Ladies and gentlemen, welcome to TotalEnergies First Quarter 2024 Results Conference Call. I now hand you over to Mr. Patrick Pouyanne, Chairman and CEO, and Jean-Pierre Sbraire, CFO, who will lead you through this call. Please go ahead.

Good morning and good afternoon, everyone. Welcome to this quarterly results session. I’m pleased to be here with Jean-Pierre, who will provide insights into our strong first-quarter results for 2024. Before that, I want to highlight how we have executed our 2-pillar strategy during this quarter. I’d like to celebrate the company’s 100th anniversary, which we marked on March 28, with festivities across 120 countries. We acknowledge our pioneering ancestors who discovered oil in Iraq in 1927 and pay tribute to the many employees, past and present, who have contributed to our journey. By signing this anniversary, we recognize our legacy as pioneers for a century. Continuing in that pioneer spirit, we initiated our path toward energy transition in 2020, evolving TotalEnergies into an integrated, multi-energy company with a clear and simple strategy based on two pillars. The first pillar focuses on oil and gas, particularly LNG, aiming to produce and grow hydrocarbons responsibly to meet rising demand. The second pillar is about investing in and developing integrated power energy for the future, with a goal of achieving net cash positive status by 2028. This first quarter of 2024 has seen substantial progress in advancing this strategy. We’ve made significant strides on both pillars, reaching several milestones. On the oil upstream front, we successfully began operations in Nigeria with Akpo West and the Tyra development in Denmark, both contributing positively to our overall cash margins, along with Mero 2 in Brazil, which started earlier this year. We have also made headway in exploration with a positive appraisal of the Venus oil discovery in Namibia and are working towards a Final Investment Decision aimed for 2025. In the Orange Basin, we acquired new high-interest licenses on the South African side. Additionally, we are progressing well towards sanctioning several Final Investment Decisions planned for 2024, including the Cameia project in Angola, aiming for 80,000 barrels per day, which we operate with a 40% stake. We also intend to place orders for Suriname projects in May and expect to take the Final Investment Decision by the end of 2024. Recently, we completed a notable deal in Congo to increase our interest in the Moho deepwater field while divesting some mature assets. On the LNG side, we have been quite active. We are now benefitting from low reverse trading prices, opening opportunities to further integrate the U.S. LNG value chain, starting with our acquisitions from Lewis Energy Group’s upstream assets in the Eagle Ford. This week, we announced the Final Investment Decision for the Marsa LNG project in Oman, which will set a new low-carbon standard for the next generation of LNG plants at just 3 kilograms of CO2 per BOE, utilizing renewable energy. This exemplifies how TotalEnergies is deploying its integrated multi-energy model in Oman, showcasing the potential of our strategy. We are also working closely with Asian buyers interested in medium- and long-term contracts. This quarter, we signed a contract with Sembcorp in Singapore starting in 2027, perfectly timed as our production increases. Our teams are actively engaging in Asia, particularly in China, Japan, and Korea, where we have a robust position in LNG and are looking to secure oil-linked contracts as part of our strategy. Lastly, we are acquiring SapuraOMV in Malaysia, which has significant potential for growth in gas business tied to LNG pricing. Turning to the second pillar, integrated power, we have seen an increasing adjusted net operating income for the fourth consecutive quarter, which Jean-Pierre will discuss further. We are advancing in implementing our integrated strategy in Texas with a recent acquisition of 1.5 gigawatts of CCGTs, addressing growing demand driven by data centers and AI. In Germany, we finalized the acquisition of Kyon Energy, a battery storage developer. The relevance of our strategy continues to be evident through our results, validating its efficacy and allowing us to sustainably grow shareholder distribution. We are pleased to announce a 7% increase in the interim dividend compared to last year, which I believe will be positively received by our shareholders. This success reinforces our growing share price, signaling market recognition of our strategic direction. Our total shareholder return remains strong, and this value is shared not just with shareholders but also with TotalEnergies’ pioneers, promoting employee share ownership plans. We are proud to be the leading company in Europe for employee capital ownership, surpassing EUR 11 billion, and the Board has decided to grant 100 shares to each of our 100,000 employees in celebration of our 100th anniversary. Now, I will turn it over to Jean-Pierre for a detailed overview of our financials for this first quarter.

Yes. Thank you, and good morning, good afternoon, everyone. As Patrick mentioned, our consistent strategy continued to deliver strong results, and we are well positioned to deliver on our 2024 objectives of more energy, fewer emissions, and growing cash flow. Brent prices were flat quarter-to-quarter, down only 1% to $83 per barrel, and refining margins were strong, plus 36% quarter-to-quarter. 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 capital, of $8.2 billion. Profitability remains strong with a return on average capital employed of 16.5%. We maintain discipline, confirming net investment guidance of $17 billion to $18 billion for 2024. Importantly, we continue to extend our track record of attractive shareholder distribution with $2 billion of buybacks executed during the first quarter and nearly a 7% increase year-on-year of the first interim dividend for 2024, which is now at 20% compared to pre-COVID levels. Moving now to the business segment results, 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 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 to 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 price 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 MMBtu during the second quarter '24. Now moving on to 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 of '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 operations, excluding working capital 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, we anticipate that the Q2 '24 refining utilization rates will increase to around 85% as the Donges refinery progressively restarts, and there are no major turnaround plans.

On marketing and services, this quarter demonstrates the efficiency 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 working CapEx of $6 billion during the first quarter of '24. The main components behind this include the reversal of the exceptional working capital 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 prices on inventories at the end of the first quarter of '24 compared to the end of '23; and $2 billion of seasonal effects, with $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 $6 billion working capital led to a 4% increase in gearing. The decision we made, given the interest rate environment, to exercise the call at the 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 is related to the seasonality impact on working capital 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. The Board of Directors of TotalEnergies decided on the distribution of our first interim dividend 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 of '24.

The first question is from Christopher Kuplent with Bank of America.

On net working capital and your net debt outlook. I think that removes a few questions. But maybe a broader one, I wanted to double-check with you, Patrick, regarding 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, and your thoughts on whether Europe has learned its lesson from the energy crisis or whether it's still dangerous 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.

Thank you, Chris. For sure, European leaders do not want to have another energy crisis related to prices. You can see that in Europe. Not only do you have the German farmers and the French farmers who are complaining as soon as you try to lift or increase some taxes on tractors, fuel prices, so it's not a good idea; that is very clear. We see a global political temperature where a lot of people are calling, I would say, for reform, not in opposition, but for less regulation linked to the Green Deal. We could think that the next mandate of the European Commission might focus more on execution than increasing targets and regulations. But the price issue is obviously more in the hands of OPEC and OPEC+, who are likely to keep it around $90 per barrel. We don't want to go back too high above $100 because it would also impact customers negatively. The price has risen recently due to the crisis in the Middle East, but I don't see a fundamental shift in the market supply. As we all know, there hasn't been much inflow of new supply recently. Demand continues to grow by about 1% to 1.2%. So I believe we can expect prices to hover above $80, perhaps $80-plus for the year. That said, volatility remains a concern. On the subject of windfall taxes, I do not anticipate that there will be such taxes. The principle involved emphasizes that we have a system in which profits are taxed in the country where they are produced. This principle is upheld in most of our treaties with other countries, and we cannot impose double taxes on the same profits. Therefore, I don't think that this will emerge. However, European politicians are looking at what has been done in the U.S. concerning the 1% tax on buybacks. Honestly, this is a debate that is likely to arise in Europe as well. Having said that, I do not believe it would substantially alter our buyback policy for TotalEnergies. This is simply because our buyback policy is centered on sharing additional profits with our shareholders. Even if we have to pay 1% on EUR 8 billion, that translates to $80 million. I think we could handle that, though we wouldn't encourage it. As for the broader perspective, European debt levels have increased, and we anticipate greater scrutiny regarding potential additional taxes. We should stress that if we can cut costs, that would be fairer than simply imposing taxes. In summary, I believe we must distinguish between statements made during the European campaign, the intentions of 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 2025. Can you say what the size of the resource will be for that FID? And can you share with us post your successful appraisal what you've encountered in terms of reservoir thickness, the gas cut flow rates, et cetera?

Irene, you go into details, for which we pay a lot of money to obtain this data, and I will not share them publicly or with my colleagues because we still have much exploration to do. Today, I will not answer regarding reserves, but rather going forward, the reserves are linked to the dimension of production per barrel per day. We are speaking about a development of roughly between 150,000 barrels per day and 180,000. However, we need more engineering studies for that to firm it up. All the data are there. We've conducted the campaign, so our immediate priority is to move towards production. Moreover, our neighbor announced a new discovery in the southern part; we have equivalent prospects on our side. We will drill it and are acquiring seismic data to make that happen. Overall, for Namibia, our first development is this year, which is positive news. To answer your technical questions, I don't have the full data so cannot share any proprietary information. Challenge me as much as you'd like, but I don't have the details. Let's purely say that we are launching if we discuss developments because the data is strong enough to sustain profitable development that aligns with our criteria.

The next question is from Christyan Malek from JPMorgan.

Two questions. Just maybe first on Namibia. I was surprised how the scale of the resource has been increased in terms of the GAAP statement. I've never seen such a massive move in the way it's been presented. How comfortable are you that the FID will stay within your CapEx or envelope in terms of both cost per barrel and other considerations, given that we've seen this scenario before in Angola? My second question is about listings. I find that we can blame everything regarding valuations, but the striking difference between U.S. and European major cash flow levels is the oil. When you have cash flows stemming directly from oil volumes, the potential seems to rebound in a stronger macro environment. At what point do you reconsider the allocation of capital?

On the first question, I'm very comfortable about the FID in Namibia, first FPSO and the second one. This development will remain within the $18 billion capital framework per year. It is profitable, and that is not a problem. The priority for us is typically when we have good oil projects that fit within our criteria; we will sanction them without hesitation. We have never arbitrated against an oil project in the company, which is why I expressed our strategy with 2 pillars. First is oil and gas; second is integrated power. It is clear that we will continue to proceed with good projects as they arise. Our agility enables us to arbitrate effectively while maintaining a constant priority for oil. We are able to sanction additional developments because they align with our profitability criteria. The proof remains that we have demonstrated this in the past, designing a structure that allows us to maximize cash flow and shareholder returns through our strategic foresight. Regarding your second question about capital allocation, we want to stick to our strategy. We maintain a solid oil and gas business that delivers the best return on capital employed among the majors. We are also investing in integrated power, which has a lower return. However, the integration creates value over time. In summary, we prefer not to compromise on our long-term strategy; it is vital to stay the course while remaining selective about projects.

I just meant over the medium term there could be a bifurcation of cash flow. As oil volumes grow and others do not, will the market begin to look backwards regarding that in terms of cash flow?

It will indeed be a good problem if cash flows increase due to higher oil prices. However, I am aware that prices are volatile, and we need to be careful about forecasting. The key point lies in our strong oil and gas business, which allows us to generate the best return on capital employed and increase cash flows as prices rise. I wouldn’t prematurely adjust our strategy due to fluctuations in oil prices.

The next question is from Lydia Rainforth with Barclays.

Two questions, if I could. One is a follow-up on the U.S. listing. Patrick, you mentioned that the Board asked you to look into moving the listing. How long would that process take? What would ultimately stop you from doing it? The second question is on the LNG business. Could you provide us with your perspective on the LNG market outlook? We've seen some project delays due to increased costs; however, there are also competitive projects beginning to emerge.

On the first question regarding the U.S. listing, we agreed with the Board to seriously evaluate it. I will be reporting back to the Board by September, and then we will determine the pragmatic way forward and keep you informed. It's essential to facilitate access to shares for U.S. investors. In terms of the LNG market, I remain positive for 2025 and 2026 since we will not see significant new capacities coming online during that period. We are all aware of the project delays, but demand remains strong. After 2027, we can expect more U.S. and Qatar capacities to impact the market. Demand tends to be reactive, and we’ve observed that countries, particularly in Asia, are willing to invest in LNG, which is encouraging.

The next question is from Martijn Rats with Morgan Stanley.

Two questions: first, regarding the buyback and oil prices, could you share your thoughts on the potential for increasing the buyback program later this year, should oil prices stay elevated? Secondly, could you elaborate on the SapuraOMV acquisition? What attracted you to this transaction?

In regard to the buyback, when we announced in the February release the EUR 2 billion buyback implied for the first quarter of '24, that will remain the baseline level for ongoing buybacks in the current environment. Current sentiments are positive, but it is premature to speak of further increases when we’ve only seen oil prices at $90 for one month. We are carefully monitoring the market, and any adjustments will depend on the market’s stability. Regarding the SapuraOMV acquisition, this deal enhances our position in Malaysia and establishes a strong bond with Petronas. With this acquisition, we gain access to a prolific basin and a significant operating presence. We view this transaction positively; it was not insignificant from our perspective.

The next question is from Lucas Herrmann with BNP Paribas.

Could you provide insights on FIDs for offshore wind and your thoughts surrounding the allocation of capital to wind and the timeline for deployment globally? What about opportunities in Germany, U.K., and potentially North Asia?

On offshore wind, our recent experience in New York raised concerns about the viability of this market for us. While there are many projects we are considering, the business case hinges on energy pricing. If costs become too expensive relative to market prices, we are prepared to delay decision-making. We want to prioritize profitable projects, particularly as the energy landscape evolves. Germany and the U.K. could present opportunities in the future, but we must remain cautious about pricing and development schedules.

The next question is from Biraj Borkhataria with Bank of Canada.

I have a question regarding LNG; there's been talk around EU sanctions on Russian LNG. What would this mean for your offtake at Yamal? Would you be able to either redirect cargoes or declare force majeure? Additionally, could you provide an update on the hydrogen tender you announced last year?

To clarify, if EU sanctions Yamal LNG, the price of LNG will significantly rise. We would benefit from this. Yamal's contribution is limited. Since 2023, we've not received dividends from Yamal LNG, and given the risk of sanctions, we've opted not to hedge our volumes from Yamal. If sanctions are imposed, we will exercise force majeure on some contracts. However, the European leaders understand the critical need for gas security and do not wish for a crisis. As for hydrogen, we received over 50 offers through our tender, targeting 500,000 tonnes per year. We are optimistic about securing this target, which is crucial in reducing CO2 emissions.

The next question is from Michele Vigna with Goldman Sachs.

Congratulations on the strong capital discipline and the ongoing growth of the portfolio. Can you discuss potential project delays or reengineering in your portfolio due to cost inflation? Mozambique is an area where some bids have come back high. Finally, regarding your U.S. primary listing, do you believe it is feasible to achieve inclusion in a major index while remaining headquartered in Europe?

On Mozambique, we don’t face significant challenges. While costs have risen, we’ve effectively addressed our discussions with contractors. I'm pleased to report we have good contracts in place, enabling us to restart our project. Security has improved in Cabo Delgado, and we are optimistic about moving forward. Regarding your second question, a primary listing in the U.S. could indeed enhance accessibility for U.S. investors, although inclusion in a major index like the S&P may not be feasible. Our primary goal is to ensure that U.S. shareholders can directly access our shares in New York.

The next question is from Kim Fustier with HSBC.

I have two LNG questions: First, following your deal with Lewis Energy, how much of your U.S. LNG offtake do you hope to secure? Second, regarding oil-linked LNG contracts, could you provide details on slopes in these contracts? How much of your contracts is up for renegotiation?

To hedge our production costs effectively, we aim for 1 Bcfe of coverage through our U.S. LNG assets. This is strategically important, but there's no rush; we prefer to develop this slowly, making strategic acquisitions when suitable. Regarding oil-linked contracts, the specifics of slopes are proprietary; however, we renegotiate around 30 million tonnes of LNG contracts every few years. Negotiations often involve various parameters, not just pricing.

The next question is from Alastair Syme with Citi.

Could you clarify how much of your integrated power business earnings derive from Spain? I believe you have significant flexible generation assets there. How might low power prices impact your earnings? Regarding Namibia, what do you see as the developmental potential there?

Around 2025, Spain should contribute about 1 to 2 gigawatts from our 35 gigawatts portfolio. While it’s not a major contributor, our early presence was strategic for accessing solar projects. However, competition is intense, and electricity prices are low. We may also consider enhancing our portfolio in Germany and the U.K. in the long run. Regarding Namibia, development potential appears bright, though we need to ensure we aren’t overly optimistic; production capacity will be a determining factor.

The next question is from Bertrand Hodee with Kepler Cheuvreux.

On U.S. offshore wind, could you explain the cancellation of your recent project, and do you still view offshore wind in the U.S. as viable? Additionally, regarding LNG, you mentioned signing long-term contracts with Asian buyers; do you have a target volume?

Regarding the recent project cancellation, it was due to contractor performance—specifically, a key contractor raised its costs amidst inflation pressures, prompting local content discussions. Our priority is aligned, but I cannot disclose precise internal negotiations. As for LNG contracts, we have no specific volume target but are looking to establish a sustainable pipeline. We've noted strong interest in developing potentials, given the current market demands.

The next question is from Paul Cheng with Scotiabank.

Patrick, with your recent acquisition of 20% of RED, is that sufficient LNG coverage for the Gulf Coast, or are you seeking more? Regarding your Talos Low Carbon Solution acquisition, how does that affect your capital investment pace in this area?

The recent acquisition was a step toward securing more capacity, but it's not adequate on its own. We are looking to cover around 1 Bcfe in the coming years, particularly in the Eagle Ford, as we've identified strategic opportunities. The Talos acquisition enhances our position in carbon solutions, particularly in the U.S., where we can establish reliable storage options, complementing our existing portfolio effectively.

The next question is from Henri Patricot with UBS.

Given your strong first quarter in terms of cash flow from operations, should we expect this to continue, or are there factors we should consider when analyzing your cash flow for the rest of the year?

I want to confirm the cash flow guidance of $2.5 billion to $3 billion will hold. However, I caution that seasonality will impact this, and we may not see a consistent run rate. The dynamics change as consumers adjust to weather patterns, impacting demand significantly. So while we're optimistic about maintaining performance, some fluctuations are expected.

The next question is from Jean-Luc Romain with CIC Market Solutions.

What should we expect in terms of organic CapEx for Integrated Power for the rest of 2024? Will it stabilize or increase?

I believe the CapEx allocation for Integrated Power should remain consistent. The proportion is currently ideal at around 30% to 33%, and we want to maintain that level. While we are seeing growth in our portfolio, it won’t lead to a higher capital allocation for this segment. It is essential we monitor the pipeline, manage our timing effectively, and utilize our capacity appropriately.

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

Thank you to all of you. We aimed to conclude on time, allowing you to attend the Exxon call, which follows shortly. Thank you for your attendance. Another quarter of strong performance underlines that while some may see TotalEnergies as somewhat predictable, we prefer continuous upward movement in share price. A steady and reliable company is important to our investors, and we are proud to deliver this consistency.

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