning can be proved to be serious. I’m not a big fan of taxonomy, to be honest; it’s a classification. I've observed in some countries like Belgium that they are making caveats with financing. But the companies that are serious about the transition should be considered. That’s my take. I'm more in favor of a best-in-class philosophy instead of banning approaches. This could apply to actions without impacting them. If it’s not Article 9, it will become Article 8, or another classification. But there’s confusion in trying to regulate the transition through financial regulations, and that doesn't affect our strategy.

The next question is from Jason Gabelman of TD Cowen. Please go ahead.

Yes, hey, thanks for taking my questions. I wanted to go back to M&A for a moment. Last year at your Analyst Day, you talked about an interest in growing your US LNG integrated gas footprint. I’m wondering, as we try to figure out the use of proceeds from the oil sands asset sale, if that’s an area that looks attractive to you moving into upstream gas further into upstream gas in the US and/or partnering on LNG projects there? My second question is on Kazakhstan. Some news out of there regarding a potential lawsuit related to recouping costs from the Kashagan project, of which you have an interest. I was wondering if you could provide some comments around that lawsuit and potential liabilities arising from it? Thanks.

Regarding your second question, I have no further news beyond what you’ve learned. It seems that the government of Kazakhstan wants to reopen old discussions. It’s not the first time. The cost recovery in Kazakhstan, I think my feeling is that all the IOC five are quite united, and they will face this together, with the contract that will be respected by all parties. So that’s my comment on that. In your earlier question on the US and LNG, you should not consider that we are divesting assets to spend money tomorrow. We can also be patient in the market. I need to comment; I think I did last time during our last investor meeting. Our areas of interest—renewables, oil, LNG. We are looking for opportunities to create value across this global portfolio.

Thanks.

Gentlemen, there are no more questions registered at this time.

Okay. Thank you very much. Jean-Pierre gave you all the figures. The results were good. Thank you to all the teams. Thank you for your questions, and see you soon.

Ladies and gentlemen, this concludes the conference call. Thank you all for your participation. You may now disconnect.