Ladies and gentlemen, welcome to TotalEnergies' First Quarter 2025 Results Conference Call. I'll now hand over to Patrick Pouyanné, Chairman and CEO; and Jean-Pierre Sbraire, CFO, who will lead you through this call. Sir, please go ahead.

Good afternoon, everybody, or good morning for those connecting from the US. Before Jean-Pierre goes through the details of the first quarter results, I would like to make a few opening remarks on what appears to be a more challenging global environment today and how TotalEnergies intends to leverage our consistent strategy to deliver resilient results benefiting from our energy production growth and attractive shareholder returns. We have indeed entered a period of heightened macroeconomic and geopolitical uncertainty. This includes fragile negotiations surrounding the Ukrainian-Russian conflict and the fluid tariff policy enacted by the U.S., along with the decision by OPEC+ to unwind its voluntary production cuts. While the impacts of these developments are not yet fully appreciated, they may evolve over the coming months, creating uncertainties about oil demand and leading to increased volatility in the oil markets, which has been downward oriented in recent weeks, as well as a rise in costs for new projects in the U.S. due to tariff impacts. In this fluid landscape, TotalEnergies continues to flourish thanks to the unique strengths we have consistently built over the last 10 years. Our results are showing this to be true. First and foremost, we have been steadfast and have never wavered in our commitment to Oil & Gas. Over the past decade, we have developed one of the best low-cost emissions Oil & Gas portfolios, boasting more than 12 years of reserve life. This provides us with substantial leverage through strong and accretive growth, clearly distinguishing us from our peers. Delivering this growth is certainly one way we protect our future cash flows. We are fostering growth across two pillars, with the second pillar being electricity, which is not dependent on oil prices and adds an additional layer of resilience to our business model. As you will see later with Jean-Pierre, we delivered robust year-on-year production growth of nearly 4% in Oil & Gas and 18% in Electricity during this quarter, leading to an overall production growth of close to 5% for TotalEnergies. Simultaneously, we are in control of our costs. Our CapEx is managed well, with most of our contracts being based on lump-sum EPC contracts, securing the level of CapEx. On the OpEx side, we have maintained performance over the last year despite inflationary trends, with our cost per barrel or OpEx per barrel lower than $5, and again this quarter. Finally, our balance sheet remains strong, reinforcing our confidence in achieving our growth objectives for 2025 while keeping sugar costs under control. Given our confidence in our business model, the Board has decided to maintain attractive shareholder returns despite the uncertain environment. The Board has confirmed the first interim dividend at €0.85 per share, which is a 7.6% increase compared to 2024. In other terms, I would say it's even more than that, representing more than 10% at the current exchange rate of 1.14. As you know, dividends hold top priority in our capital allocation framework, and we intend to maintain and grow the dividend in future years, even during these uncertain times. Remember that we did not cut the dividend during the COVID period. After 12 consecutive quarters of €2 billion in share buybacks, the Board has once again announced share buybacks of up to €2 billion for the second quarter. Despite a softening price environment, with prices falling below $70 per barrel since the beginning of April, in light of an uncertain geopolitical and macroeconomic context, the Board will continue to monitor these buybacks quarterly. This approach aligns with the guidance we provided to the market last September to maintain a $2 billion buyback in reasonable market conditions. In conclusion, I believe we are well-equipped and well-prepared to navigate uncertain environments, as reflected in our Q1 results today. We remain focused on achieving our 2025 objectives and maintaining attractive shareholder returns. I will now turn over to Jean-Pierre, who will present the details of the first quarter results.

Thank you, Patrick. My first comment will address the price environment in the first quarter, which was generally similar to the fourth quarter of 2024. Brent was priced at $76 per barrel versus $75 in the first quarter. The European gas price (TTF) was $14.4 per MMBtu, an increase of 6% compared to Q4, while the average LNG price was $10 per MMBtu, a decrease of 4% compared to Q4. Additionally, the European refining margin remained weak, averaging $29 per tonne over the quarter. In this context, the company reported an adjusted net income of $4.2 billion and cash flow from operations (FFO) of $7 billion for the first quarter of 2025. Profitability remained robust, with a return on capital employed for the 12 months ending in March at 13.2%. Furthermore, TotalEnergies has a strong track record of attractive shareholder distributions, with $2 billion in buybacks executed during the first quarter, alongside the previously mentioned 7.6% year-on-year increase in the first interim dividend to €0.85 per share, now up 20% versus pre-COVID levels. Moving to the business segment results, let’s start with hydrocarbons. 2025 is off to a strong start. First-quarter production exceeded the high end of the guidance range at 2.56 million barrels per equivalent per day, depicting nearly 4% growth year-on-year. Production benefited from the continued ramp-up of projects in Brazil, the United States, Malaysia, as well as in Argentina and Denmark. Additionally, we have been successful in maintaining operating costs at a low level, recording $4.9 per barrel equivalent for the first quarter. Looking to the second quarter, production is expected to increase by 2% to 3% year-on-year, reflecting more planned maintenance compared to the first quarter, which had an impact of around 50,000 barrels per day. Given the strong 4% growth achieved in the first quarter, we reiterate our full-year 2025 production growth guidance of more than 3% compared to 2024. Next, in Exploration & Production, the company continues to execute well, with E&P reporting adjusted net operating income of $2.5 billion and cash flow of $4.3 billion in the first quarter, representing increases of 6% and 9% quarter-over-quarter, respectively. Cash flow benefited from new low-cost, low-emission point production, resulting in an additional $100 million of cash flow generated during the quarter. We anticipate additional accretion throughout the year, particularly from the Ballymore offshore field in the U.S., which achieved first oil earlier this month, and Mero-4 in Brazil, expected to be online in the third quarter, both of which will add high-margin barrels that will enhance cash flow. Concerning integrated LNG, LNG sales remained stable at 10.6 million tonnes, with integrated LNG achieving adjusted net operating income of $1.3 billion, reflecting a year-on-year increase of 6%, but a quarter-to-quarter decline of 10%, aligning with the average LNG price previously discussed. Cash flow of $1.2 billion was impacted by the timing of dividend payments from equity affiliates. LNG trading results were affected by an unexpected downturn in European markets due to the heightened uncertainty surrounding the Russia-Ukraine conflict. Forward European markets expect gas prices to remain elevated in the second quarter of 2025 amid ongoing inventory management in Europe. Given the pricing trends in oil and gas, TotalEnergies expects its average LNG selling price to be between $9 and $9.5 per MMBtu in the second quarter of 2025. For Integrated Power, adjusted net operating income in the first quarter was $500 million, with cash flow at $600 million. As anticipated, this quarter's results do not encompass any positive impact from farm-downs, which we expect later in the year. This timing issue drives a temporary decrease in our operational health assessment to 9% this quarter, which is expected to reverse when we make progress on the farm-downs. Looking ahead, the company is on track to meet its annual cash flow guidance. Additionally, we are advancing on multiple fronts in the Integrated Power segment, signing a premium power contract with SLB Electronics for 1.5 terawatt-hours over 15 years during the first quarter. We also deployed our differentiated Integrated Power model further in Germany with the launch of six new battery storage projects developed by Kyon, the company we acquired last year, as well as the closing of the acquisition of the renewables developer, VSB, earlier this month. Moving to downstream, amid weak refined margins, along with declining petrochemicals and biofuel margins in Europe, downstream produced adjusted net operating income of $0.5 billion and generated cash flow of $1.1 billion in the first quarter of 2025. Cash flow during the quarter was influenced by several factors, including the typical seasonality in the market and service businesses, in addition to the timing impact of dividend payments from equity affiliates in refining and chemicals. More broadly, the macroeconomic environment remains challenging, with refining, petrochemicals, and biofuel margins performing below planned cases, impacting cash flow by an estimated $150 million. Operationally, we faced some challenges at Donges refinery and a productive refinery, which negatively impacted cash flow by about $200 million. These issues at productive have been resolved, while work continues at Donges, where we have no systemic operational issues. Importantly, our performance remains strong at other sites, increasing the global refining utilization rate to 87% in the first quarter of 2025, compared to 82% in the previous year's first quarter. Moving to the company level, net investments totaled $4.9 billion during the first quarter, and we reiterate our full-year 2025 guidance in the range of $17 billion to $17.5 billion. In this quarter, we reported a seasonal working capital buildup of $4.4 billion, which is less than the $6 billion reported in the first quarter of 2024 and aligns with the $3.4 billion to $4.4 billion range reported in the first quarter of 2022-2023. The drivers of this quarter's working capital build include: a reversal of $1 million in exceptional working capital items reported in Q4 2024, a $2 billion seasonal effect from gas and power distribution activities in Europe, and a $1 billion impact from changes in business related to inventory and sales increases by the end of the quarter. Lastly, the balance sheet remains strong, with gearing at 14.3%. However, as mentioned earlier, the $4.4 billion working capital this quarter is subject to high seasonality. Excluding this seasonal impact, the normalized gearing would be 11%. Now, Patrick and I are available to answer your questions. Please open up the line.

Thank you. We will now begin the question-and-answer session. The first question is from Doug Leggate of Wolfe Research.

Good morning from Houston, Patrick and JP. Thank you for taking my question. The market's reaction to the debt move this quarter appears to be impacting your stock. I appreciate the explanation and the details you provided. However, it raises the question of how you view sustaining the 40% payout for share buybacks. If that requires relying on the balance sheet to support the capital program, what trade-offs are you willing to make regarding resilience? Is there a point at which the buyback or the payout would be in question? I have a follow-up as well.

The 40% cash flow for buyback is not in doubt; it’s clear guidance. We aim to exceed 40% by the end of the year, and I stand by that commitment. The buyback guidance we provided in September is to maintain a $2 billion buyback per quarter under reasonable market conditions. The Board has considered the current conditions we've been facing since the first quarter and early April, where oil prices ranged between $65 and $70, which we still view as reasonable market conditions. It's important to take a broader economic perspective rather than just focusing on specific price points. The global situation is uncertain due to fluctuating tariffs, but we might see the U.S. adopt a more reasonable stance in the future, which is something we must adapt to. The Board's response, much like during the COVID pandemic, is to recognize that the company’s fundamentals remain strong, and we are generating solid cash flow. Thus, there's no reason for an overreaction now. We need to remain observant, particularly with our operational expenditures. Therefore, maintaining that 40% cash flow distribution is a strong commitment. Last year, we even reached buybacks of around 50% or 40%. We expect that with our buybacks of $4 billion in the first two quarters and a firm commitment to dividends, we are looking at a total capital allocation of at least $12 billion, possibly more, which supports the 40% target. Additionally, we monitor our normalized gearing, which we discussed previously. As of February, we targeted a gearing of 12-13% by year-end, and currently, it stands at around 11%. If oil prices hover at $65, that might shift the gearing slightly to about 14%, but we’re confident in our growth fundamentals. Our focus is not solely on growth but also on managing our costs, and we’ve demonstrated strong capabilities in that regard. We want to convey a consistent message to our investors—TotalEnergies is a company that values consistency, particularly in unstable environments, rather than reacting impulsively. This has been our approach for the last decade, and the Board is unified in this strategy.

Patrick. My follow-up is related to that. You have built in capital flexibility to the plan, particularly around integrated power. You've talked about a $2 billion flex. What would it take for you in the macro environment to consider a spending reduction on your net capital guidance? I'll leave it there.

I believe I am clear on our plan. We have some flexibility, but currently, we cannot activate it. With oil prices at $65 per barrel, I am confident about our strategy for this arrangement. The real concern lies in the impact of tariffs on our supply chain, especially regarding renewable energy projects and battery projects in the US. If tariffs of 20% or 25% are imposed on imported solar panels, we might have to reconsider some decisions. For instance, we recently had a 600-megawatt project approved by the Executive Committee at the end of March, but after assessing the potential impact of tariffs, we decided to postpone the investment. Without tariffs, the project would have yielded a return around 12%, but with tariffs, it's projected to be less than 10%, prompting us to pause. We are not in a rush; our focus is on managing these potential fixed impacts. Nonetheless, I remain comfortable maintaining our guidance on capital expenditures. The question of flexibility becomes more critical if prices drop significantly, as we experienced during COVID when we saw prices fall below $50, prompting us to make adjustments. You may recall that we successfully saved $3 billion during that time. Currently, we have some flexibility, and Nicolas Terraz in Upstream has begun to ask his teams for clarification. To be specific, we might activate around $500 million in responses at this level. As for the company overall, I am confident in monitoring our situation in light of our balance sheet.

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

Thank you very much. I had two questions, if I may. First, I wanted to come back to your point, Patrick, on tariffs. It's pretty clear that they would materially impact the renewable business in the U.S. But I was wondering whether it could also affect some of the Oil & Gas projects and if there could be any issue with the LNG vessels globally, given that some of them are Chinese built. And then the second question, you may not have an answer, but I was wondering if you had a view on what happened to the Iberian power systems these days. And if there was anything in terms of structural change to the power systems with renewables that you think need to be addressed? Thank you.

On the tariffs, we have to be clear. As I said, I think this could have an impact on the new projects, which have yet to be sanctioned. Most of our projects already have real brands secured. I'm not expecting any impact from tariffs since all that was secured under strong EPC contracts. However, the difficulty might be more to ascertain which area we are talking about. There is a question of whether the tariff will eventually become 10% across the board, which could be absorbed in the U.S. projects. Remember, the Trump policy didn't only increase tariffs, but also implemented countermeasures to lower taxes. This component is also something we need to keep in mind – it's not solely a cost matter, it’s about profits in the end. So at this stage, my anxieties are mainly centered around monitoring a six-month uncertainty concerning tariffs and investment in the U.S. market. I believe we will gain more clarity in the U.S. investment environment by year-end as negotiations unfold and tariff determinations are finalized. Moreover, the lowering of taxes will also play a vital role in this process. Regarding LNG, the situation is indeed interesting. It's true that U.S. LNG exports without Chinese vessels could be limited. There has been continual discussion surrounding ID.2 to impose a special tax on all vessels not built in the U.S. Still, we are beginning to see more leeway in this matter. Energy policy discussions in the U.S. have been raised, and while long-term plans exist, we need to see how effectively the market can operate under this new structure. Always remember, we work on a global scale to ensure business interests prevail. As for the Iberian power system, I do not have specific insights right now. However, I will mention that we observed that in Germany, during a week of low wind, there were no major issues. A key lesson is that stability is achievable when grids exceed 30% renewable integration. Therefore, when adapting to such markets, grid investment and the inclusion of flexible assets becomes paramount. This is true not just for Iberia but for broadening the scope of renewables overall.

Thank you.

The next question is from Lydia Rainforth of Barclays.

Thank you and good afternoon to everybody. Patrick, if I just come back to the idea around the sustainability and affordability of the buy-back. Part of the reason that there is a shortfall is that the pace of growth that TotalEnergies is delivering. And I'm just wondering, could you give us an idea of the difference in CapEx that you would need just to keep the business flat versus delivering the growth you are. So really, what's the growth CapEx? And the reason I ask that is clearly, others and the fact are living slightly higher free cash flow, but actually growing less than TotalEnergies is? And then the second one, just to link against the balance sheet. It's clearly strong at the moment, but that weaker market always creates opportunities. So, how should we think about how else you would look to deploy the balance sheet potentially for acquisitions? Or put another way, are there any holes in the portfolio that you would like to fill? Thank you.

Great question, Lydia. Thank you. The first one, let me be clear. We are giving value through projects. We have some good projects that deliver accretive value. So the growth needs to be preserved for the medium and long-term industry. We need to develop it. Then, of course, again, if I have to cut CapEx, I remind you, I'm able to cut CapEx, but not on fundamental growth in Oil & Gas, where we will deliver accretive cash flows for our shareholders. I will not arbitrate on that. But I have ways to arbitrate if I need to invest less in EV charging. Don't worry, I will do it. So, we are spending money and this will be reviewed during our business plan exercise in June and July, as well as in our future investor meetings by October. We are prepared for this exercise. We will look at flexibility and define it to arbitrate. I will not arbitrarily reduce what is fundamental for future cash flow growth for our shareholders. You clearly have projects that have been sanctioned and that are in motion. They will be delivered, and the priority must be to maintain the budget and their timing rather than beginning to arbitrate at this moment. However, we also have enough room within our $17 billion budget to find $2 billion; it is not complex at all for a company like ours. If necessary, targeted savings will be made as we have done in the past— our track record over the last 10 years shows we can save effectively. The balance sheet: you know my position on it; it’s always good to be countercyclical. The primary question is whether we can create real value at a low purchase price. We need to think in terms of arbitration—of course, buybacks today also hold attractiveness. Given that share prices are low, it’s wise to buy back shares at such cheap prices. We will face a comparison between this option and any potentially attractive acquisitions. Today, we are not there: I don’t see cheap acquisitions, and we continue to divest some items and sell them at $70 per barrel. So, we'll have to consider the medium and long-term view to drive value creation and cash flows for shareholders.

Brilliant. Thank you.

The next question is from Biraj Borkhataria of RBC.

Hi. Thank you for taking my question and thank you for the comments. The first one is just a quick clarification on the way you and the Board look at the normalized gearing versus the number that we see. Is it just the seasonal factors that are in there in the adjustments? I think as Jean-Pierre talked about $3 billion of roughly seasonal factors, and I can't quite reconcile that with the 11% normalized gearing. And then the second question is just on the latest situation in Mozambique. Obviously, we're a few months on from the election, important project or you just wanted to update there. Thank you.

Let's leave Jean-Pierre to answer, but to be clear about the calculation; yes, we took up $3.4 billion. We informed you that $4.4 billion working capital buildup came with a $1 billion reversal of exceptional elements reported in Q4 of 2024. When you make the $3.4 million and subtract the $3.4 million, you arrive at 11%. Jean-Pierre, you can provide further clarity and the team can share more details, but it’s straightforward. We've observed the company and how it handles seasonal effects very well. In terms of Mozambique, we had good news with financing back on track, thanks to a U.S. decision. The shareholders have collectively decided to progress the project. We are still waiting for one or two pivotal answers, but in essence, it is now a bureaucracy aspect. The security situation in our industrial area remains stable and secure. We are coordinating with contractors to ensure their safety within the secured perimeter. In terms of another topic, we have addressed existing controversies surrounding our mine rights, whether or not they receive validity remains to be seen, yet we have consulted the National Commission of Human Rights to ensure a proper inquiry. The target remains to relaunch the project by mid-year.

Thank you.

The next question is from Irene Himona of Bernstein.

Thank you very much. Good afternoon. Regarding your adjusted gearing, it is clearly low at 11%, so a $2 billion quarterly buyback is not a problem. However, I am curious if there is a specific level for normalized gearing where the Board would reconsider the $2 billion quarterly buyback. Additionally, could you provide an update on the timeline for advancing the Namibia project towards a final investment decision? Thank you.

I think I've answered that previously. Let me reiterate: we argued at the beginning of the year that the Board was comfortable targeting gearing around 12% to 13% at $70 per barrel. At $65, we would be looking at something around 14%. By stating this, I mean that we’re reasonably comfortable at this level. It's not an issue we can pinpoint, but this is the range where we are comfortable using the balance sheet. Additionally, while not precise, I would say if it falls below $50, we would need to revisit it. We stress the importance of staying consistent rather than erratic in our development. Regarding Namibia, I was there just last week for the first time. We have a project for which we provided some information back in February. It's a matter of finding common ground with the authorities. We have about 750 million barrels of oil; it's quite a lot. However, reinjecting gas means we will require a longer license period. It's feasible but presents challenges—3,000 meters in water depth means capital expenditures will be higher, somewhere around $20 per barrel. I’ve indicated to the government that we need to protect ourselves against lower oil prices; hence the ongoing discussion for a proper balance. This visit was just my first, so I don’t expect immediate answers. Still, I sense a willingness from authorities to enhance the Oil & Gas industry in Namibia; it could serve as a significant first mover, albeit with logistics costs. Therefore, this dynamic must be evaluated.

Thank you.

The next question is from Giacomo Romeo of Jefferies.

Thank you. Two questions for me. I think your message on buybacks in the current macro environment is very clear. Just wanted to go back to what you showed in your slide in the CMD, where you were showing the Community CFFO below $50. In there, you give us a flex level of capital investments. And you would expect those levels to generate free cash flow above the dividend. So is there a minimum level of buyback in that macro environment that you think you'll be able to sustain? The second question I have for Patrick is on Argentina. We have seen some of your European peers taking early positions in LNG projects in Argentina. There have been some headlines suggesting you're looking to scale than your presence in the country. Just trying to get a bit of what your thinking around the investment prospects in the country and whether you think there is some attractiveness around the potential for Argentina to become an LNG exporter?

Yes. So first, you refer to a slide, which was slide number 53, according to my colleagues, which provided you with the answer, I believe. It indicated that at $50 per barrel, while executing disciplined capital investments, which were reduced by $2 billion compared to our global guidance, we would manage to cover dividends and still return some cash flow for buybacks. This means your question is addressed. I don’t believe buybacks would be reduced to zero at $50; that simply isn’t the objective. You also have to factor in the post-dividend breakeven, which remains below $50 at the end of this period, with guidance above 40% of cash flow from operations throughout entire cycles. This will support distributions to shareholders, which will be maintained even when oil prices are lower. On the other hand, Argentina: there are many active projects within LNG globally. We have more promising projects elsewhere, primarily in Qatar, the U.S., Mozambique, and Papua. Reflecting on current developments in Argentina, I’ve expressed that President Milei’s administration has made significant reforms, but historically, Argentina has been a challenging investment environment, which reflects in the two years of shareholder returns over the course of 25 years. Infrastructure investments in such an unstable currency exchange policy are currently not my priority. Importantly, we are directing focus toward monetizing Argentinian gas in Brazil and fostering those contracts. While I respect the activity happening in Argentina, it isn’t currently a top priority for TotalEnergies.

Thank you.

The next is from Matthew Lofting of JPMorgan.

Thanks for taking the question. Two, if I could, please. First, I just wanted to follow-up on the earlier comments on buybacks, payout ratios, and gearing. If I understood correctly, Patrick, what you said earlier, the Board, it sounds like views, April conditions as well as Q1 is within the bounds of reasonable and 50% to 55%, it for a sustained period is perhaps where you review as you were referencing earlier that the mid-cycle payout greater than 40%, when the Board thinks about 2026 and beyond. How mechanically and swiftly should investors expect TotalEnergies to revert to 40% plus as an underlying payout? And then secondly, I just wanted to ask you about working capital. The quarter-on-quarter fluctuations appear to have been quite substantial over the last 6, 12 months versus history, perhaps. So, I wondered if you could touch on some of the reasons behind that and the extent to which you expect that to continue, perhaps related to evolutions in the portfolio set up.

I want to clarify that I never indicated a limit on the payout, only provided two examples at 55%. This year, we are maintaining a payout of 65% to 70%, and I feel confident about this moving forward, without any concern about a price ceiling. The 40% is not a midpoint but a minimum; our goal is to exceed that in full cycles. This isn't merely a target or a strict rule, but rather an upper boundary. Last year, we achieved 50%, and the year before was similar, which provides us substantial flexibility, particularly with TotalEnergies' effective $8 billion dividend. In low cash flow scenarios, we can sustain this by generating around $20 billion in cash flow, allowing for buybacks as well. The Board is proactive in managing this to ensure shareholder satisfaction. Regarding working capital fluctuations, there are two main reasons. First, certain fiscal elements grow, which impacts working capital management and will show improved performance in the first quarter. Second, there's a seasonal pattern; energy consumption in Europe increases during winter, leading to higher demand and upstream working capital. Generally, people pay their energy bills in installments throughout the year but consume more during winter, resulting in seasonal billing at year-end. We can expect fluctuations of around $1 billion but anticipate stabilization by the year-end, a trend we have observed over the years.

Super. Thanks Patrick.

The next question is from Henri Patricot of UBS.

Yes. Thank you for the opportunity. Two questions from me, please. The first one, on the integrated power business, you mentioned that earnings are a bit lower this quarter because of the lack of farm downs. So I'm wondering whether that's something that's very much temporary? Or if you see actually some more challenges in agreeing on these farm downs, given the increased uncertainty around renewables, in particular in the U.S.? And then secondly, on the integrated LNG business and the guidance on FFO, you targeted earlier this year, $6 billion of cash flows. Looking at Q1 performance, it appears to be more like stable cash flow at $5 billion. So do you still see as that $6 billion target is achievable in 2025 in the current environment? Thank you.

First, it's really a question of timing on the farm downs. You will see our anticipation already in Q2 that we should have almost two quarters combined. Farm downs revenues generally represent more or less $17 million per piece of equipment. Annually, they total around $300 million, so 70%, 75% of which should flow in quarter. This time, there was no overlap from farm downs, but we have already one in Portugal that is about to close, generating what should have been done in the first quarter. We do not foresee significant hurdles; our strategies remain focused, and we have a dedicated team aiming to execute them. The second quarter results will exhibit higher returns from farm downs than originally planned. Now, regarding the LNG business: when I survey the guidance we presented in February, we are indeed targeting $6 billion in earnings. However, this comes with some variance across the board. We are more aligned with $5.5 billion to $6 billion presently, but we will continue moving forward. Our insights suggest that fundamentals in Q1 2025 were bullish but were unexpectedly thrown off balance by geopolitical events that impacted trading and demand. In fact, the outlook still holds a positive note.

Got it. Thank you.

The next question is from Martijn Rats of Morgan Stanley.

Hi, hello. I've also got two questions, if I may, which actually sort of just follow-up the question from Henri. I wanted to ask you about your thoughts on the true appetite that Europe might have for more Russian pipeline gas. There's been many contradictory comments and indicators. It's a real market concern, but clearly, you have spoken to many people. I was wondering what your impression is of how likely this is; say, within the time frame of 12 months? I mean like multiyear view, probably all things are possible, but on a 12-month view, how likely this is really? And then secondly, perhaps a bit of a technicality, but I want to ask about the guidance for LNG price realizations for the second quarter, down to $9 to $9.5 per MBtu. I would imagine that doesn't fully capture the impact of recent spot price declines given the lag built into the system. If you had to think about for the third quarter, how much would that incrementally fall assuming, say, oil prices stay at current levels. Would we see a drop below 9% to 8.5%, or 8%? Is that the trajectory that we should be thinking about?

I believe we need to be cautious right now because the geopolitical situation is complex, and reaching an agreement among the various parties isn't straightforward. Currently, I feel that the market might have overreacted to recent news. One positive aspect is the significant pressure in trade discussions between the U.S. and Europe to increase purchases of U.S. gas. This suggests that U.S.-produced LNG is a likely option to meet demand, and I sense a favorable inclination from European authorities towards accommodating the U.S., which bodes well for TotalEnergies. Our presence in the U.S.-European LNG market is robust. However, on a political front, there is discontent in Europe regarding the potential increase in Russian pipeline gas. The emerging coalition in Germany appears to oppose more Russian pipeline gas, as shown by their movements towards reducing fossil fuel dependence. The dialogue around European energy is evolving, focusing more on stability and energy security. At a recent conference in London, many leaders deliberated on supply security and the positive role of renewables, supported by U.S. LNG imports. In the upcoming year, I would be surprised to see significant quantities of Russian gas entering Europe since it may take time to resume, if at all. In terms of pricing, presenting figures of $9 to $9.5 per MMBtu reflects the spot price dynamics. With a long-term contract framework based on Brent, we incorporate a two-month lead time, simplifying the estimation of future prices based on current contracts. The spot market remains uncertain. Oil prices may fluctuate due to geopolitical factors that could influence prices at any time, so I prefer not to specify a strict price range for the third quarter, as predicting exact movements is challenging given the prevailing circumstances.

Let's all hope for that. Wonderful. Thank you.

The next question is from Lucas Herrmann of Exane BNP Paribas.

Yes, thanks very much. A couple of quick questions, if I might. The first, just going back to debt, but also balance sheet and what's been going on with currencies. In fact, maybe, Patrick, I should ask you more broadly on currency and impact. The question specifically was the debt that you hold a proportion of is euro-denominated. And the question is simply the impact that strengthening euro rate has had on dollar-reported debt last quarter. Additionally, if currencies remain strong, we should probably expect absolute debt to see a modest uptick as a consequence of currency moves. But maybe talk more broadly on the volatility we’ve seen in the dollar and how it relates to your business? And secondly, just a quick question on cash flow and associate dividends. J.P., where should we expect the net associate contribution to end up for the year as a whole? Clearly, there has been $400 million of profit booked in the first quarter, which was not covered by dividends. But how do you see things for the year as a whole? What should we be modeling? Thank you very much.

Sorry, Lucas, I missed the second question. What was the $400 million related to?

I was just looking at the associate move, the difference between dividends received and cash flow for the year.

Thank you for your questions, Lucas, and your support. Regarding debt, I'll let Jean-Pierre respond. Concerning foreign exchange, the dollar-euro exchange rate doesn't have a significant impact. The only benefit comes from dividends paid in euros. When the dollar is at $1.15 or $1.14, the dividend burden decreases by 5%, potentially saving about $400 million. The effect on global cash flows is generally consistent across the board. While some businesses are impacted, the overall balance remains stable. A weaker U.S. dollar is advantageous for us, as it prevents our shareholders from facing substantial dividend increases. Moving on to equity cash flow, some equity partnerships operate on an annual rather than quarterly basis, resulting in dividends being paid at year-end. For instance, Nigeria LNG will distribute dividends in Q2, Q3, and a significant amount in Q4, but none in Q1. Our equity investments are not solely under our control, and it's suitable for joint ventures to manage these dividends effectively. I want to emphasize that our board members are committed to maximizing dividends. While the $400 million may vary with price changes, we aim to sustain our cash flow from these equity shares.

Not to confirm you, my debt is in dollars. Because even if I issue bonds in the euro market, given that my business is in dollars, I’ve swapped this bond into dollars. So my exposure to FX regarding debt is quite limited for that reason.

Okay. Thank you. That’s helpful.

The next question is from Paul Cheng of Scotiabank.

Thank you. Good morning, or good afternoon. Patrick, you guys signed the agreement with Egypt and Cyprus to export gas there. Can you give us some idea of what's the timeline? What's the next step and the size of the project? Thank you.

There was a significant decrease, and since Iana is the operator, Claudio is better positioned to respond because the operator is accountable. We had a successful agreement in January in Cairo, which was a significant accomplishment as we developed a framework for transporting gas from Cyprus through existing infrastructure to one of the LNG plants. We needed to secure a political agreement between the countries, and I’m pleased to say that has been achieved. We are now ready to monetize the gas from Cyprus, which can be transported through a facility in Egypt. The next step is for ENI to make a final investment decision by 2026. Some technical roles are currently underway, and proper engineering plans are being established. For TotalEnergies, the agreement we signed was crucial to proceed with any capital expenditures or engineering tasks. We wanted to ensure a strong political agreement was in place before our teams began spending. I can assure you that engineering teams are eager to invest without securing commercial terms first, but we are working against that trend. We own 50% of the project, and progress is substantial. Since this project is not directly aligned with our 2030 growth plans, we are anticipating the start of gas deliveries as early as 2029.

Okay. Second question: the U.S. has a new rule under the Gulf of America that will not allow multi-zone tax. Is that a significant opportunity for TotalEnergies there?

Paul Cheng, I don't believe we have production in the Oncore project. The Oncore project is producing. Yes, Oncore is producing. We have some projects in Jack and Oncore. What can we actually do? I don't know. But you know again, yes. This will be welcomed if we can potentially have more opportunities. By the way, one of our objectives remains to prioritize exploration in the U.S. in the Gulf of Mexico. We believe there are significant opportunities to pursue. We don't want to be the operators ourselves, but we are actively engaging with other companies. Again, in terms of our long-term goals, we are investing more resources back into Gulf of Mexico exploration, such as our success with Oncore and Ballymore, and this is encouraging.

Thank you.

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

Yes, thank you very much. Just a quick one to follow-up on conversion, $7 billion in CFFO relative to your full-year guidance, that picked up was LNG and gas trading, the farm downs that are missing and associate dividends let us know if you can point other improvements for cash conversion later in the year. And the remaining question I had was, Patrick, regarding your appetite for more renewable growth. I thought it was quite important to see at the end of March, new or tighter, even tougher net zero targets. You are now competing against utilities that are buying back their shares and halting further growth of assets. So I wonder if you can comment on the competitive environment in this world leaving the tariff uncertainty for one moment out of the debate and just looking at your competitors in the low-carbon space.

Okay. $7 billion compared to your full year guidance, I would say the price environment for E&P has positively contributed more than anticipated for the full year. I remain ingrained in line with our guidance. I told you that there was around $1 billion from the cash trading, and we're targeting $5.5 billion to $6 billion that all integrated power, which I'm confident we will achieve. The refining and chemicals segment is more challenging, to be honest, but I saw good news this morning reflecting that European margins have jumped to about $50 per ton. So, we could see improved performance across the board if prices decline. We should capture the essence of that and drive profits upward. I have communicated that our results for the first quarter are in line with previous forecasts but it’s dynamic and could change. What remains our strength is the trading volume across our sectors, as we mentioned earlier.

Concerning renewable growth, we are committed to driving expansion in this sector, particularly in integrated power. I highlighted during my earlier comments that our focus not only amplifies our presence but also incorporates flexible assets, especially given the need for holistic product marketing to meet consumer demands. If the current challenges signify any desire for growth, be it through increased competition or regulatory shifts, our strategies remain clear. Renewables significantly enhance our profitability; our objectives are aligned with the market's demand trends. In light of recent developments in the renewable landscape amid the growing dependency on data centers and renewables—some sectors have shown demands rising towards integrated power. What’s crucial to my narrative is digestion within varying sectors that might help Solidify our competitive standing amidst the uncertainty.

Great. Thank you.

The next question is from Jason Gabelman of TD Cowen.

Thank you for taking my question. My first inquiry is regarding the integrated LNG business. It's challenging to identify the advantages from the SapuraOMV acquisition on a quarter-to-quarter basis. You've mentioned before that production correlates with global gas prices, and considering their current state, I would have anticipated an increase in earnings from that new production. Could you explain what impact this has had on earnings, especially if it’s potentially offset by lower trading in this quarter? Additionally, one of your major competitors highlighted this morning that the trading environment has become more challenging due to new macro risks the market is facing. Are you experiencing similar conditions in your oil and gas trading operations? And considering the ongoing tariff risks, does trading become more complicated? Thank you.

Honestly, the SapuraOMV acquisition is delivering results. However, I don't have those details available. You may review reports and easily reference prior periods and obtain comparative figures. Overall, the acquisition is contributing positively, and we are actively working on capitalizing on our position in Malaysia to expand our portfolio of assets. On trading, I acknowledge the comments regarding the current trickiness of the macro environment. Our traders face difficulties in the essence of tomorrow’s fundamentals, which may suddenly be attracted or reversed based on geopolitical messages. So, the trading environment is complex but manageable. Despite our oil trading performing commendably in this quarter, I reserve confidence in the overall strategy behind the distribution of our resources across the guts of our assets. Trading in the gas business has done well overall, but the unpredictable quarterly reversals add to frustrations.

Great. Thanks for those answers.

The next question is from Alejandro Vigil of Santander.

Yes, hello Patrick and Jean-Pierre for taking my questions. Related to both questions about the downstream business. You have flagged some improvement in refining margins in the short-term, but I'm more interested in your thoughts about the new-term outlook for this division? And the second question is about marketing. We have seen some weakness in the first quarter, probably just seasonality, where you can comment on that? Thank you.

This isn’t quite as straightforward, as people tend to drive less in winter than in summer. This is true across Europe, and in effect, that has resulted in a lack of surprises. Our results for this first quarter align closely with what was produced in the first quarter of 2024. We may have experienced a drop in overall fuel returns but are still around $260 million to $240 million. Therefore, there should be no expectation of a significant deviation, as this is merely seasonal in nature. The volatility within marketing and services remains quite minimal compared to others. When we disclose assessments indicating growth ranging from $2.2 billion to as much as $2.4 billion throughout the year, we expect that they ultimately deliver solid cash flow. So, in sum, the observed shifts in consumption patterns are not unusual.

The medium-term outlook for downstream amidst improvements tailored to refining is crucial. Noteworthy is our recent decision to shut down one cracker—this signals a serious recalibration of our petrochemical strategy in light of pressures faced, which we believe will enhance our capabilities in the future.

Thank you.

The last question is from Henry Tarr of Berenberg.

Thank you for accommodating my question. I would like to ask about Russia. If there is a peace agreement regarding Ukraine, how do you view your interests in Russia and how do you plan to approach that situation? Thank you.

It will all depend on the conditions of the peace deal, which I cannot predict at present. That being said, we possess strong assets like Yamal Energy, which I consider to be a prime investment; we continue to work on these. For the rest, it’s hard to make propositions surrounding the geopolitical arena due to the varying factors at play. That’s about all I can share for now.

And this was the last question. Mr. Pouyanné. I'll turn the call back to you.

Thank you for your attention. Once again, I feel our company demonstrates very strong fundamentals that instill confidence as we navigate through turbulent waters without overreacting. Through our results this quarter, we exemplify our strengths, especially regarding our E&P division where production growth and robust cash flows are paramount. These aspects lie at the core of our business. Our Integrated Power segment is resilient as well, reflecting the ongoing challenges alongside downstream environments, and the teams are mobilized to optimize asset operations for better margins. Thank you for your attention, and see you soon.

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