Eni Spa Q1 FY2021 Earnings Call

Good afternoon and welcome to Eni's First Quarter 2021 Results. The year remains a transition period, and the first quarter has shown a varied pace of recovery across our businesses. The quarter was favorable for oil, with an 11% increase in Brent price in euros compared to the first quarter of 2020. We have noted a partial recovery in demand, currently around 95 million barrels per day, alongside a more disciplined supply due to OPEC+ cuts and a natural decline in state oil production. Similarly, the chemicals sector rebounded significantly, driven by industry disruptions from winter weather in the US and increased demand in Asia. However, other sectors continue to encounter challenging conditions. The downstream sector experienced pressure from negative refining margins and lower volumes due to lockdowns, especially in Europe. Despite rising gas prices, the difference between PSV and TTF remained minimal due to new supply sources in Italy and heightened demand in Europe and the Far East. Regardless of these conditions, we are consistently advancing in our recovery. ENI's adjusted EBIT was €1.3 billion, consistent with the first quarter of 2020, and 2.7 times greater than the previous quarter. The adjusted net profit was 0.27, five times higher than the first quarter of 2012. In retail and upstream, our production of 1.7 million barrels per day aligns with our initial guidance. This production level represents a 5% decrease from last year, maintaining a steady gas profile, while total production declined by 9% due to OPEC cuts and a reduction in investment for production optimization as a result of the pandemic. In exploration, aligned with our infrastructure-led strategy, we uncovered 120 million barrels of oil equivalent, primarily in Norway and Angola, which allows us to utilize existing facilities effectively. The Cuica discovery in Angola is near our current FPSO in Block 15/06 and is expected to connect to production within six months. Global gas and LNG EBIT slightly decreased due to a lower spread between European hubs and limited optimization compared to last year, and we foresee ongoing challenges for this sector in the upcoming months. In terms of energy evolution, we are swiftly expanding our retail renewable businesses, having entered the Spanish market this quarter and completed the acquisition of a 20% share in Dogger Bank, our first offshore wind project in the UK. The merger of our retail renewable businesses is progressing, and further along in this presentation, I will detail our refining plan which faced a negative margin of minus $0.6 per barrel in the quarter and weaker retail sales in Europe, down 10% year-on-year, impacting our results. Lockdowns and reduced air travel negatively affected consumption of high-value products. In biorefining, where demand has weakened and put pressure on margins, we have initiated a new Biomass Treatment Unit in Gela, which will allow us to process up to 100% waste and residue feedstock, aligning with our goal of being palm oil-free by 2023. Furthermore, we made significant strides in this promising sector by acquiring FRI-EL, a leader in Italian biogas production. Versalis, our chemical company, achieved its best results since 2018. Turning to financials, we had a cash flow from operations of €1.96 billion and capital expenditures of €1.4 billion, enabling us to generate strong cash flow. Even with a net acquisition portfolio totaling €400 million, we maintained our leverage at 31%. Now, looking at natural resources, upstream EBIT for the first quarter reached €1.4 billion, an increase of about €300 million from the first quarter of 2020, thanks to improved market conditions. Despite a year-on-year decrease in production to around 90,000 barrels per day, we confirm our production target for 2021 at 1.7 million barrels per day, factoring in an OPEC cut of 35,000 barrels per day. We anticipate second-quarter production to be around 1.6 million barrels due to maintenance originally slated for 2020, which was postponed to 2021 because of COVID. We expect a gradual rebound in subsequent quarters. In 2021, maintaining our capital expenditures below €4.5 billion will allow us to fully benefit from a favorable scenario. Regarding the GGP and the first LNG cargo successfully loaded from the Damietta Plant on February 21, 2021, nine cargoes have been shipped to date, and we anticipate stable production throughout the year, totaling around 40 cargoes for 2021, which will help sustain our gas equity production in Egypt. In terms of GGP EBIT, the first quarter was slightly negative, decreasing by around €260 million compared to the previous year, primarily due to the very low spread between European hubs, which was down 84% year-on-year, limiting trading opportunities, especially in Italy and contributing to about one-third of our overall losses. The additional negative effects mostly stem from the absence of one-off optimization that occurred in the first quarter of 2020. If the current scenario persists for the remainder of the year, we expect GGP's EBIT for 2021 to approach breakeven, potentially yielding positive free cash flow of around €200 million, aided by contributions from the Damietta startup. Before we discuss energy evolution, I would like to briefly highlight the startup of the Merakas field in Indonesia, announced earlier this week. This field is a tangible advancement in our strategy to boost gas production, utilizing our infrastructure-led exploration and rapid market entry. Aside from a six-month temporary suspension due to COVID from March to September 2020, Merakas was developed in 11.2 years, connecting to the existing Jangkrik FPU. The field is estimated to house about 2 trillion cubic feet of gas and is expected to produce approximately 30,000 barrels per day in 2021, increasing to 50,000 barrels per day in 2022. Merakas gas will be partly sold domestically and will also help extend the lifespan of the Bontang LNG facility. In the evolution of energy, our renewable gas initiatives are expanding rapidly. EBITDA for the first quarter of 2021 reached €220 million, up 17% from last year, due to strong performance from EGL, which is growing its customer and service base. The combined entity of retail renewables posted an EBITDA of €600 million in 2021, representing nearly a 70% year-on-year increase. The downstream sector’s EBIT for the quarter was slightly negative. In refining and marketing, weak demand, particularly for jet fuel amid widespread lockdowns, affected oil and biorefining margins. We expect gradual recovery as COVID measures ease. Versalis achieved a positive result for the first time since the second quarter of 2018, bolstered by demand for polyethylene and styrene and a favorable margin environment. While we anticipate this positive trend may lessen in the upcoming quarters, we expect the chemical segment's results to remain favorable. For the full year, a lower than anticipated refinery scenario will be largely mitigated through remediation actions and positive trends in chemicals. Adjusted pro forma EBIT for downstream refining and marketing in the chemicals sector is projected to be around €400 million. Now, regarding cash, in the first quarter of 2021, our adjusted cash flow from operations before working capital stood at €1.96 billion, surpassing our total capital expenditures of €1.4 billion. Looking ahead to 2021, we project cash flow from operations before working capital at replacement costs will exceed €9 billion, assuming Brent prices hover near $60 per barrel and considering our refining margins to be slightly above zero. This cash flow generation will adequately cover our nearly €6 billion capital expenditures for 2021. Before we enter the Q&A session, I want to share insights into our plans for retail and renewable businesses. The Board of Eni has endorsed a strategic initiative to assess the optimal industrial and financial plan for the new entity formed from this integration. This endeavor is part of Eni's broader commitment to deliver value through energy transition and marks a significant step in reducing Scope 3 emissions for our domestic clients, which we began several years ago. Our renewable efforts commenced in 2015 with the establishment of the energy solutions business unit, which has progressively expanded its technological and geographical footprint, managing over 1 gigawatt of capacity installed, all under construction across more than 10 countries. Throughout this period, we've fostered various joint ventures to create growth opportunities in the US with Falck Renewables, in Norway with Hitec, and in Italy with CDP. In 2021, we also partnered in the world's largest offshore wind project at Dogger Bank in the UK. These joint ventures, along with other initiatives, will serve as the organic sources for our growth. Meanwhile, we’ve broadened our retail offerings. In 2017, we established Eni Gas e Luce, a dedicated company for selling innovative energy services to end customers. EGL has expanded its international presence by launching a new company in Greece in 2018 and entering the Spanish market this year. Additionally, EGL has introduced new services, including energy management, electric mobility, and building energy upgrading, reaching nearly 10 million customers. Looking ahead, we anticipate that our retail G&P customer base will grow to 50 million within a decade, accompanied by an increasing supply of renewable energy and biomethane. By the end of 2021, our renewable capacity is expected to exceed 1 gigawatt, with projects under construction increasing to 5 gigawatts of installed capacity by 2025 and 15 gigawatts by 2030. This new entity will provide a distinctive value proposition for both our customers and investors. In a competitive market, our renewables will leverage a loyal customer base, stabilizing revenue streams and granting flexibility in seizing market opportunities. Simultaneously, retail will be empowered to offer green energy generated from our solar facilities. We believe this will significantly enhance our marketing differentiation, improving our commercial appeal. Additionally, supplementary services like distributed solar and energy management will round out our unique approach. Overall EBITDA for the new entity is projected to nearly double from €600 million in 2021 to around €1 billion by the end of the plan. Operating cash flow generation will also double, driven by resilient and cash flow-positive retail operations alongside growing contributions from the renewables segment. Eni has formed a dedicated internal team, supported by strategic and financial advisors, to lead this project, which will explore multiple options for maximizing value from the new entity. Considerations include a possible stock exchange listing through an initial public offering or the sale or exchange of a minority stake in the new entity during 2022, depending on market conditions. This market valuation will unlock value, achieving better enterprise value-to-EBITDA multiples than currently recognized by the market for renewable and retail companies. Now, Eni's top management and I are prepared to address your questions. Thank you.

Thank you. So the first question is from Michele Della Vigna of Goldman Sachs. Please go ahead.

Francesco, thank you very much for the presentation. I had two questions, if I may. The first one is on Eni Gas e Luce, I was wondering, do you see this as your global day call for power, which include all of the renewable work that you're doing in your upstream heartlands in the Caspian in Africa, in Southeast Asia, or more as a European focused company? And then secondly, your ongoing exploration success continues to provide you with a large panel of short cycle development opportunities. At the time, when the macro recovery is finally coming through, do you see an opportunity to accelerate the development of these projects as the most interesting investment decision?

Okay. Thank you, Michele. About EGL and then I will leave it to Alessandro Puliti, to answer regarding the exploration in FID. Now, in terms of EGL, what I can tell you is that this is a vehicle that for us is to decarbonize our domestic clients. So, that is the main scope of this vehicle. This vehicle is substantially a new entity and there are no such kind of players in the market. The market is now specialized either in generating capacity or on the other side is selling power to the clients. We are generating now, we are creating this new machine, as I put together these two to a screen share. And in the middle, there is value, because in the middle there is energy management, there is a capability to absorb the rotation of the renewables and so gaining value from that. And there is clearly value in the two sides of this proposition because as we said that there is a stabilizing factor for renewable sales to captive clients, and there is a green marketing proposal that is attractive for domestic customers. In terms of the boundaries of this vehicle, this vehicle will be mainly an OECD player because clearly in this area there is the full chain combat at the back and there is no exclusive, let's say, OECD. For example, we have opportunities in certain countries that we believe are quite promising. For example, we think in Kazakhstan, a country that offers EMP, particularly historical positioning in this country, we could just be focused on the generation side in the future, we don't know the future, we will see what's going on. But the generation side will remain attractive. So, where there is a market that is let's say, more mature with a large advisor, there is an opportunity to sell directly to the final customer, otherwise we will sell to the grid. For example, in Australia, where we have activity already existing. What will not be included is that kind of generation capacity that is, they say, embedded treaty connected to our upstream plan. So, in that case, this capacity is just a facilities offer of our upstream activity. And now I leave the second answer to Alessandro.

Okay. Good afternoon regarding the ability to transform a recent exploration success into an accelerated development program to capture oil pricing upside, I will say that this is exactly the strategy with sector because our exploration is mainly devoted to the so-called infrastructure-led exploration, targeting prospects nearby existing infrastructure and facilities to accelerate time to market and bring new production to the market. Also, we have a strong input on what is called near field exploration. So, directly close to fields already in production. I would like just to give you an example on this recently in the western desert of Egypt, our carrier discovery led very quickly from zero to an addition of 50,000 barrels of oil to our Agiba operating company in the western desert of Egypt and this was immediately put into production right after for successful exploration wells.

Thank you.

The next question is from Mehdi Ennebati of Bank of America. Please go ahead.

Hi. Good afternoon. Thanks for taking my questions. So, two questions. The first regarding extreme. So, this is applied to the sensitivity to the oil that you provided first a few months ago. You first confirm a little bit would have been much higher than what you expected. So, can you please tell us why there was such a difference between what I couldn’t hear and the figure based on your sensitivity? Was there any one-off or anything like that which this is actually office related? And the second question is on study, if you pursue the principle of integrity as you said, this is good. But if I look at the initial rate of your chemical plants, which remained at 70%, so this means that you are able to take advantage of this strong economic environment that the local demand doesn't have to take advantage in pollution, or should we expect the high value of wait in the coming quarters of each division as the market remains?

I will respond to the first question and then I will let Adriano Alfani address the chemical performance. First, there are two key elements to consider, and I will also explain the specific case. On a quarterly basis, there are various factors at play that reflect our shifts from quarter to quarter, making it relatively imprecise. Additionally, our sensitivity analysis is based on minor price movements, typically around $5 to $7. However, if you consider a $17 change, like comparing the last quarter of 2020 with the first quarter of 2021, you have roughly 50% associated with gas. Of that gas, approximately 20% captures the dynamics of that quarter. Another 30% is interconnected, and this interconnectedness suggests a lag time, as it generally reflects a nine-month average from the previous period. Then there's the remaining 50% of gas tied to fixed or former prices, which are minimally affected by market variations. Therefore, the first point to consider is that our linear approach to sensitivity in a quarter does not accurately represent the extent of these changes. There's also the potential impact of PSA that could influence results. Specifically, for the last quarter of 2020 and the early part of 2021, two factors played a role. At year-end, we typically see one-off events, such as the insurance benefit from the end of last year and a settlement in West Africa, which both positively affected the EBITDA and EBIT for that quarter. Additionally, there was a mix change, notably a significant increase in gas from Zohr and a decrease in contributions from Indonesia’s Jangkrik, which is more closely tied to the spot market. Furthermore, there were fluctuations in Nigeria as well. Even with similar absolute gas or volume trends, there are many moving parts. Lastly, this larger variation justifies a certain degree of discounting, although it is not substantial and reflects all the factors I have mentioned. Now, I will turn it over to Adriano for the response regarding chemicals.

Sure, Francesco, can you hear me? Thank you. As you mentioned, the situation in Tijuana has been extremely positive due to a global recovery in demand, particularly in Asia and North America, along with a strong recovery in Europe. This rebound occurred more rapidly and to a greater extent than anticipated at the beginning. Additionally, there have been challenges on the supply side. By the end of 2020, we began to notice limitations in product availability from North America and certain shortages in Europe due to the hurricane season in the US. This shortage has intensified in Q1 because of severe weather conditions affecting us. We are aware of the challenges we have faced over the past years and have also encountered unexpected events in Asia and Europe. Our integration was around 70% to 72%, but we could not achieve more due to two main reasons. One reason relates to internal factors, including some minor unexpected events that slightly hindered our production capacity. The other reason is that in some business segments, we source products from the market, such as benzene and other chemicals, which have been in short supply. We also encountered challenges in securing these supplies. Consequently, in Q1, we maximized our operations, resulting in an asset utilization rate of around 72%, which was consistent with Q4 2020. In the second quarter, our asset utilization will be affected by a few already-announced events, including the turnaround in Brindisi and other activities we disclosed this week in Mantova, leading to limited capacity due to the turnaround season.

Thank you very much.

The next question is from Jon Rigby of UBS. Please go ahead.

Thank you. Hello, everyone. I have a quick question regarding the proposed transaction. First, is this transaction all you plan to do, or is there a subsequent phase intended to extract more value? Specifically, while this will generate cash for Eni's corporate purposes, do you have a strategy for utilizing the cash from any proposed transaction, such as enhancing a buyback to clearly demonstrate the differences in valuations? Secondly, we are grappling with the challenge of maintaining competitive advantages that integrators have when entering certain markets, particularly in relation to the integrated discount on the operational side. Is there a way to create a management and legal framework that preserves the independence of this new entity while also allowing you to leverage the skill sets present within the Eni group? Thank you.

Okay, Jon. You raised an important point regarding your first question. I’d like to summarize the three main reasons for this transaction, the merger, and the potential IPO next year. The first reason relates to the industrial rationale. This integrated value chain is designed to stabilize and create value throughout. I believe this can only be achieved by an integrated player. The second reason is to establish a vehicle to function in this area of growth, focusing on new businesses with appropriate metrics. These metrics include multiple value, cost of capital, and dividend policy alongside leverage levels. We aim to raise awareness of these growth areas. In the current environment, entering this game without the right setup can be detrimental, leading to immediate discounts as an integrated oil and gas company. Hence, we need the right currency to engage effectively. The third reason, as you mentioned, is the opportunity to generate free cash to enhance and stabilize Eni's distribution policy and increase the capacity for growth within the new entity. This includes accelerating capital expenditures, leveraging new equity inflows, and relieving Eni from cash pressures for investment in these new businesses. It’s too soon to define how we will use the proceeds, but it’s clear that there is a mutually beneficial opportunity for both the new entity and Eni. We aim to maintain control of this entity because we prioritize value. I’ve noted before our commitment to being a fully decarbonized energy company across all sectors, processes, and products. This approach allows us to develop tools to decarbonize our domestic clients. We are also targeting net zero in our upstream operations by 2030, with downstream targets set for 2040 and a scope three target to address our emission flows. There are additional clients in mobility that need decarbonization, as well as users of our oil and gas production who we may not directly influence. We intend to preserve this connection, which is why we are considering a minority stake disposal, as we believe this is just the beginning of our journey. This process will affect the entire company, and we anticipate that any discount will gradually decrease due to our efforts across all segments.

Right. Got it. Thank you. That’s very clear.

The next question is from Alessandro Pozzi of Mediobanca. Please go ahead.

Hi, I have a few questions. The first one on the tax rate. I think there are a couple of other responses. At the group level, 75% is probably be higher than what I had expected. So if you can maybe give us some additional color. But then at the same time, I think the upstream was quite, was quite low, despite the increase in volumes from Africa and Egypt. So maybe can you tell us how we should model the tax rates in the upstream, at the group level going forward in 2021? And also, maybe an update on the renewable pipeline. Can give us maybe some color on the next key project coming on stream? And also upstream, you will find a new JV with GDP and permits. I was wondering, what type of opportunities do you see? And also the type of permitting that Italy is quite slow to get permits for new projects. So and you have quite an ambitious target 1 gigawatt of new capacity. Yes, I’ll leave it there.

Thank you for the question. I will address the tax issue, and then I'll let Alessandro discuss renewables. Regarding the tax rate, it stands at 70% to 73%, which is slightly higher than we originally estimated. It's important to note that the group's overall tax rate has been affected by a poor performance this quarter in RMM and GDP. Certain segments have particularly low tax rates, and we did not recognize some deferred tax assets in Italy due to concerns about their future recoverability. This is a key factor influencing our current situation. If it weren’t for this one-off component, we would have aligned with the guidance of a 60% tax rate, which would be around $60. For Exploration and Production, the tax rate is at 50%, which is relatively low. This is because, with a $60 award, various countries provide benefits beyond the typical higher-tax-rate regions like Libya, Egypt, and the Middle East. Furthermore, we are seeing favorable results from other areas, including OECD countries and Italy. The overall E&P sector is benefiting from this diverse mix of contributors. Looking ahead to the full year, I can confirm that we expect to return to an overall tax rate of 60% to 65%, as the one-off factor we've experienced is anticipated to diminish over time. While quarterly guidance is significant, it should not be viewed in absolute terms; my annual assessment remains unchanged. Now, Alessandro, if you could please provide an update on renewable growth?

Yes. In renewables, we anticipate exceeding one gigawatt of capacity by the end of this year, either installed or under construction. Regarding the pipeline, we are also focused on reinforcing it to reach our target of 4 gigawatts in 2024. We are pursuing several development avenues. One important aspect is our joint venture in the US with Falck Renewables, which is now fully operational and benefiting from an improved regulatory environment under the new administration. In Southern Europe, we are exploring various opportunities, especially in co-developments, such as the recent arrangement with the Spanish company X-Elio to acquire three photovoltaic plants in southern Spain. We are particularly interested in these countries because we see potential for synergies with our retail business, which entered Spain last month. Additionally, our joint venture with Cassa Depositi e Prestiti in Italy is now fully operational and is focused on enhancing our pipeline of Greenfield projects. This includes utilizing real estate assets owned by us, CDP, or public administrations that are currently idle. We believe this area presents a compelling economic opportunity and aligns well with the sector's development in our country.

Okay. Do you expect a bit more favorable environment easily following the new government? Do you think they are permitting will be accelerating the process?

Certainly, we see the conditions now for the environment to improve, especially in the authorization processes that have been the weak points slowing down the development of renewables in recent years. There are certainly a number of positive announcements from the government in this regard.

Okay, that’s fine. Maybe I can fit in one last question. It’s probably not easy to determine the right compound for renewables in the retail business. What valuation or multiples should we consider for that business?

Alessandro, it's still early for us as we are promoting a concept that is quite new. To provide some market insights, our E&P measure is currently valued at four to five times EBITDA, while I believe it's now valued at seven to eight times EBITDA. Renewable players are typically valued between 10 to 15 times EBITDA based on growth expectations, and some are even higher. The immediate valuation impact from this vehicle's proposition is clear. The integration of these two entities could potentially elevate the vehicle's valuation to a double-digit multiple.

That’s very clear. Thank you very much.

The next question is from Irene Himona of Société Générale. Please go ahead, ma’am.

Thank you very much. Good afternoon. Two questions please. A question on Mexico, if I may? They have just passed new hydrocarbon law, rolling back the energy liberalization of recent years; you have a lot of presence there, obviously. I wonder how we should think about the risks to any in particular to the full development of Area 1, or indeed in terms of potentially higher tax and royalty levels in Mexico. And my second question is on the global gas and LNG business, when it comes to making delivery profit in quarters when you have some contractual renegotiation. So if we move that, we are left with essentially a trading business. How should we think of this business, because clearly we cannot model or predict contractual settlements, or how should we think of it going forwards, please?

Thank you. Thank you, Irene. I leave the answer of Mexico to Alessandro Puliti, and on the LNG business to Cristian Signoretto.

Okay. Regarding Mexico and our project and new laws, our project is progressing, as you know, we are in the early production phase nowadays and we are constantly producing above 20,000 barrels of oil per day. In the next year, it is foreseen the installation of the FPSO and then we will ramp up to its maximum production. So we are not envisaging an impact on our project due to the new law, because as far as we understand it won't affect this project, or affect other oil trading businesses and not developments, this kind of developments. So for the time being, we don't have any doubt on our project delivery in Mexico. And I will leave the floor to Christian for the LNG.

Good afternoon. I would like to elaborate on two key areas. Firstly, regarding the gas business, which primarily targets Europe and Italy, as you noted, this sector has been significantly impacted by the renegotiation with our long-term supplier, unlike in the past. This quarter has been influenced by the unfavorable spread between the Italian market and the European market, which directly affects our long-term supply agreements and has led to a necessary renegotiation that we expect will yield positive results in the future. On the LNG front, we are aiming to significantly expand our portfolio in alignment with our upstream initiatives. In the first quarter, we sold 1.5 million tonnes of LNG, but there was no contribution from the DAMIETTA startup during that period, although you will see this contributing in the upcoming quarters. Additionally, with support from other US equity projects, we anticipate further growth. However, it's important to note that this activity is tied to the less complete part of the value chain, with the price movements of LNG and gas being linked to upstream operations. We are managing the trading margin, which involves the difference between our purchase price for LNG and the selling price in the global market.

Okay. Thank you.

The next question is from Oswald Clint of Bernstein. Please go ahead.

Thank you, Francesco. I'm curious if you could provide some insights into the cash flows from some of your other startups. You mentioned Morocco, as well as Algeria, Angola, and Sharjah, particularly regarding the ramp-up there. It seems a bit unclear regarding pricing and taxes, so any details you could share about the cash flow per barrel from those projects would be appreciated. Additionally, could you discuss any feedstock pricing pressures related to your bio refineries? Gela has locally sourced biomass, but how is palm oil performing in that context? Has there been any pressure in the first quarter, and what do you anticipate for the rest of the year? Thank you.

Thank you, Oswald. I'll leave this second question to someone else and then we can come back to you regarding the project you mentioned in terms of its contribution. We are not sharing details at the project level. What I can tell you, I will explain later. Could you please continue?

Okay, speaking. Yes, regarding the pricing of the feedstock in our biorefinery, the first quarter faced considerable pressure from palm oil, which is the primary component of our feedstock. However, we anticipate a significant variation throughout the year, as we have started operations on our BCU, which will enable us to significantly alter the distillate of the feedstock for the biorefinery.

Now, regarding cash flow, each project has its own financial dynamics due to the differing products involved. The UAE Sharjah project is focused on gas with condensate, which offers more attractive cash flow. The Algeria project, Berkine, includes two streams: gas production and oil production that we began earlier this year. In terms of cash generation, we are meeting our expectations. As for cash flow from operations, we indicated a value of $60. We are fully utilizing the favorable conditions on an annual basis, benefiting from both growing oil and gas production. It’s important to note that there is a time lag, especially with oil-linked contracts, unlike fixed domestic sales. In February, we projected a cash flow from operations close to €8 billion with an oil price assumption of $50. With the revised assumption of $60 for Brent, we anticipate an increase of about 1.5 billion from the price effect. However, we also expect to lose an additional €300 million due to our sensitivity analysis. While chemicals may add some value, overall, when these figures are summed, we estimate to exceed €9 billion. This aligns with our forecasts, and we are performing slightly better due to favorable conditions and product mix, with new fields positively contributing to the overall results, primarily from brownfield projects in Sharjah and Berkine, where facilities are already established.

That's really helpful. Thank you, Francesco.

The next question is from Massimo Bonisoli of Equita. Please go ahead.

Thank you and good afternoon. I have a question on the announced transaction. You mentioned among the options an exchange of minority stake. So, could you give us some color on this option? Would you eventually swap your stake for another minority in a renewable company, or it may also include other E&P assets? Are you looking for synergies with another renewable retail company? And the second question is, back on the call of the full quarter, it was announced there that you will eventually have a transaction in the upstream like the one with Vår Energi for a joint venture in upstream assets. Are you targeting a larger portfolio of assets for the JV, which include multiple countries in the same region just to understand the perimeter of over dealing in the upstream?

Okay. About the first transaction, the retailer renewable, clearly, we have listed the three different opportunities. Clearly, the IPO, the disposal to a strategic player, or eventually combination, clearly the sort of element cannot be a combination for an upstream player. We wanted to create the retailer renewable champion. So we have to assume to work within that playground. So I think that this is the logic of this operation of this potential option, because at the end of the day, we listed all the potential options in this early phase of our study. About the model Vår-like initiative, if you remember, once we presented the strategy, we said that we would like to have this kind of combination, because we wanted to create a vehicle that is financially able to be standalone. This is different from the retailer renewable, in this case, the target is to have a big consolidated vehicle as well, able to collect cash, etc. and to distribute dividend and to reduce the CapEx exposure in particular in certain countries or regions that are more or less capital intensive. So, from the point of view, we are actually working very hard on that. There are more areas of interest, more geographies of interest, and potentially different operations, not all at the same degree of maturity. But clearly, we are thinking to a combination, where we could have a few countries together, not too many countries, because once you build this kind of vehicle, you have to think about operational synergies, you have to think of financial attractiveness, and also you have to think about governance. So, you cannot just say to put together in a big soup all the ingredients that you like, you have to select the right one.

Very clear Francesco. If I may squeeze in another quick – very quick question, just on for our models, considering the changing in the assumption of oil for cash flow generation, what would be your new net working capital impact for 2021?

On working capital, just sampling substantially to around 500 million of absorb of working capital. So we continue to have this kind of assumption.

Very clear. Thank you very much.

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

Good morning. The first question is on renewable capacity growth you discussed, a lot of the focus of the JVs you mentioned seems to be tilted towards solar, and your scale at the moment in winter is, you could say somewhat suboptimal. Can you talk a little bit about the potential bidding opportunities to add capacity in this technology? And where do you see wind – offshore wind capacity going in the context of your 5-gigawatts and 15-gigawatts targets? And the second question is, you mentioned that EGL power and renewables is just one of your decarbonization legs. Your biofuel business is also quite unique in the context of the integrated sector I think. So do you think that the value of this business is fully recognized at the moment and have you considered a similar path to the one you announced today with for any gas evolution, power renewables for this business as well?

Okay, Giacomo on the second question, then I leave to Alessandro again about the wind offshore plan. Clearly, we started with this domestic decarbonized model because we think this is more mature. There is a large client base. There is an opportunity to grow faster in renewable capacity. And the reason I say this opportunity is to create the joint integrated model. So I think that this is the first step that we have designed. I agree with you that the other element that is quite interesting is the bio refining and the mobility client. The mobility client is the other side of the domestic client. The domestic client is exiting, taking a car and moving around. So, it's truly the same mindset to receive asset of the carbonized product. And you know, that we have the second let's say, internal capacity. We are the second operator, the second player for bio refining capacity. We have the refining that has a unique technology that gives us a lot of flexibility. But we prefer to grow further and to let's say, reinforce this model before thinking to something more. Clearly, in this current configuration, all the technologies, these new businesses, may other in the overall evaluation of E&I are relatively discounted. So, we have to think about that. And Alessandro, if you want to integrate about the wind?

Yes, I can confirm that looking forward, we are going to rebalance our partnering portfolio between solar and wind. In the past, we focused particularly on portable site projects. But we are now shifting this and we are looking to geographies a wind function, wind projects under construction currently in Italy, in Kazakhstan, we entered a wind project in Iowa in the US. So, what we are targeting is to come to 2024 with a split of renewable power generation between wind and solar, I would say 60% solar and 40% wind, which will also include as you mentioned, offshore wind after our entry into Dogger Bank, we are also looking to those kinds of projects.

Thank you.

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

Thanks very much. And Chester, thanks for the opportunity. The commentary around trying to extract value is very encouraging or thinking much more about how to play with your portfolio. Just going back to another aspect of that, as part of the strategy is clearly to realize value through diversity in some of your upstream positions. And I wondered how that market was looking for you at the present time. I'd assume more robust, but any commentary around potential divestments, JVs, etc. would be helpful. And secondly, if I could just go back to LNG, a couple of questions really. First, Maracas, how much of the production of Maracas, I presume all of it goes through on saying, but how much of it is actually contracted to other buyers at the present time? And how much do you end up being able to play in?

Okay. About disposal then and the other question about LNG are given to Christian. Now, the disposal clearly we are working, that we presented a plan of disposal for the four year playing range of €2 billion, so particularly 500 million per year. And actually, this year, we are expecting to have a net effect between disposal and acquisition of, let's say, minus €500. Because we are selling for €500 and potentially having, let's say, potential acquisition in the range of €1 billion in different sectors. I am not just referring specifically to upstream. We are clearly working and differentiating the absent side. There are at least four or five assets that are under tender in certain cases quite advanced. And I think this processor is maturing. There are assets that are coming from the dual exploration approach. Assets that are related to see mature countries where we consider no more cores in our portfolio and other opportunities that we could monetize and analyze that through this event or partial disposal of a smaller stake. So, the process is coming in. It takes time because negotiations require a lot of detail. And therefore you will see some effects in the coming months. About LNG?

On Maracas, I can tell you that a quarter of that production will go to the domestic market as required by the government. The remainder will supply the Bontang LNG facility and will be brought to market in the coming weeks and months. We are in discussions with the authorities and potential buyers to include necessary contracts to secure the uptake of LNG from Maracas production. Regarding Damietta, you can think of it as a tolling facility where Eni owns 50% equity and provides the tolling arrangement.

When it comes to the link between the production of Damietta, I will let Alessandro provide more details on that. Regarding Zohr and Damietta, there is no direct commercial link, but there is a notable production connection between the two facilities. For instance, in the first quarter of 2020, Zohr's production averaged 2 billion cubic feet per day. By the first quarter of 2021, this had increased to an average of 3 billion cubic feet per day. Clearly, Zohr is responsible for nearly 50% of Egypt's gas production and serves as the main producer in the country. The opening of these export opportunities has significantly helped us reach maximum production capacity, benefiting both the upstream and mainstream operations.

Some forecast for the fourth quarter of this year or an average?

The fourth quarter in average would be certainly above 3.3 Bcf per day while the average of the year will be around 2.7 Bcf per day.

Thank you very much.

The next question is from Bertrand Hodee of Kepler Cheuvreux. Please go ahead.

Yes. Hi Francesco. Two questions, if I may, related to gas prices? And so first, my understanding is that on Zohr gas price realization there was a formula linked to Brent with a flow at $4.2 and an end cap at $6 per Mcf when oil price was above $60 oil? So my question is, is there a lag effect on Zohr, meaning that could we see if the oil price stays above $60 in the next quarter? An uplift in your natural gas price realization? That is my first question. And the second question is on the Tcf spread, though you clearly mentioned that you have suffered this quarter from this narrowing spread. And the reason behind that is and you may share your view in that is for the new volumes from that release, but in a way is that the structural narrowing and your action to renegotiate some gas contracts?

Thank you. Thank you, Bertrand. I leave it to Alessandro and to Christian about this answer about Zohr and the spread.

Regarding gas pricing Zohr formula? Yes, I confirm there is a lag time effect and we will see the full benefit of this $60 per barrel towards the end of the year and beginning of next year. I’ll leave it to Christian to complete the answer.

Yes. Regarding the spreads, you are correct that the gas inflow from the pipeline has introduced approximately 60 bcm, increasing to 8 bcm annually in extra capacity. This has indeed reshaped the supply sources in the country. The first quarter was also influenced by a very high TTF price due to the LNG market tightening, which redirected LNG from Europe to Asia. This dynamic affected the PSV, although it was not directly connected. I agree that moving forward, while it may not reach the levels of the first quarter, the spread between PSV and TTF may find a new equilibrium, probably in the range of 10 to 12 rather than the €20 per 1000 kilometers we experienced over the last two years. Additionally, this situation has prompted us to begin renegotiating contracts with our suppliers, which we expect to see positive results from in the coming months.

Thank you very much. Extremely helpful.

The next question is from James Hubbard of Deutsche Bank. Please go ahead, sir.

Hi, thank you. Good afternoon. I have two questions. First, you mentioned real estate in relation to renewables, and I assume you are referring to Brownfield industrial sites. Please correct me if I'm mistaken, as you seem quite enthusiastic about it. I envision older fuel industrial sites and I'm curious about the available acreage and why this is an exciting opportunity for installing solar panels. My second question is for clarification. I thought I heard you say during the call that for the full year, refining and marketing chemicals is expected to reach 400 million in EBIT. Did I understand that correctly? Thank you.

Yes. This second question, then the first one I return to Alessandro. About the EBITDA clearly, this is a revised guidance that includes a progressive improvement in the refining margin. So potentially averaging in the range of 1.8, 1.9 that is the half of the margin that we are assuming the original budgeting. And we substantially have this factor between the range of 300. On top of that, there is the benefit of the chemical businesses that is adding an additional 100 versus the previous guidance, this means that there is a reduction of these two segments together in the range of less than €200 million of EBIT. About the real estate on particular use of industrial plant, I leave this to Alessandro to provide you more color.

Yes. We are referring to both industrial sites and unused areas that are managed by various public administration entities. We believe there is significant potential that we want to unlock. Additionally, we are working on a new joint venture with Cassa Depositi e Prestiti in Italy that was established a couple of months ago. This involves both industrial sites and unused areas.

Okay. And I guess the advantage in Italy is much faster permitting, is that correct?

Yes. It's on permitting and we count very much on the simplification that the government announced recently, together with the availability of the areas themselves in Italy. This is an issue once you exclude the agricultural areas, then you're left with a significant constraint that is hindering, let me say, the growth of renewables in the last few years.

Okay. Thank you very much.

The last question is from Lydia Rainforth of Barclays. Please go ahead, madam.

Right. Good afternoon. Three questions if I could. Firstly, on the biogas market that you mentioned earlier in the exhibition that you did? What is the scale of that market that you're seeing there and will that fit into the energy evolution part of the business? And then secondly, of course, I think I missed this earlier on but in terms of July and the review on prices the share buyback scheme, is that just automatic in terms of the idea that there will be a buyback that you will start in the third quarter? Thanks.

Okay. I'll let someone else address the biogas question, and then I'll wrap up with a comment on the buyback. Thank you.

Okay, speaking about biogas, our recent acquisition of FRI-EL has positioned us to have a substantial pipeline for converting plants that generate gas from biomass into bio-methane, both compressed and liquefied. Specifically, we aim to enhance our ability to expand this business by acquiring organizations that are already established in this area. Our goal is to ultimately supply only biogas to service stations that offer compressed and liquefied gas. With the pipeline already planned, we expect to convert gas to methane within a couple of years, reaching approximately 50 million cubic meters per year. This is a significant amount to begin with.

Yes. Regarding the distribution policy and buyback, we have structured this approach to align with fluctuating oil prices, which will be established in July. Currently, Eni is in a strong position. This quarter has shown that despite discrepancies in consensus and sanctions imposed by sensitivity applications, we are successfully generating substantial free cash flow. This is just the beginning. The quarter still involves various elements of marketing and gas and power sectors, indicating room for improvement that will clearly develop over the years. Exploration and production will benefit from price variations in gas. Therefore, we set a $60 price reference as a benchmark, above which we generate significant free cash. Currently, the price is $67, and for the year to date, it stands at $62. Our buyback scheme is activated based on a price of $56, so we are in a favorable situation. The market outlook is positive, with promising signs, and we will reassess this in July after six months of market data. The market is recovering, particularly in Western countries, demonstrating growth as lockdown restrictions are lifted. India remains significantly affected, but overall, there are many encouraging indicators that inspire optimism for the future. This concludes my remarks for this call, and I do not believe there are any other questions.

No, sir. I confirm there are no questions at this time.

Okay. So I thank you all and we will remain in touch for any further qualification that could be required. Thank you very much.

Thank you. Bye.

Ladies and gentlemen, thank you for joining. The conference is now over and you may disconnect your telephones.