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Ladies and gentlemen, welcome to TotalEnergies First Quarter 2024 Results Conference Call. [Operator Instructions] I must advise you that this conference is being recorded today, 26th of April, 2024. I now hand you over to Mr. Patrick Pouyanne, Chairman and CEO; and Jean-Pierre Sbraire, CFO, who will lead you through this call. Sir, please go ahead.
Good morning, and good afternoon, everyone, for this quarterly result session. I'm happy to welcome you together with Jean-Pierre, who will go through all the details of these good, strong results in first quarter 2024. But before to do it, I would like to highlight the way we have implemented our 2-pillar strategy during this quarter. And first, to celebrate this -- to recognize that the company celebrated its 100th year anniversary on March 28. We have been celebrating this event all through the company in 120 countries where we are present. We have company's ancestors who are really pioneers when they discovered oil in Iraq in 1927. And of course, it was the opportunity this anniversary to pay tribute to hundreds of thousands of pioneers who had followed them and who are, in fact, the past and the present employees of the company. And we have decided, by the way, by the signature of this anniversary, would be pioneers for 100 years. So -- but today, I would say with the same pioneer spirit, that we have decided in 2020 to embark in our journey in the energy transition. And moving to TotalEnergies into an integrated, multi-energy company with a clear and simple strategy anchored on 2 pillars. First, on oil and gas, mainly LNG, with the objective to continue producing hydrocarbons in a responsible way -- producing and growing hydrocarbons in a responsible way in order to answer the growing demand. And second, investing and developing integrated power energy for the future with objective to become net cash positive by 2028. So this first quarter 2024 is really -- 2024 is about advancing this strategy. I would say we are off to a great start on both pillars. We have achieved several milestones during this quarter that I would like to underline. First, on the oil upstream. We successfully started up some operated operations in Nigeria with Akpo West and the Tyra development in Denmark, both of which are additive to our overall corporate cash margins, as well as Mero 2 Brazil, which started at the beginning of the year. We continued to have success on the exploration appraisal front. We've recently finished a positive appraisal of the Venus oil discovery in Namibia, and we are now working towards FID targeting in 2025 for the FID. We have also captured in this prolific Orange Basin some new licenses of high interest on the South African side. We are making -- also it's important -- I told you it's a matter of execution of growth towards 2028. So we are also making good progress on some FIDs, which were planned for 2024. We will sanction in this month of May as the Cameia project in Angola, 80,000 barrel per day, operated by us with 40%. And we also plan in May to first -- to place the LLI orders for Suriname projects. And we confirm that we envisage to take the FID before year-end 2024 in Suriname. Finally, I would like to also comment that we've done an interesting deal recently in Congo to increase our interest into a giant deepwater field, Moho and divested at same time some very mature assets. That's for oil. On the LNG side, quite a big activity as well during the quarter. First, we begin to benefit from a low reverse trading below $2 per million BTU to see some opportunities to integrate -- to further integrate U.S. LNG value chain upstream with the first acquisitions from Lewis Energy Group's upstream natural gas assets in the Eagle Ford, operated by a strong operator, EOG. Earlier this week, we announced the FID of the Marsa LNG project in Oman, which is really setting a new low-carbon intensity standard for the next generation of LNG plants, 3 kilogram of CO2 per boe fully-electrified and the electricity coming from renewable sources. And it's a very good example of TotalEnergies deploying its integrated multi-energy model in the country. Thanks to that strategy, we reached a new scale in Oman combining LNG and renewables or 2 pillars. So it's a good example again of what we can achieve by moving on the 2 pillars.
On LNG, I would also insist that we continue to work with Asian buyers, which have some appetite for medium- and long-term contracts. And I would say all linked long-term contracts, which is important, of course. In particular, for example, this quarter, we signed a contract with Sembcorp in Singapore beginning 2027, just perfect when we have more production. And to cover it, I would say, or to hedge it with some oil-linked contracts. That's the target. And there will be more to come as our teams are quite active on the Asian front: China, Japan, Korea. So we are working. Of course, it's important. We have a strong LNG position, and we know we have some perspective to sign some oil-linked LNG contract is on part of our strategy. And lastly, I would also mention on the integrated gas part that we have -- we are acquiring the rule of SapuraOMV in Malaysia. This is a gas business related to a netback of LNG pricing with quite a good potential to increase. And in fact, it's quite -- it's a prolific -- Sarawak is a prolific gas region with some potential to grow in the future. That's why we're very interested to acquire these assets. Then moving to the second pillar, integrated power. We have again fourth time -- fourth quarter in a row an increasing adjusted net result income -- operating income, and Jean-Pierre will come back on it. As you noticed, we have implemented -- we are advanced in the implementation of the integrated strategy in Texas on the aircraft with the acquisition -- closing the acquisition of 1.5 gigawatt CCGTs. And -- but good, the demand is growing in Texas, data centers, AI. We are right on the good market there. And also in Germany, which is another key market for us. We closed the Kyon Energy acquisition, which is a battery storage developer. So you will see through the results that -- or the relevance of our strategic continues to be demonstrated quarter after quarter as a proof of concept that our differentiated model works, delivering strong results, which are fundamentals that allow us to grow our shareholder distribution in a sustainable way. We confirm again that we increased the interim dividend by 7% compared to last year, which I think will be appreciated by all our shareholders. And by the way, it's also this proof of concept starting to pay off as we kind of serve the positive evolution of the share price recently, which is on their view, in the view of the Board, a signal that the strategy is being increasingly recognized by the market as a good one or the right one and also evidenced by our leading total shareholder return. Finally, this value is not only shared with our shareholders, but also with the pioneers of TotalEnergies, and it's important for promoting employee shareholding plans. We are now in Europe the #1 company in terms of amount of capital owned by employees, more than EUR 11 billion, and a special grant of 100 shares to each -- or 100,000 employees has been decided by the Board to celebrate our 100th year anniversary. So I don't know if we have $100 billion of results, Jean-Pierre, but not yet. So then with that, I'll turn it over to Jean-Pierre, that was the transition, to go through the detailed financials this first quarter.
Yes. Thank you, and good morning, good afternoon, everyone. So as Patrick mentioned, our consistent strategy continued to deliver strong results, and we are well positioned to deliver on our '24 objectives of more energy, less emissions and growing cash flow. Brent prices were flat quarter-to-quarter, down only 1% to $83 per barrels and refining margins were strong, plus 36% quarter-to-quarter. Thus, European gas prices declined by 35%, reflecting a mild winter and high storage levels. In this context, TotalEnergies reported first quarter '24 adjusted net income of $5.1 billion, only down 2% sequentially. And cash flow from operations, excluding working cap, of $8.2 billion. Profitability remains strong with return on average capital employed of 16.5%. And we maintain discipline, confirming net investment guidance of $17 billion to $18 billion for '24. Importantly, we continue to extend our track record of attractive shareholder distribution with $2 billion of buybacks executing during the first quarter and nearly a 7% increase year-on-year of the first interim dividend for '24, which is now at 20% compared to pre-COVID level. Moving now to the business segment results and starting with hydrocarbons. Production was 2.46 million barrels of oil equivalent per day in the first quarter '24, stable quarter-to-quarter and up 1.2% excluding Canada. Production benefited from oil start-ups at Mero 2 in deep offshore Brazil and Akpo West in Nigeria, as well as 6% growth quarter-to-quarter in LNG production, which has offset the Canadian oil sands asset disposal that closed in the fourth quarter. Looking now forward. Production for Q2 '24 is expected to be between 2.4 million and 2.45 million barrels of oil equivalent per day and reflects planned maintenance that is partially compensated by ramp-ups of Mero 2 in Brazil and Tyra in Denmark. We reiterate full year '24 production guidance of 2.4 million, 2.5 million barrels of oil equivalent per day, which is 2% growth year-on-year, excluding Canada. Exploration and production reported adjusted net operating income of $2.6 billion and cash flow of $4.5 billion. Also, we continue our leadership as a low-cost producer with first quarter '24 upstream production cost at $4.6 per barrel. Moving now to Integrated LNG. Hydrocarbon production for LNG was strong during the first quarter, up 6% quarter-to-quarter, thanks to higher availability, mainly additives in Australia and Qatar Energy, LNG and 2 in Qatar, as well as the increased supply of LNG in Nigeria. However, first quarter LNG sales decreased by 9% quarter-to-quarter, primarily due to lower demand in Europe, given the mild winter and high inventories. Volumes also reflected partial downtime in Freeport LNG in the U.S. this quarter. Integrated LNG adjusted net operating income was $1.2 billion during the quarter, reflecting lower LNG prices sales, but also low volatility in the markets. Cash flow totaled $1.3 billion, impacted by the timing of dividend payments from some of our equity affiliates. Given the evolution of oil and gas prices in recent months and the lag effect on price formulas, we anticipate that TotalEnergies average LNG selling price should be between $9 and $10 per MBtu during in the second quarter '24. Now moving on our integrated power business segments. We are pleased to report that this business continues its profitable growth trajectory with adjusted net operating income growing sequentially for the fourth quarter in Europe as activity grows. Adjusted net operating income grew 16% quarter-to-quarter to more than $600 million and was supported by production growth in both renewable and flexible generation. So flexible generation, as Patrick mentioned, now includes the 1.5 gigawatt CCGT acquisition in Texas, which closed during the quarter and further enhanced our integrated position to provide clean firm power in the attractive and growing ERCOT markets.
Cash flow from Integrated Power was $692 million for the first quarter, on track to achieve our target of $2.53 billion of cash flow for the full year '24. Finally, return on average capital employed for the 12 months ending March '24 reached 10%.
Moving to Downstream. The refinery utilization rate for the first quarter of '24 was stable at close to 80% with the restart of SATORP in Saudi Arabia, following a planned turnaround during the fourth quarter '23, offsetting the impact of the unplanned shutdown at the Donges refinery in France. LNG contributed $960 million of adjusted net operating income in the first quarter of '24, up 52% quarter-over-quarter due to higher refining margins. Free cash flow from operating -- from operations excluding working cap evolutions of $1.3 billion also increased double digits quarter-to-quarter, although it was impacted by the timing effect in cash dividend payments from equity affiliates.
Looking forward now, we anticipate that the Q2 '24 refining utilization rates will increase to around 85% as the Donges refinery progressively restarts and because there are no major turnaround plans. On marketing and services, this quarter demonstrates the efficiency of the implementation of our value-over-volume selective strategy with cash flow from operations increasing by 5% year-on-year to $480 million in the first quarter of '24, despite the decrease in our sales of petroleum products. At the company level, we reported a working CapEx of $6 billion during the first quarter of '24. And the main components behind Tierra, first, the reversal of the exceptional working cap release of $2 billion in the first quarter of '23 we highlighted during our last earnings call. Secondly, $1.5 billion related to the effects of higher oil and petroleum product price on inventories at the end of the first quarter '24 compared to end of '23. And $2 billion of seasonal effects, $1 billion related to the seasonal effect on tax liabilities and an additional $1 billion related to the seasonal effects on gas and power distribution activities. Gearing at the company level increased to around 10% at the end of the first quarter compared to 5% at the end of last year. And the just described $6 billion working capital led to a 4% increase in gearing. And the decision we made given the interest rate environment to exercise the cool end of March on the EUR 1.5 billion IB bonds resulted in an additional 1% increase in gearing. Therefore, we expect gearing to structurally range around 7% to 8% as 2% to 3% of the current gearing related to seasonality impact on working cap at the end of the quarter. Our consistent and balanced strategy is paying off, as Patrick mentioned. And the first quarter has positioned us for continued success in '24. In this context, the Board of Directors of TotalEnergies decided the distribution of our first interim dividends of EUR 0.79 per share for the fiscal year of '24, representing an increase of close to 7% compared to '23 and authorized an additional $2 billion of share buybacks for the second quarter '24. And with that, I'll turn it over to Q&A.
[Operator Instructions] The first question is from Christopher Kuplent with Bank of America.
On net working capital and your net debt outlook. I think that removes already a few questions. But maybe a broader one, I wanted to just double check with you, Patrick, the political temperature and your assessment as we go into, not just AGM season, but the idea that petrol prices remain capped, there is talk about windfall taxes should they be expanded or not, whether there is a plan to tax buybacks what your thoughts are in terms of whether Europe has learned its lesson from the energy crisis that we're in or whether it's still a dangerous thing to make too much money as an oil and gas company. I'll leave it there for you to go in whichever direction you would like.
Okay. Thank you, Chris. For sure, European leaders, they don't want to have again a crisis on energy crisis on the price. You can see that in Europe, not only you have the German farmers, the French farmers, who are complaining as soon as you try to lift or to increase some taxes on the tractors, fuel, fuel prices, so it's not a good idea, but very clear. We see, by the way, a global political temperature where a lot of people are calling, I would say, for reform, not opposed, but less regulation linked to the green deal. And we could think that the next mandate of the European Commission might be more about execution than increasing targets and regulations. But the purpose for the price, obviously, European leaders can do nothing about it. It's more in the end. But I would say OPEC and OPEC+, which, by the way, today are probably countries are probably quite time with around $90 per barrel. We don't want as well to go back too high above $100 because they don't want to have some impact on customers. So clearly, the price was pushed up in the last month because of the crisis in the Middle East. But I don't see the fundamental of the market. As we all know, there is not much inflows of new supply in the market. The demand continue to grow 1%, 1.2%. So my view is that we have -- we can expect this price above $80, $80-plus in -- for the year, I would say. So we are fine. But having said that, you never know, we have observed some volatility. Windfall tax, no, not windfall tax. But there is a principle involved. We are in state of law and you have a territorial principle for taxes. That's very anchored and most of the constitution. For France, it's in 120 of 30 treaties with other countries. We tax the profits where we are -- which we delivered in the same country, and we cannot beat double tax for the same profit. That's a fundamental principle. So that's -- I'm not. So I don't think it will come. The point is that, of course, the European politicians are looking to what has been done in the U.S. on the 1% of tax on the buybacks. So honestly, this is a music which could cross the Atlantic this year. Having said that, honestly, it will not change the buyback policy of TotalEnergies because again, the buyback policy is sharing additional profits with our shareholders. And even if we have to pay 1% of EUR $8 billion, which makes $80 million. So I think it's -- we'll absorb it. But we'll not encourage them to do it, let's be clear. But that is something. The depth in Europe have increased so people can -- will look for some additional taxes. We should learn them if we can cut costs as well, but that's not fair, honestly the way to look at it. So globally, I mean, honestly, I think from this perspective, I think there is a -- you must make the difference between, I would say, all the statements during the European campaign and politicians and the reality of what is really executed.
The next question is from Irene Himona with Bernstein.
Question on maybe, if I may. You said, Patrick, you're working on an FID by year-end '25. Can you say what the size of resource will be for that FID? And can you share with us post your successful appraisal, what have you encountered in terms of reservoir thickness, the gas cut flow rates, et cetera?
Irene, you go to details, which we pay a lot of money to get this data, and I will not share them publicly or my colleagues because we still have quite exploration to be done. Now in fact, today, I will not answer by reserves, but I would answer. The reserves, it's more a question for us of dimension, the dimension of the production per barrel per day. And it's linked, in fact, like in Suriname, these type of FPSOs, they are the parameters, the key parameter will be the volume of gas, we need to recycle because there is a GOR. So we speak around, I would say, a development around between 150,000 barrels per day and 180,000. It has to be now firm up for there is more engineering studies. But all the data are there. We have made the campaign so business now the priority is to go to production, I would say. And then, of course, Namibia for us, not only that. Because our neighbor has just announced a new discovery in the Southern part. Southern part, we have the equivalent prospect on our side. So we'll drill it. So we are acquiring that seismic in order to make the acquisition. So for me, in Namibia, it's the first development, and we see others coming behind. But let's explore and as I said as well, we continue to acquire some acreage in particular on the Orange Basin. We have 2 good licenses -- prospective licenses on the South African side, which we might drill in 2025 according to the, I would say, to the process of authorization, which is prevailing in South Africa. So that's where we are. So it's a good news. We have -- we will be probably the first to produce oil in Namibia. That's the objective. So in this year, Namibia first development next year. That's a good news, I think.
And so to answer your technical questions. First, I don't have the data, so I cannot share the secret. Second, to be honest, no. Again, I think if we launch -- if we speak today about developments because data are good enough to make a profitable development, fitting with our criteria, which is, as you know, less than $20 per barrel of CapEx plus OpEx more, or less than $30 per barrel breakeven.
The next question is from Christyan Malek from JPMorgan.
Two questions. Just maybe just first on Namibia. I mean I was quite shocked how the scale of the resource in -- has been increased in as far as the GAAP statement. And I say that because I've never seen such a massive move in sort of -- in the way it's been presented.
But the question I have is, therefore, in the context of your execution plans and your discipline on spend and investments. How comfortable are you that as and when you do sanction the FID sort of if and when, that this will stay within your CapEx or envelope in terms of both cost per barrel and so on, given we've seen this movie before as far as Angola, when we had major discoveries and then sort of fast forward 2, 3 years, and it wasn't as easy to get the volume online for a number of reasons. So that's my first question. Even if you have line of sight on that from now, that would be good. And the second question is, there's a lot of debate around listings. And I sort of find that we can blame everything apart from the actual valuation and why the valuation is where it is relative to the U.S. But the question I have for you, Patrick, is electrons versus molecules. At what point do you potentially in a stronger macro environment, reemphasize your molecules and as far as either sort of rotating capital or investing more capital because as far as it sort of strikes me that the quantum of cash flows the U.S. majors can deliver versus Europeans. The main striking difference or the distinction is just the level of hydrocarbon as far as oil and the cash flows generated from that oil volume. And I know energy transition is a whole other debate. But just purely on quantum of cash flow, is there anything that would make you reconsider a reallocation of capital?
Okay. First, on the first question, I'm very comfortable to FID in Namibia, first FPSO and the second one. And it will be within the $18 billion of framework of capital per year. We can do it. It's profitable. It's not a problem. And obviously, our priority typically when we have good oil projects, we have fitting with your criteria, they will be sanctioned. There is no doubt to that. And that we never arbitrated against an oil project in the company, and that's why we have -- we expressed our strategy with 2 pillars. So first being oil and gas. The second one is, I mean, Integrated Power. But it's clear. So no, I'm not afraid to have 1, 2 or 3 developments to be done in Namibia. I think what is good for our company will be good for the shareholders. So if it's good projects, we will sanction them. And we have some space. And we have been very agile in the company to arbitrate. And I prefer to have more options in my portfolio, but a constant strategy to arbitrate and then to give priority to some of them. We just demonstrated it with Marsa LNG. We postponed P&G because the costs were too high. We have sanctioned Marsa LNG and 80% share. It's not big, but it's profitable because the CapEx were in line with our expectations. So this is the type of options.
And so I prefer to have too many options and to be selective on the most profitable ones because this will contribute to enhanced cash flow per barrel and so the cash flow per share, I would say. So that's fundamentally what we do.
So this one, I'm -- and if there is more to come, we will capture it, to be clear. By the way, you are right, but I never seen any way anybody in 25 years in the history to speak about 10 billion barrels with 1 well or 2 wells. But I mean, so but the media, the media aspect. So no, no side with 2 words, never, but we'll see. Then on the stock leasing. Listen, by the way, when you -- it's nice to mention 1 of the U.S. companies because I was looking to the results, which have just been announced. They are exactly the same as us. So maybe it's not a matter of molecules or electrons. It's maybe -- that's why we have -- I mentioned that we could. And as we have more and more U.S. shareholders thinking to have a clear listing in New York is obviously a move on which the Board asked me to look at it because it makes sense. So we'll see what we can organize, but it's going into the direction of growing U.S. shareholder base seems to be a nice -- a normal thinking from a Board of Directors independently, by the way, of the domiciliation of the company in Europe. That's clear, but that's the first one. I Don't think -- so the reallocation of capital, no, I don't consider it. I think we prefer to stick and to be consistent with the strategy. I think it has a value in the energy field to have a consistent strategy and to -- because we know it's a long-term industry and if you don't navigate and thinking. So the integrated power business, it continue to grow to deliver cash flows. We are on the road map to reach 12% and then to be net cash positive. So I don't see why I should suddenly reallocate capital because oil -- bowl of oil is higher. And again, it's a matter of -- I prefer to stick on our strategy to be selective in terms of projects, including hydrocarbon project, sticking on the -- and the low -- the cash breakeven of the company, I think it's fundamental. However, then suddenly, I think another race to volumes, which will not be positive. So I think it's -- we are generating as much dollars as one of the companies you mentioned. So we need to -- that's the reality. So it's not a question, of course, of a portfolio. It's a question fundamentally of finding -- going to the shareholders who are willing to buy energy companies. There are more -- yes?
I just meant over the medium term, there could be a bifurcation of cash flow. As their oil volumes grow and others don't, that's what I meant more in the context of if and when prices move higher and there's more volume in oil, is the market starting to look so backwards for that in terms of valuing cash flow? That's what I meant more in the medium.
Okay. No, honestly, it will be a good problem if we have more cash flows because the price of oil is going higher, but I will not make the mistake to think that yes, it's possible. The scenario you described is perfectly possible, Christyan. But at the same time, we should -- don't say again higher forever. That's not true. I mean we know that it's volatile. You know that when price of oil go up, then demands would low, and then exactly the typical thing. So we must not forget the sense of the history. Having said that, the best answer I tell you is that today, we have a very good -- or not a good, super strong oil and gas business, which allow us to deliver the best return on capital employed among the majors despite the fact, I don't like the word despite, but we are also investing in integrated power with a lower return. So that means the best question is if we have a portfolio and an efficient oil and gas operations. The proof again this week -- quarter is the cost per barrel -- OpEx per barrel is $4.6 per barrel. So that's -- we protect you if the barrel is higher, we'll make more cash flows for sure because we maintain and we continue to steer with breakeven. So -- and it's not only a matter of investment, it's also a matter of portfolio, quality of the portfolio.
The next question is from Lydia Rainforth with Barclays.
Two questions, if I could. One just a follow-up on the U.S. listing. Patrick, I think you said that the Board has asked you to look at the moving listing. How long would that process take? And ultimately, sort of what would stop you from doing it at this point? And then the second question was on the LNG business. You talked earlier about the, I guess, having flexibility within the portfolio. I'm just wondering if you could talk us through what your outlook is at the moment on the LNG market? Because obviously, we've had some projects that have been delayed because of higher costs, but others that are coming in that are very competitive. So just your perspective on that market.
Okay. On the first one, to be clear, there was a discussion of the Board -- with the Board, clearly, on the matter of U.S. listing. We all agreed that we have to seriously look at it. And so we are working on it together with Jean-Pierre. And I plan to report to the Board by September, and then we'll see pragmatic way forward, and we'll come back to you. But we consider that and I had discussions, by the way, with a number of large shareholders in the U.S. about it. But today, in fact, we have ADR, which is not a real share. They come to buy shares on the Paris market. You have exchange rates. We have 2. And when I look to the behavior of the share during it every day. You have the Paris market, which is depicting the share until 3 p.m. And suddenly, you have a drop or a hype because New York is leading it. And by the way, the share at the closing in Paris is just the value in New York at 12 p.m. So all that is not -- and on the top of it, which is more important. Again, we have -- it's clear that in the energy and the oil and gas field, U.S. shareholders are buying the shares and European shareholders are not so buying the same way. So I think it's also a recognition to the growing part of the shareholding. And so we must look at it because again, the Board is keen to understand, why? If there is -- I'd say it's a way to fill the gap that we see if we can get easily access to shares to U.S. shareholders. So that's where we are, and we'll keep you aware, don't worry, but I think it was time to -- the right time to mention it to our investors. On the LNG, the LNG, I will tell you, I'm positive for '25, '26 because you will not see much new capacities. Of course, like you and all of us, we are not naive. We observed from '27. I've not mentioned '26 because some projects will be delayed. I'm sure it's a big project. You will see new capacities coming on stream from the U.S. and from Qatar. So this will have an impact on some of the market. That's clear. But '25, '26, the price would -- could be tension since some of the plants, again, could have some difficulties, that's possible. After that, okay, that will be good for the demand, it will rebound. So what we are trying -- what we are doing together with the LNG teams is to sign some oil-related medium-term contract because the view that we have on this business is that the oil might remain like Christyan's question suggested it, it might remain stronger. So that's what we can do. And again, by the way, I'm not afraid because generally, and it was very well demonstrated by one of our peers, when you have some low cycle in LNG, they are not very long because generally, the demand is very reactive. You have countries, clearly we've seen it this year in 2023. You've seen more China buyers coming back to the market at $8, $9, $10. Under $10, you see China. And you will see if it go up into $9, you will see India as well coming. So I think it's positive for the demand. So -- and that would be, by the way, something important in this business because somewhere with the events of '22, customers are a little shy. There is energy, which went to the roof. That's why, by the way, they are also interested themselves to sign more oil-related contract base because basically, more stability in that oil pricing, but in the gas market, which has been very volatile. So I think -- so again, maybe a lower price. Another comment on it because sometimes I'm surprised by some analysis, which are reported. LNG, one of the interest of LNG, like you've seen in the results of total energies when the price of gas is going down in Europe, we have some amortizer in the LNG pricing formula. It's not -- we are not a European gas seller, I would say. And so the impacts on our revenues, cash flows and results are much lower because the formula LNG are amortizing this for them. So again, we are -- I'm not worried. I continue to believe that it's a good business to invest because it's a growing demand, because we need gas and energy to produce -- to complement the intermittency of electricity. There is a primatization demand when -- in the middle class in Asia. So all that is driving, I would say, electricity demand. part might be covered by coal and renewables, but part also with gas. And you know a country like India is very interesting. They are building a real gas infrastructure with big clients around the country. City gas is being developed. And so it's a reality we are investing, by the way, in this business there. It's a reality. And I think that -- so a lower price during 2, 3 years might -- will be -- would give a proof to that demand. And when the demand is installed, it's difficult to stop because when gas becomes your fuel for your house. So that's the perspective I see. But again, we are active in order to, I would say, edge not edge is not the right way, but to sign some medium-term contracts with oil-related terms.
The next question is from Martijn Rats with Morgan Stanley.
When oil prices are referred to as relatively stable, I find that a very sort of very interesting comment. But anyway, I have 2 questions that I wanted to ask. The first is a relatively simple one on the buyback and oil prices. We started the year, of course, with EUR 2 billion a quarter in buybacks. But I think it's fair to say that oil prices have been surprising to the upside so far this year. So I was wondering if there is some move in the quarterly buyback perhaps later this year, if this oil price sticks and under what conditions we might see sort of their -- the quarterly buyback much higher? I was hoping you could say a few words on what the prospect of that sort of might be?
And then the other one is about the SapuraOMV sort of acquisition. You bought 100% in sort of 2 tranches. I know it's not as exciting as Namibia perhaps, but it's not entirely small I was wondering if you could say a few words about the rationale of that transaction, what the attractions of the assets are, how it fits in the overall picture.
Good. No, it's not small. It's a good deal. We don't see -- even if we don't make a lot of noise, even I prefer to pick some good assets, which fits with the strategy, with growth potential. We don't really think it's small because, in fact, it's giving us with Sapura the lead -- an operating position in Malaysia. We see that as many advantages. In fact, we have a strong bond of Petronas. Malaysia is a very -- in fact, it's still a prolific basin, several gas basins, prolific ones. It's an opportunity to have a material position, 50,000 barrels per day, I think. So it's material. We can dedicate people. We see there beyond these licenses more to be done. So I cannot -- there is a potential to expand in the gas business. This is a business which related and which is priced as a netback from LNG. So you have different formulas. So it's part of also the rest of this business. You have some upside, and you can correlate it. And it's also a way get to strengthen the links with Petronas, Malaysia is an interesting location as well for other activities like in particular, CO2 storage for Asian buyers. So it's -- there are some -- a lot of Japanese companies are looking to that. So we see -- and again, I think for a company of our size, Elo is now in Asia, a South of Asia strategy. I think more fit in Asia is important for our future. This is where the demand will come. And Malaysia is an interesting country. We have also some LNG business. So this was a good opportunity. Again, a material one because what I don't want is to move from a small asset. So this one was -- so we were to have materiality by making all this transaction together. On the buyback, okay, I just want -- in fact, you know the answer by asking the question, Martijn, I think. When we stated in the press release of the -- in February, just reading it, with EUR 2 billion of share buyback in the first quarter of '21, which will remain the base level for quarterly buybacks in the current environment. I think the current environment in February were more or less $79, $80 per barrel. We continue on this basis, but it's quite clear we have been clear about the cash allocation framework we follow. Further dividend. The CapEx where we are, and we don't intend to extend them. And we said that we use share buyback to -- if we have more cash flows to share it with shareholders. So again, it was premature this quarter because we have only seen $90 for 1 month, so I will not conclude, but the $90 will remain for the year. I know that when I was making some roadshows in London, people were speaking to me about $100. But in the meantime, it was at $95. It went down to $88 or $89, So it's volatile. To be clear, it's clear that in our minds that if we have more cash than the base case, then we'll look to share it full share buybacks with some shareholders. But we don't have a mathematical formula to give you, so you have to guess. And again, it's a monitoring. We'll see what will be the second quarter. And I expect some decision probably middle of the year or September by the Board, when we'll have a better visibility of what could be the execution of the year. We have a good balance sheet. So we can -- we will not wait the end of the year to announce to you what we'll do. But again, let's look to what is the reality of the market. Because at the same time, oil price is better, gas price was a little lower than anticipated at the beginning of the year even if it's going up in the last weeks to more $90 in Europe, and the spread with the U.S. because NLP is going down at 1.5 is also a good -- important indicator for us between TTF and Repsol. That's a good signal. So again, we will follow what we say to our investors and shareholders. I remind you as well that we said that we want to distribute more than the payout for more 40%. This quarter it's at 46%, I think. So we are on the way to -- not to disappoint you, but as it's like the strategy, we are consistent and we go step by step. And when we are in a position to take decision, we'll take them.
The next question is from Lucas Herrmann with BNP Paribas.
Interesting comments throughout, Patrick. Amazing, isn't it? We all focus on oil now and have moved on a little bit. But I just wanted to, on the subject of FIDs, I wondered if you could talk a little bit about the offshore wind business and just how things have progressed for you over the last 6 to 12 months around costs, and what your thoughts are now on the timing of decisions Germany, U.K., possibly North Asia where you have opportunity. So just to give us some idea of, okay, I know what I'm doing on Namibia or Suriname, but what am I thinking around the allocation of capital to wind and time line?
Okay. I will be transparent. There is no way. It's clear that we had the experience recently in New York where -- and in fact, it's an issue. When you are in some markets, which are more regulated or I would say, more depending on some fiscal incentives. Suddenly, everybody wants to take the incentive for himself. But if the supplier is increasing the price of his turbine, because you want to capture the ITC, then we don't have it and then we cannot make the project. So it's a chicken and egg story. But we are not condemned to develop projects if they are too costly. I'm very -- I'm CapEx driven, and you know me for a long now. We have just recently said that on P&G, we are able to delay because the CapEx was there and going to new contractors. And on offshore wind, obviously, will be the same position. Because it's clear that this energy is more expensive than onshore wind or solar. And in our Integrated Power strategy, it has to find its place in a merchant way. So we have to be able to make money, merchant pricing as well. So if it's too costly and that is going out of what could be expected as a merchant pricing for electricity, then why should we do it? So we are working on it. It's -- there is no rush. We will not be led by, I don't know, which planning by 2030 target. The 2030 target for TotalEnergies can be filled with plenty of onshore possibilities. We'll have some offshore projects because we have some in the portfolio, which are good, on which we will give the priority. We have created many options. And what we were discussing between us with Stefan was, okay, if we need to run all these opportunities and to do the best ones and not necessarily all of them. So again, you have some heating there. But either we can have some cold weather on all this value chain. Otherwise, we will wait and see. We are at the position. But we work. We work on that. Last comment, I would say, for me, offshore wind is an energy for, again -- and you have to look carefully to what will be the electricity market prices. It's an energy where for markets, where the energy -- electricity price will remain high. It's not -- so you cannot deploy it everywhere. But Germany is a good fit. U.K. is potentially a good fit as well. And New York will see again, as we can obtain or not the right conditions to develop it. So we are monitoring it. But in our capacity of Integrated Power, it should represent something like 10% by 2030. So it's not a core of the growth. And so if the 10% are only 7 or 8, I don't care. No, basically priority is profitability -- a profitable growth. And so we will go and review this project one by one and if costs are rocketing, it's better to wait and see and to allocate our capital to another project.
The next question is from Biraj Borkhataria with Bank of Canada.
The first one is on LNG. There's been on and off news flow around potential EU sanctions on Russian LNG. Now I'm just wondering what this would mean for your -- the offtake at Yamal? In particular, would you be able to divert the cargoes and sell them elsewhere? Or would you have to declare force majeure? And then the second question is on hydrogen. So late last year, you announced a call for tender for across your refineries. And I don't think we've seen anything since I was wondering if you could provide any insight on the response from the industry and what you're seeing there?
Okay. I know you like Russia, Biraj, very much. To be clear, there is no, for total, if you -- I will tell you, if EU sanctions Yamal LNG, the price of LNG will go up quickly. And globally, our portfolio will benefit of it. So I'm not at all -- it's a positive if there were sanctions, not a negative because the cash from Yamal is quite limited contrary to what you might all think. First, we don't receive dividends from Yamal LNG in -- since '23. Second, the LNG business, because I remind you that because of the risk of sanction, we decided not to hedge the volumes of Yamal. That means that this year, we have sold Yamal in Europe at TTF price, and we buy it at a Brent basis. That means that it's not a very profitable operation given this year contract. So honestly, it's not a point.
So yes, if there are sanctions on Yamal by Europe or by EU, we will have to exercise force majeure for sure on some of the contracts. There's 2 contracts, 1 in for Europe, which we can exercise. There is 1 for Asia on which we'll have to look more carefully to the close. So this is where we are. And -- but my view to share with you, Biraj, I don't think because the European leaders understand that there are gas security of supply to they rely on the LNG. And they don't want again to see a crisis in Europe until '27.
And what I understand is that they might have some ideas, but from '27, not before. So we'll see. Again, for TotalEnergies, it's neutral. It's even a plus if there were some sanctions. So maybe people should think I'm a little provocative. But in fact, that's a reality. When I look to these projects, and it's not billions of dollars in cash flows. It's more a few hundreds of million dollars, which we can absorb easily, which have already been largely absorbed since 2022 in the company by other projects. On the second one, no, I would like you to follow more carefully. We gave you some indications in February on hydrogen. We told you that we received a lot of offers, more than 50 different offers to our tender. We have been offered 5 million tonnes, and we are targeting 500,000 tonnes per year. So then all the maturity of all these projects are not the same. We are working on them. I'm quite optimistic, to be clear, that we'll get what we are targeting. It's important for us because these 500,000 tonnes will allow us to decrease CO2 emissions by 5 million tonnes, 5 million tonnes of emissions, we have this year 38 million tonnes. So it's quite sensible on the road map. And again, within the European ETS framework and the famous Red Sea, we can do it, I would say, in terms of neutrality compared to paying the taxes or eliminating emissions and getting some green hydrogen. So really, it's quite attractive. We are, in fact, becoming an anchor customer for some players, in particular, in Antwerp or Rotterdam. And even Rhina in Germany, quite a long, strong interest. So -- and we could benefit from being a first mover there. Because again, they are as people, our projects are willing to develop the projects, thanks to such a 15-year contract that we could offer. So we'll come back to you when we have clarity. There are different tenders, a lot of discussions. But I think before this year-end, we'll be able to come back to you with news, but I prefer the teams to work than giving more indications. But that's -- we are -- I'm convinced that we'll have the -- we'll be able to execute the road map as planned.
The next question is from Michele Della Vigna with Goldman Sachs.
Congratulations on the strong capital discipline and the ongoing upgrading of the portfolio. I think you mentioned P&G, that's definitely a great example where cost inflation has led you to rethink or at least delay the project. I was wondering which other projects in your portfolio you think should be delayed or perhaps reengineered a bit following some of the recent cost inflation. Mozambique is certainly 1 where it feels like some of the bids have come back a little bit on the high side. And my second question is -- goes back to the idea that you floated off a U.S. primary listing. Clearly, the big aim there is to be included in one of the major indices, like the S&P 500 which has so much passive and semi-passive following. I was wondering if you've had any discussions there and if you think it's actually something doable to be included in that index while being remaining headquartered in Europe.
Actually you know the answer to the second question. And you know that you cannot to be S&P 500. They are not initiated in the U.S., that's all. So we don't intend, that's why we speak about primary listing. But again, when I see -- when we discuss with U.S. shareholders, being for them having access directly to your shares in New York would be a plus compared to going through this ADR or to the Paris market to buy shares. I think that's what we think about it. We see clearly more appetite on the North American site for energy companies, oil and gas companies was in Europe. So it's -- we are studying what could be, again, to facilitate their appetite by offering them easier access to share that's the idea. But the index might be abused, but it's not in the agenda to be clear, because we don't speak about the initiation, we speak about primary listing. That's earned. On the first one, no, honestly, on Mozambique, we don't face at all. I know one of my colleague wants to float that idea, but it's not true. I mentioned that few months ago that we were discussing with contractors on Mozambique because they raised their costs. We had good discussion with them. So the good news that I can confirm today is that in fact, we are back to -- we are on the good contracts with all of them. We realigned all the contractors because their interest is that we can execute the contract -- project. The interest is not to force us to re-tender or redesign, or I don't know which [indiscernible]. So we have a good concept, strong concept, resilient one. So we work with all of them. And today, we have contracts which have been initial to restart the project. But we have over dimension in that project. And again, on the security side, I would say there have been a lot of things. The security in Northern, the Cabo Delgado is okay. There is no incidents, no events. It's well controlled. We will meet -- I will meet soon, President Nyusi from Mozambique to review it with himself. And so I would say on the southern part of Cabo Delgado, it's quite far from where we are. There have been some incidents. But there again, they are redeploying some forces. And by the way, again, that part is first, I would say people are asking me, will you lift the force majeure. But the first thing to be done by the State of Mozambique, which is in charge of the sovereignty and security, to tell us if we could lift it before I decide. Let's do it in the right order. I would say don't try to ask privately owned companies to decide about something which is not fully in our hand, security of that vision. It's the first duty, it is the duty of the State of Mozambique, and we are working with them. So I would say we are -- so it's not a matter of cost, this one. It's more a matter of having the right conditions to lift the force majeure and to move on progressively, probably because it has to be done. To restart, we'll try -- we have to -- want to -- remobilizing this stuff will take time. So -- but it's not a cost. So, yes, P&G was, of course, disciplined, frankly, and it's not there is not really a redesign. It's more, I think we made as we tried to explain, I will tell you is limited to our traditional engineering firms, partners, Western one. I think what is new is that Western contractors have not so much appetite for many. It's like us. It's value of a volume. So we have a lot of -- plenty of projects in the U.S. probably easier to execute. And so what we think is that and we have begun to work with some Asian engineering firms, which are able to -- which are also able to deliver upstream -- good upstream projects, and we observe it. In Uganda, most of the contractors who are working in Uganda, half of them are coming from Asian countries and the execution is very smooth. And they respect the cost budget. So we are happy with them. So I think it's more -- we went to the traditional players. We want to open the tender. It will take time. And I'm optimistic that we can put this project back on track. But again, as I answered before, within our portfolio, we have many options. And that's good to have many options.
No, we are not discussing a lot of Marsa LNG. We have it. We introduced it. We know we might have another option, which is called '24 in Rio Grande LNG projects, which might be more efficient than ever. So I prefer to have more option and then to organize the planning and to be able to resist to cost increase to keep the discipline. While we will be able, despite this, to deliver the LNG growth we anticipate for 2028. So that's where we are. And again, we'll monitor the project one by one. And we'll see in Suriname, clearly, we have good costs. probably benefiting somewhere from synergies for some contractors with all the projects in Guyana. That's clear. So there is a synergy somewhere. And contractors who are working on Guyana, they propose to come with us in Suriname because for them, it's just next. And so they can capitalize on what they've done. We'll see in Namibia, which is a new province will be for me. The next, I would say, frontier from this perspective is how do we establish an efficient oil and gas industry in terms of servicing, et cetera, in Namibia.
The next question is from Kim Fustier with HSBC.
I've got 2 on LNG, please. First one is on U.S. LNG integration. I think your intention to extend into the upstream in U.S. gas has been well telegraphed for a while. And now you've made a first step with the Lewis Energy deal. Are you able to say roughly what proportion of your U.S. LNG offtake you'd like to cover in the medium term? And secondly, you mentioned good appetite for new oil-linked LNG contracts from Asian customers. Are you able to say or give any color on the slopes embedded in these new contracts? And also, what share of your contracted LNG sales is up for renegotiation over the next few years?
Okay. On the first one, I think I've been clear. We want to protect or to hedge, I would say, our cost of production by having some gas, some equity in gas production in the U.S. So it's around 1 Bcfe, which we could target more or less. But then again, no rush. Today, it's a right time, [indiscernible] is low. So we've seen some dry gas producers quite keen to open the doors, so we try to jump in. So it will not be a big acquisition, probably it will be a sum of assets and like we do, you observe probably prefer to do that than rushing to make big M&A, which are expensive, and so we have an opportunity to do it and dry gas window, Eagle Ford is perfectly located next to Rio Grande. That was one of the advantage of Rio Grande Energy. And you know there are not much appetite for these dry gas Eagle Ford basin. So there are opportunities there to deploy, to develop a position on the long term. That's what we target. And the cost of acquisition is quite good. It's quite good, in fact. In particular, today, because it's countercyclical. It's always what I think, to make good is when it comes to cyclical, and this is typically what we should do today. And -- but 1.5 or 2 is a good opportunity for us to advance. So if people are listening to me, they can come. Then on the LNG contracts, no, I cannot give you some commercial discussions on the slopes. It's protective. By the way, in most of my contracts, it's written that I cannot disclose it. So I cannot do that. If we sign it because it's fitting with our expectations, that's all what I can tell you. But no, I cannot do that. And we renegotiate contracts. In most of the long-term contracts, we have a close, which is, I would say, either 5 or 10 years. It depends. So I think it's more a 7 years than an average. So every year, I would say, as we have a large portfolio where we have 30 million tonnes of LNG contracts. We have 1/7, I would say, more or less of these volumes, we are being renegotiated. But a negotiation for us, it's also positive because the opportunity sometimes to have longer contracts. So it's a permanent. It's an exchange a bit in pricing and duration and volumes and optionalities. So in fact, when we are reopening this contract 5 years, there are many parameters, which are on the table. It's not just the pricing. And then you exchange okay, maybe more optionality to redirect some volumes in favor of the seller or of the buyer. So that's pointing to, I think, this negotiations. So I would say we will negotiate more or less. Again, you can take it as a whole at time [indiscernible] 30 million tonnes is what we are accustomed to do it. But it's also -- I was in China recently, we also discussed new contracts with the people. So it's a permanent give and take and that's part of this -- of commerce, I would say, it's commerce, it's a business, trade.
The next question is from Alastair Syme with Citi.
Can you talk about how much of your integrated power business earnings comes out of Spain? I think you've got a lot of the flexible generation combined cycle capacity. I'm really just interested in how current low Spanish power prices will eventually feed through into earnings if they'll be at any point?
And then my other question just back on Namibia. I mean I think in the press earlier in the week, you've got 10 down to suggest that it might hold similar potential to Guyana. You talked about 180,000 barrel a day development, which is something there's not a huge -- I'm just sort of interested in what makes you connect the dots to something like Guyana size to the basin?
But again, on the second point, there are 2 differences. One is each development. You know how much is the size of 1 development. And again, is dimensioned fundamentally by the facilities on the top side on the FPSO. Because including the GOR, you cannot oversize the gas handling facilities on the top side on the FPSO. And that governs generally quite a lot of oil production. So I told you, again, the question will be how many can we do it. And when I see my comments that I've done, is just what when I observe. It's not only -- it will not be like in Vienna when 1 JV will cover the full discoveries, it's not the case. So will not have, I would say, from these processes, the same efficiency to have 1 JV in charge of deploying the full resources while it is the case for our friends in Vienna. In Namibia, you have different operators who are discovering oil and hydrocarbons or sell, share, gulp. So that means, but when I'm adding what we know about it, I'm adding it. I think the perspective to have 6, 7 FPSOs or I don't know, is perfectly possible on the whole Orange Basin, and we're just at the beginning of the exploration including on our block, including I mentioned the Orange Basin on the South African side. So honestly, it will not be as efficient in terms of [indiscernible] because it's on 1 JV, but several JVs could cover, I mean, the potential of this area seems to be quite attractive. So again, you have different operators, different exploration programs to be executed. So that's the second part.
On the first one, Spain is -- around 2025, out of the 35 gigawatts, it will represent, I think, something I want 1 to 2 gigawatts. So it's not a major country. It's the one we started quickly because it was easy to have access to some solar projects next to France. But it appears -- yes, you're right. But it's quite -- it's not an easy country because a lot of competition comprise electricity is quite low. You have a lot of -- but again -- and you have some curtailment. So you have to be careful about the project. It was an early mover to renewable. So there is a lot of process there. But I would say in the plan, I would say, by 2030, we could target something like 4 gigawatts of 100, so 4%, 5%. So it's not -- in Europe, for me, it's not the #1 country to deploy in terms of Integrated Power. Germany has more interest and even, I would say, U.K. Because, again, for us, the driver will be where do we see the best combination between gas and renewables.
Okay. My question, which is really on today. I get a lot of your earnings Integrated Power coming out of a combined cycle in the gas in Spain.
Spain is quite low. You don't use much of this combined cycle today, honestly.
The next question is from Bertrand Hodee with Kepler Cheuvreux.
Yes. Two questions. The first one is on the U.S. offshore wind. There were recently your project attentive energy that was canceled. Can you share with us the reason of that cancellation? Because I understood there were -- there should have been a one-off, I would say, indexation close linked to the cost. And so I'm struggling to really understand. And do you still see a way forward in U.S. offshore wind? And then the second question is on -- is LNG related. You said in your introductory remarks that you've asked your team to sign long-term LNG contracts with Asian buyers in the coming years. Do you have a volume in mind?
The first question, in fact, Bertrand, I answered previously, I explained that. So one of the key contractor, which is making a lot of local content that certainly increase its costs, probably trying to push the limits, reach the limit. And in fact, it's, I would say, you have to wait and see the follow-up. But I cannot disclose it because again, we have some contracts with the city and the State of New York. So I prefer not to comment it. The state of New York is managing these, I mean, contracts. Their intent is yet to have the projects, and so they will probably, like they've done for the 2 old contracts with 2 competitors that will re-tender it in the conditions, which will allow us to launch a project. But let's -- you need to have a little more time and you will understand. On the second one, I would say, it's not -- I don't want to put a target officially today in front -- publicly with my teams. We know that we have some volumes available in our portfolio. So this volume might be marketed and it has to be marketed. When we took in Rio Grande the commitment of 5 million tonnes, we don't want to market all of it, but part of it clearly has to be marketed. It's clear. It's part of the strategy. We have -- our balance sheet is strong enough and we are trusting our teams enough to do it without having the contracts. But at the same time, it's good to deliver the contracts. So it's less than 5%, but it's not 0. So you find the objective. It's not like that. Again, at the end, it's a question of negotiation, discussion and having the right contracts in terms of value.
The next question is from Paul Cheng with Scotiabank.
Patrick, you did a small deal buying 20% of the RED. With your LNG exposure in the Gulf Coast, is that sufficient or that you are seeking additional asset in the U.S.?
Okay. Paul, I think I answered to Kim. No, it's not enough. It's the first one. It's an opportunity. It's a first volume. It's, I think, 100 million to 200 million square per day, and we target more 1 Bcfe. So there will be more to come. But the Eagle Ford, as I before, is the right -- is a good base in dry gas and Eagle Ford is a good basin for us.
Okay. And that your acquisition of Talos Low Carbon Solution, with that, how that changed the way that your approach or that your pace on investment in that area in the carbon story?
I think it's a complement. I have been obviously on CO2 storage that we were ready to develop a portfolio primarily in Europe because it's linked to our assets. In the U.S., we have some refineries and petrochemical assets. So we know that we'll have to store CO2. We had the opportunity to have access, as I would say, at cheap conditions to this nice -- 2 nice projects CO2 storage, 1 in Texas, very next to Port Arthur where we are located, which is operated by [indiscernible], very committed. So a good operator next to our facilities. So that's matching our target. And another one Louisiana, which is not very, but we intend to divest the second one. So again, we are driven fundamentally by securing some volumes on good projects for being able to store our own CO2. And if we have more capacity, we'll offer it to [indiscernible] in this way in the vicinity. So that's, I think, our strategy. And this one, the U.S., in the U.S., we have quite a vibrant CO2 economy. So it might be a nice place to have a good scheme to have, I would say, a low-cost CO2 storage.
Patrick, primarily that you said for lower your carbon emission or intensity of your own operation or that you look at it as a gateway for a third-party revenue source business?
It's for both.
The next question is from Henri Patricot with UBS.
Just 1 question on Integrated Power. You mentioned your strong first quarter in terms of cash flow from operations. If we analyze the first quarter, you already in the upper half of the guidance range for the year and you have more capacity coming on stream over the rest of the year. So I expect that you're more likely to be -- at the upper end of the $2.5 billion, $3 billion cash flow range, maybe even slightly higher. Is there something to have in mind when it comes to the first quarter cash flow, which we expect that we may not expect exactly that run rate through the year?
Thank you. No, I confirm the $2.5 billion to $3 billion, you can multiply by 4, you will find something like $2.7 billion, $2.8% billion. But I'm not sure. It's a permanent growth. I'm not sure it sometimes will not have the seasonality in this business. And don't forget it, you consume more in winter and sometimes in summer time, it depends on the region. Even if in Texas, it's a contrary. You have more cash in summer time with hot weather than in Europe. But yes, it's a seasonality aspect. So it's not -- so I confirm $2.5 billion to $3 billion. And if we can be next to $3 billion rather than next to $2.5 billion, we'll be happy.
The next question is from Jean-Luc Romain with CIC Market Solutions.
My question is related to CapEx in Integrated Power. You have had a strong start to the year. Should we expect the quarterly level of organic CapEx to continue about the same rest of 2024 or to still accelerate?
No. But I think you have something there and even during the year. Because as you know, we -- the guidelines we give you is the net CapEx. And you have, of course, with a growing portfolio, a growing part of farm downs, which will be booked probably more on the second half of the year than the first half. So you see more organic CapEx at the beginning and then we should land to what was the plan for the year. I think $5 billion, that's what we mentioned to you. So I don't anticipate a higher capital allocation to this segment. And by the way, we -- I mean, as it was said by Christyan, as we have quite a number of good oil projects, the idea is not, again, we've told you that we have reached the right percentage of allocation, 30%, 33%. So that's a guideline. And I'm sticking on this one for the years to come. It's part of -- we came to that level quicker than expected. But now it's also a matter of discipline. We have a lot of opportunities, but we are also selective. And it's important because again, it's not one, again the decrement of the others, but we execute the strategy. So it's more a timing effect like for the working capital rather than seasonal effects, but you will see it landing during the year. Okay?
Gentlemen, there are no more questions registered at this time.
Well, and thank you. Thank you to all of you. I think we were targeting to be on time in order for you to attend the Exxon call, if I understand, which is follow up in 5 or 10 minutes. So we respected it. Thank you for your attendance. And again, it's another quarter of strong delivery. Some people will say TotalEnergies is sometimes a little boring, but we are going for the good and always going up as a share. So I mean, I prefer to be in that situation, not a surprise, but to execute, to deliver, to be consistent. And I think it's probably one of the good. When you buy shares, you can trust that we will deliver. That's the message. Thank you.
Ladies and gentlemen, this concludes the conference call. Thank you for your participation. You may now disconnect.