Snam S.p.A. (SRG) Earnings Call Transcript & Summary

Good afternoon. This is the Chorus Call conference operator. Welcome, and thank you for joining the Snam 2020-2024 Strategic Plan Presentation. [Operator Instructions] At this time, I would like to turn the conference over to Mr. Marco Alvera, CEO of Snam. Please go ahead, sir.

Thank you. Ladies and gentlemen, good afternoon, and welcome to Snam's 2020-2024 Strategy Presentation. I hope that you, your families and your colleagues are well. And I look forward to seeing you again in person soon. The plan we present today is about Snam's exciting journey towards a net zero carbon future. This journey has 3 significant implications. First, getting to net zero ourselves. We intend to be the first in our sector to do so by 2040. Secondly, our assets play an essential role to get to net zero, which means that it extends the long-term RAB growth potential. Third, the energy transition businesses that we have built now face exciting growth prospects. All this makes Snam a market leader in the race to net zero. Our target of net zero by 2040 is the most ambitious in the industry so far. Already by 2030, we commit to cutting emissions by half, which means taking out approximately 800,000 tons of CO2 equivalent. Almost half of this reduction will come from installing new dual-fuel gas electric compressor stations, which will also help with the sector coupling. We will also reduce methane emissions by 45% by 2025 compared to 2015, in line with the UNEP framework. ESG remains at the core of our strategy. And in the backup, you will find our new ESG scorecard, which defines our '22 targets on which you will be kept up to date. Getting to net zero is one of the biggest challenges of our generation, and it faces significant hurdles and requires unprecedented investments and cross-industry cooperation. Countries accounting for 50% of global emissions have set or are in the process of setting full decarbonization goals. China recently announced its ambition to peak CO2 by 2030 and get to net carbon zero by 2060. Meanwhile, the U.S. has recently signaled its intention to rejoin the Paris Agreement and set its own net zero targets. Putting together different sources indicates that between $100 trillion and $150 trillion of investments are required across the value chain. The mobilization of resources will be significant, and Snam is ideally positioned to play a key role in this supercycle. Our position in the supercycle is firmly anchored on our midstream assets, which continue to generate attractive investment opportunities and visible cash flows for the very long term, as they provide flexibility to the energy system and play an essential role in getting to net zero. In addition, we are building positions upstream and downstream of our assets in hydrogen, in biomethane, production infrastructure and final uses with the focus on mobility. Finally, we've created an energy efficiency platform, offering our clients the opportunity to lower their own energy consumption, their energy bills and reducing their environmental footprint. A net zero future places renewables at the core of many of our activities. In this context, it will become increasingly strategic to invest in this space. We're also interested in leveraging our core competencies in adjacent segments such as water. Neither of these opportunities are currently included in the plan that we present today. We believe that we're well positioned to thrive in this new phase, thanks to the groundwork we have put in place over the last 4 years. There are 6 reasons why Snam will succeed in a net zero environment. First, our early commitment to ESG and to net zero. Second, the fact that our regulated asset base is future-proof and a crucial part of the energy transition. Third, our team's unparalleled project management and execution capabilities. For the 14th year in a row and despite COVID, we will close our investment program this year on time and on budget, including a very complex project like TAP, where we have assumed the project's leadership among our senior peer group. Fourth, the 4 startups in the energy transition have established themselves as business leaders in each of their segments, and they will generate outstanding growth and value creation. Fifth, our enhanced international footprint and product portfolio, which allows us to pursue additional decarbonization initiatives. And finally, we have repositioned Snam and funded these initiatives, maintaining our strict financial discipline. We've kept a strong balance sheet while paying superior returns to shareholders and growing our overall profitability. Let's now take a closer look at the market. The green gas revolution we have been an early advocate of is finally well underway. As countries think about what net zero looks like, the role of green gas for hard-to-abate sectors, long-distance transport and seasonal storage becomes clear, leading to strong policy support. On that basis, the share of green gas in 2050 is expected to be above 25%. The role of gas infrastructure assets in delivering net zero has also become much clearer over the past 12 months. Unprecedented collaboration, technical testing and information sharing among leading TSOs leads to the conclusion that the European grid requires limited retrofits and newbuild to be hydrogen-ready. The unique feature of green gases is that they're not a transition fuel. But like solar and like wind and like most of the hydropower, these are considered forever fuels. Phase 1 of the role of gas in the energy transition is the switching from coal and diesel to natural gas. This is already economically competitive in a number of sectors, including power generation and heavy transport. Fuel switching provides immediate CO2 savings at the lowest abatement cost and has the potential of adding 400 billion cubic meters of gas demand according to the World Energy Outlook. Looking at the longer term and the Phase 2 of the transition, which is the scaling up of hydrogen, this is now looking even closer than it was last year as costs are falling faster than we had anticipated. The levelized cost of hydrogen is driven by the cost of renewable electricity, the cost of electrolyzers and the load factor. As we see renewable power reaching new lows, the key change compared to last year is a 15% lower cost of electrolyzers already for 2020. This 15% reduction has been achieved as the manufacturers are envisaging and looking to the great demand visibility that they're now getting because of the policies. We now think that with around 25 gigawatts at a global level of incremental and predictable electrolyzer demand, we could get hydrogen production costs -- green hydrogen production costs down to $2 per kilo, which is a tipping point when it becomes competitive in several applications. This can be achieved before 2030 with 25 gigawatts of electrolyzer demand in areas where favorable renewable conditions exist like the Middle East, North Africa and other desserts for solar. On top of production costs, the hydrogen will need to be transported, distributed and stored and used in refilling stations before it gets to the consumer. With regards to transport, pipelines are by far the most convenient way to access large amounts of renewable energy from distant locations. This BloombergNEF analysis shows, how by 2050, hydrogen imports to Germany from North Africa will cost around $1 per kilo and will be cheaper than the hydrogen produced locally from offshore wind farms, the blue hydrogen and much cheaper than the hydrogen imported via ship from the Middle East or other remote locations, with pipeline costs around 1/10th of shipping costs when it comes to hydrogen. Based on this and on other studies, the cheapest way for Germany to source green hydrogen is potentially through our existing Italian pipeline network. We believe that hydrogen will become competitive in a number of sectors faster than expected. Broadly speaking, we think that rail and heavy transport will switch at a delivered cost of between $5 and $7 a kilo, including transport, storage and distribution, equivalent to an underlining production cost of $2 to $3 a kilo. Next up are the industries that would use hydrogen as a direct feedstock, so refining and steel DRI, where it becomes competitive in the 2030s. The third block to become competitive is where hydrogen would be used for thermal uses mainly instead of natural gas. This is not an easy hurdle to overcome, because natural gas is very competitive. But on the plus side, there are not many additional costs needed to deliver the hydrogen, as many of these industries are already linked to our gas grids and volumes are significant. So economies of scale are also significant. We would expect this third group to start to switch in the 2030s and through to the 2040s. The above projections are built absent policy interventions, which we expect will be there and will offer significant support to accelerate this. Of course, the policy support from Europe is moving strongly, and now Europe targets 40 gigawatts of electrolyzer capacity for hydrogen by 2030. The 6 countries that have so far published their own strategies or guidelines already account for 30 gigawatts between them. The sectors that are being targeted are largely mobility, where the cost gap between diesel and hydrogen is smallest, an industry which can provide significant volumes with minimal infrastructure requirements. Both Portugal and Italy, also foresee a role for blending hydrogen in the gas grid, which is very interesting because it enables a rapid ramp-up in production volumes, and therefore, a decline in the price of hydrogen even before the consumption markets are developed. Such policies can speed up the transition considerably at very low costs. The good news is that compared to the early stages of the renewable transition, we can now bridge the gap to switching much more cheaply, because we can benefit from the 20-year learning rate in renewables and the dramatic fall that we've seen in their production costs. We expect specific policies to support green hydrogen production as well as incentives to help consumers switch to hydrogen potentially of different colors. Italy's hydrogen strategy guidelines were published yesterday. The country targets a 2% share of the energy mix by 2030 and up to 20% by 2050. That amounts to around 700,000 tons of hydrogen by 2030 or 23 terawatt-hours with investments of EUR 10 billion. This will be partly generated by electrolysis in Italy with a target of 5 gigawatts of installed capacity by 2030 and will be destined for industry-heavy transport and trains, and hydrogen will be blended into the natural gas grid up to 2%. A 2% blend by volume is already possible throughout our network and including our underground storages without any significant investments. The Italian strategy document also highlights that Italy can benefit from well-developed existing gas infrastructure and that it should leverage its geographic position to import hydrogen from North Africa and be able to export it to the rest of Europe. The development of hydrogen has significant implications for infrastructure. We have scenarios run at 18% and 20% penetration by 2050. And because of hydrogen's lower density, volumes of gas in our pipelines increased significantly. They rise to over 90 bcm from 70 bcm today at a 25% share. And even at 18%, they would be higher in 2050 than they are today. We expect to see a coexistence of natural gas with CCS of biomethane and of hydrogen in our mix, with the former decreasing and the latter increasing over time. We already started advanced work to determine how we will deliver this transition through our infrastructure, including storage. We expect large volumes of green hydrogen to be produced in our sunny south and consumed mainly in the north. Our infrastructure will add significant resilience, flexibility and security to an energy system based on intermittent and faraway renewables. Let's now move to our plan. Our CapEx plan for the period has increased by 14% to EUR 7.4 billion. Of this EUR 6.7 billion is in our core infrastructure, up from EUR 6.1 billion last year. The increase is largely driven by EUR 640 million of additional investments in maintenance and replacements required to offset the increasing aging of our network, an additional $90 million in IT to increase the safety and efficiency of operations. We're also envisaging a reduction of EUR 200 million in development CapEx, mainly due to a rephasing of the Sardinian project. In this plan, we have nearly doubled investments in the energy transition to over EUR 700 million. These are not part of our RAB, but we select projects and businesses with an accretive risk/reward profile compared to our regulated business. These businesses have collectively already become EBITDA-positive in 2020, notwithstanding COVID, and they will ramp up quickly and exceed EUR 150 million of EBITDA by 2024. The main scenario assumptions underpinning our plan are a stable WACC after 2022 and a deflator of 0.9% for our RAB. We're not yet including in our numbers any effect from last week's De Nora announcement and its possible contribution as a seed asset to a new energy transition investment platform. Approximately 50% of our CapEx is hydrogen-ready. This is defined as the replacement and development investments in our assets carried out in accordance with hydrogen-ready standards. A further 9% is dedicated to investments, which increase efficiency to reduce our Scope 1 and 2 emissions, 7% to digitalization and 9% to the new energy transition businesses. Approximately 40% of our total CapEx is taxonomy aligned on the basis of the still evolving criteria, a classification, which has recently been certified by a third party. Looking in more detail at the CapEx plan in Italy. This includes more than 1,170 kilometers of pipeline replacements in the next 4 years. Our dual-fuel compressor stations, which provide flexibility to the system as we can choose whether we use gas or electricity to compress gas. Third, looking at Sardinia, the project has been rephased to start with supply as the first section of the backbone. The plan now envisages the construction of a virtual pipeline to bring LNG from Panigaglia and all 3 regasification facilities to Sardinia, with the gas coming into a floating, regasification and storage unit or more units linked to the first parts of the backbone that will be developed gradually. So finally, Sardinia can get access to gas with a project that sees everyone in agreement. We confirm our initial view that 70% of the piping is already 100% hydrogen-ready. We have defined procurement standards for the hydrogen-ready mechanical components and pipes for replacements and for development work. We're continuing to work on blending hydrogen and natural gas grid. And as mentioned, we have very recently determined that a 2% blend is now technically acceptable throughout the network, including storage, without any intervention. We have tested the world's first hybrid hydrogen turbine for blends up to 10%. And this turbine will be installed in our gas compressor station in Istrana next year. We are engaging with industrial users, users of hydrogen, our clients, people connected to our grid on the possible use of hydrogen in their thermal processes, including steel mills and power plants and other uses of hydrogen. Lastly, we are promoting and sharing knowledge and technologies among the core group of almost a dozen TSOs in what is called the hydrogen gas asset readiness initiative, which is proving to be a very effective collaboration among the peers in Europe. Digitalization is another key investment priority with nearly EUR 500 million earmarked in the plan period to become what we think will be the world's most technologically advanced gas TSO. We will develop world-class data-driven infrastructure also with the support of top technology partnerships. We're making our assets more secure and more efficient. And we aim to sell our capabilities for dual-fuel management and network optimization to customers worldwide through Snam Global Solutions and also through some of our technology partnerships with our providers. The key area of work in our core business is the replacement of our fully amortized pipelines. A large share of our network was built in the '70s. And given an amortization time of 50 years, that means that these investments are exiting the RAB as we speak. Indeed, we have now over 9,000 kilometers of pipes, which are already fully amortized. And despite replacing almost 1,200 kilometers over the planned period, this figure will remain at the same level at the end of 2024. At this level of replacement, the trend is set to accelerate. We have always taken a conservative approach when it comes to replacements, prioritizing the pipelines on the basis of technical considerations. At the same time, we're working with the regulator to determine the appropriate replacement framework. Given the complexity of some of these discussions, we now foresee this constructive dialogue to run into 2021. Looking forward, our replacement requirements are a key driver of our long-term RAB growth. We have accelerated our growth in the plan to above 2.5% per year. Looking 20 years ahead, we expect 2.5% a year to be a floor, as this would still leave us with over 11,000 kilometers of fully amortized pipeline by 2040. To be clear, our 2.5% floor is calculated, assuming only the necessary replacements from a technical point of view on the basis of our past experience and our continuous network assessments. This growth does not include any investments specifically on hydrogen. We will only replace and/or repurpose our assets for hydrogen when and where it will become necessary. Overall, the cost of transporting energy on our network is very low and by far the cheapest compared to other energy sources, be they electrons or molecules. Going forward, this cost advantage will continue to improve relative to other decarbonized options. Moving to our new energy transition businesses. Our first biomethane plant is starting up in December. We now target 64 megawatts of capacity by the end of the plan, up from 42 meg in the previous plan with an investment of EUR 220 million. Expected returns are low double-digit with a lower risk profile, given that they're backed by long-term Italian incentives. In energy efficiency, we have acquired companies with specific competencies in key segments. Over the planned period, we will develop a pipeline of projects in the residential sector also supported by the long-term fiscal incentive; install 70 million of distributed energy system, CHP, photovoltaic and fuel cells; and support deep renovation of public administration buildings. Overall, we see investments of EUR 200 million producing stable long-term contractualized returns. In sustainable mobility, we aim to have more than 150 CNG and LNG stations at the end of the plan. We will also develop 5 flagship hydrogen stations. We will increase our exposure to energy for transport, investing in 1 micro-liquefaction plant and the upgrading of truck loading facility in Panigaglia. Overall, investment in mobility will be around EUR 150 million. Lastly, in hydrogen, we are ahead of the curve. Our plan is focused on getting exposure in the first in-the-money applications, consolidating our leadership in technology and positioning ourselves for the larger-scale developments and policy-funded segments as they arise. Initial investment is EUR 150 million in the planned period, and we expect to have positive EBITDA in this segment by 2024, even before any policy support. Looking at our hydrogen strategy in more detail, a key project is to convert diesel trains to hydrogen where electrification is not possible. We have an agreement in place with the national railway system as well as with train manufacturer Alstom. This project accounts for the majority of our hydrogen CapEx in the plan at the moment, and we expect the first train already in 2022. This project is in-the-money already without subsidies, because diesel is expensive and because the logistics of supplying hydrogen to trains is simpler than supplying hydrogen to other transport vectors. We are expecting other segments of the market to become remunerative through policy support following the publication of the Italian hydrogen guidelines. Hydrogen projects will also be funded by the Recovery Fund and other European and national instruments, such as the Important Projects of Common European Interest known as the IPCEI facility. We are participating in the discussions to select projects, seeking to make them solid and bankable. These would represent an upside to our plan. With regards to hydrogen technology, we have recently struck 2 important partnerships, one with Industrie De Nora, a leading company on electrode and water technologies and with very promising hydrogen upside; and the other with a leading PEM electrolyzer manufacturer, ITM, in the U.K. Through the acquisition of the investments in these companies and the commercial partnerships, we gain exposure to the fastest growing electrolyzer segments with complementary alkaline and PEM technologies. The acquisitions will also support the ramping up of our hydrogen business unit, as today, having access to leading technologies and competencies is crucial to win projects, especially when all concepts are a first-of-a-kind and solutions need to be worked through and tailored and custom built. A meaningful part of the De Nora stake is expected to be conferred to a new investment platform focused on the energy transition. Snam will be the anchor investor. And the launch of this vehicle will enable us to enhance our exposure to the energy transition companies, assets or projects through a limited and ring-fenced investment. We expect this platform to be launched in 2021. Turning now to our international strategy. We have a great portfolio. By the end of the planned period, dividends received by the Austrian, French and U.K. associates will be far higher than the price we paid for them, meaning that the acquisitions will have been fully paid back in a short time scale. For more recent acquisitions such as DESFA and ADNOC, by the end of the plan, we expect them to be around 50% paid back already. As a whole, we expect our international portfolio to deliver solid earnings and cash returns above 10% a year on average and offer diversified growth opportunities. Looking at our mature assets in Europe. As indicated already last year, contribution from our Austrian associates reflects the expiry of long-term contracts in 2022 and 2023. We're working to mitigate such effects with shorter-term and more flexible contract, products as well, as gas flows are expected to remain stable in Austria. Meanwhile, Teréga is entering biomethane in France and is well positioned on hydrogen, given its interconnection potential with Spain. We also have assets exposed to new gas consumption and growth in gas consumption. These include TAP, which will start contributing to earnings by 2021 and the recently acquired stake in ADNOC. DESFA also benefits from growing gas consumption in Greece as well as incremental supplies to the Balkans also via LNG. Finally, through our dedicated asset-light presence in China and India and the commercial reach of Snam Global Solutions, we can consider opportunities in areas with attractive gas and green gas prospects. Finally, the key piece of news in our associate portfolio is that TAP has been completed and delivered on time despite COVID. We materially contributed to its success by appointing key people such as a former head of our gas assets who became the CEO of TAP and by supporting the company in establishing our relationship with local communities providing local content. Some world-leading technologies have been applied and integrated to absolutely minimize the environmental footprint of this project and even accelerate its executions. And we are very proud of what Snam has been able to achieve in Puglia. I will now hand over to Alessandra for a closer look at our financial structure, capital allocation approach and our main targets.

Thank you, Marco, and good afternoon, everybody. Looking at our financial structure, focus remains on derisking our business plan and preserving the solidity of our balance sheet. Cost of that is expected at circa 1.2% over the plan horizon, slightly below last year assumption, thanks to the actions already implemented to lock in favorable market conditions and the improved market scenario, both in interest rates and credit spreads. Moreover, we believe that further opportunities of funding cost saving could be achievable, thanks to further treasury management optimization, the records to uncommitted credit lines and commercial phases, an opportunistic approach to managing our maturity profile and further diversification of investors, thanks to increased share of sustainable financing. Snam's solid credit rating quality is confirmed by the fundraising progress in the last few months, notwithstanding COVID. It totaled to EUR 1.2 billion at an average tenure of circa 6 years and an average cost of 0.3%, while still having seamless access to the uncommitted credit lines and commercial paper market. In this regard, we like that our credit metrics remain comfortable within the threshold set by the rating agencies for rating one notch higher than our official one for Moody's and Standard & Poor's, even factoring in the full cash out for the acquisition of De Nora stake. Aside from numbers, as customary, we've discussed this transaction with rating agencies who appreciate the sensible and disciplined approach on technology related to energy transition and decarbonization. They like the fact that Snam will retain exposure to R&D and technology in a key space such as hydrogen, while limiting its capital deployment also in the context of the investment platform expected to be launched in 2021, protecting the low-risk profile of both its business and financial structure. We expect net debt to RAB, which will reach circa 58% on a rating-adjusted basis at year-end, to decline over the plan horizon, as in 2021, the guarantee related to the construction [ of stock ] will be released as a consequence of its entry into operation. Our ESG focus also drives our financing choices. Our commitment was reaffirmed in September when we joined the UN Global Compact CFO Taskforce, which aims at bringing together investors, issuers, banks and credit agencies to create an efficient market for SDG investments and capital flows and consistency in how to measure ESG KPIs. Since the beginning of our journey in 2016, we have sought to increase the share of our sustainable finance. Today, we stand already at 40%. This was achieved through the conversion of our revolving credit facility to sustainable loan with a bonus/malus mechanism, depending on the achievement of the KPIs, which are included in our management incentive plans. 2020 is the second year in a row that we benefit from lower margins, thanks to achieving those targets. On the fixed income side, Snam issued the first Climate Action Bond in 2019, followed by its inaugural Transition Bond just few months back. Our move from a Climate Action Bond to a Transition Bond was aimed at factoring, on one side, more ambitious and longer-term targets in terms of emission reduction both in CO2 and CH4 announced at the end 2019 as part of our last year plan; and the inclusion consistent with the taxonomy definition of new eligible category of retrofit of gas transmission network, whose main purpose is the integration of hydrogen and other low carbon gases. Our ambition is to raise the share of sustainable funding to circa 60% by the end of the plan, leveraging our new fixed income issuance out of our transition bond framework or at a sustainable like bonds and an amended and restated commercial paper program linked to an ESG rating, which allow us to issue up to EUR 2.5 billion of ESG notes. Our capital structure leaves us some headroom in terms of leverage, which gives flexibility for potential additional investments not included in our plan. We will continue to apply our strict financial criteria when evaluating any opportunity. As a reminder, we will only invest at or above the risk-adjusted returns available on our regulated organic CapEx, and we are committed to our current rating metrics and risk profile. Furthermore, we assess opportunities based on whether they enhance the value of our existing assets, allow Snam to play an industrial role and support additional growth and strategic optionality, but always in coherence with our ESG strategy and broader net zero vision. On the back of this criteria, we have increased our organic CapEx and carried out bolt-on RAB like acquisitions, invested in our energy transition businesses, expanded our international footprint and increased cash return to shareholders through dividend and buyback. Looking now at the planned targets. Tariff RAB will grow by an average of over 2.5% a year in the period, ahead of the prior planned trajectory, which was above 2%. RAB growth will support revenues, which also will benefit from the significant contribution of our new businesses. Our efficiency plan, which will reach EUR 70 million by 2022, a year earlier than planned, will also offset growing R&D cost. This will deliver EBITDA growth over the plan of over 3% a year. With EUR 700 million of investment detailed in the plan, new businesses will reach EUR 150 million of EBITDA in 2024, with a further circa EUR 50 million beyond 2024. Net profit will grow by 2.5% as a result of the growth in EBITDA, factoring in higher D&A linked to the growing investment plans on both our core business and new businesses. Cost of debt of that is assumed to be stable. We expect earnings per share to grow by over 3%. Consistently with last year, we are conservatively assuming a debt refinancing of the convertible note expiring 2022 with a subsequent cancellation of treasury shares. Let's now look more closely at 2021. We expect this to be a year of growth with an acceleration in CapEx. We see positive impact from RAB growth, and we are conservatively factoring a broadly stable output-based incentives. We're expecting an increase in D&A due to the significant ramp-up of our CapEx, higher R&D and business development costs for our platform. We're also expecting the contribution of new business from TAP, although more slowly than previously anticipated, owing to the COVID disruption. 2021 will benefit from the growth of the contribution from associate with the entry in operation of TAP and the contribution of ADNOC, partially offset by the regulatory vision for the Alstom associate and expected normalization of volume impact on tariff for DESFA. Overall, we expect net income to increase by 3% versus our 2020 guidance. Net debt will reach EUR 13.5 billion, driven by increased investments and working capital absorption of circa EUR 200 million, of which approximately EUR 100 million connected to our energy efficiency business. With regards to net debt to RAB, throughout the plan, we will remain well below 60%. Duration would apply next year as the TAP construction guaranty is released. Thank you for your time. I will now hand over back to Marco for his concluding remarks.

Thank you, Alessandra. The CapEx plan that we presented today only contains what is firm and visible and is not contingent on new policies or market evolutions. Compared to this, we see 4 areas of potential upside: first, an increase of RAB CapEx related to green gases; second, potentially new hydrogen projects supported by new policies; third, new biomethane opportunities nationally and internationally, also supported by new incentive schemes; and further growth leveraging our capabilities and product portfolio also in the circular economy, energy efficiency and renewables in Italy and abroad. As we gain additional certainty on potential investments and projects in these areas, we will update our outlook accordingly. With regards to the dividend, we confirm our previous policy of DPS growth of 5% per year to 2022. Our robust growth profile enables us to extend DPS visibility for a further 2 years, with a floor of at least 2.5% annual growth in the dividend between 2022 and 2024. This policy is based on our current plan and targets. In the next 2 years, we expect to gain greater visibility on policies and regulation and opportunities that are above and beyond the plan. Should that lead to a higher structural EPS growth, this would be reflected in the 2023 and 2024 dividend. Ladies and gentlemen, we've come to the end of our presentation today. The transition to a low-carbon economy over the next 3 decades is among our biggest challenges. For investors, the question is how to gain exposure to what will undoubtedly be a multitrillion euro investment cycle lasting many years. And it will be important not to repeat mistakes that have been made in the past. We need a no-regrets strategy that is relentlessly focused on developing future-proof assets and technologies. We need a new collaboration model where different players come together to deliver complex groundbreaking projects. To deliver the changes that we need investment in the energy transition must be sustainable and it must deliver incremental benefits to society and avoid systemic disruption and excessive costs. Snam is an exceptional investment opportunity in this environment for 4 reasons. First, we have a solid and future-proof asset base that guarantees long term, visible and predictable cash flows. Second, we have a distinctive set of new businesses that capture growth and create value in the energy transition. Third, an international footprint exposed to areas of the world that are central in the energy transition. And finally, the balance sheet and cash flows to guarantee a solid credit rating and growing shareholder remuneration. Thank you very much for your attention. Alessandra and I will now be pleased to answer any questions.

[Operator Instructions] The first question is from Javier Suarez with Mediobanca.

2 or 3 questions, these are on the medium-term view or long-term view for the company. I think that's probably the thing that has surprised me the most is the visibility that the company has given on the RAB growth to 2040, and that is at 2.5%. That is a significant commitment by the company. And I think that you have mentioned in your presentation that, that is simply related to the substitution of the existing pipeline. So the thing that I would like to ask you is to try to give us some more granularity on what the hydrogen opportunity could put the food on the table for a company like Snam. What is your latest view on the opportunity that hydrogen means for the necessity to upgrade significantly the CapEx of the company in an extremely difficult time to make these -- the existing network of hydrogen compliant? That is the first question. The second question is on the dividend policy. So the -- what the company has done is to maintain the dividend, I mean, visibility for 2 additional years, but kind of scaling down the dividend growth commitment, while the EBITDA and net income growth are similar. So can you kind of help us to understand the rationale for that decision? Is that because the company sees plenty of opportunities and believes that there is better use of capital rather than paying out dividends till 2023 and 2024? So you can help us to understand the rationale for that. That would be appreciated. And the third question is on regulation. So obviously, the hydrogen market has to be built. But I just wanted to ask you your latest conversation to the regulator or your proposal to the regulator on how the market should organize. And I'm particularly interested on what do you think -- how do you think the role of the electrolysis should be, if electrolytes should be part of the regulator -- the regulatory asset base? And also, you can give us some update on regulatory conversation to get some [indiscernible] assets beyond their useful life.

Thank you, Javier. That's a rich set of questions. So the first on the granularity of hydrogen. So to be clear, the plan does not include any subsidies on hydrogen. So the 2.5% RAB growth in the plan and beyond is based on a business-as-usual steady state. Then there are incremental RAB opportunities potentially if we need to accelerate the hydrogen readiness. We cannot quantify these in euro amounts. We have said that 70% of our pipes are hydrogen-ready. So a lot of the CapEx would be to the accessories above the ground. But it's hard to tell now how much and when that additional money will be spent, because what we need to do is understand how much methane with CCS either at the entry or the exit of our system, biomethane and hydrogen will coexist. So what we're doing is we are mapping extensively our network. We expect there will be a period of coexistence, and there will be some planning opportunities depending on the work we're doing on membranes and other technologies. So there will be hydrogen- and biomethane-related upsides on the RAB. But on the hydrogen business unit, there will be significant potential upside as what we have in the plan now is just what we see as being in-the-money with no subsidy. So there's, let's say, 2 different pockets of potential upside. One is on the RAB linked to how the coexistence of biomethane; methane with CCS; potentially CO2, because CO2 needs to be transported as well; and hydrogen all interplay. This is not something we will solve soon. I think it will require a couple of years of working with regulators in Europe to understand what other TSOs are doing, working with customers and understanding which technologies take off in which time horizon. Then you asked us about our dividend philosophy. It's always the same, Javier. We don't think that over a long period of time, we should be growing the dividend more than net income. We've come from extraordinary 4 years where net income grew a lot faster than we expected. This means that we've been able to pay a high dividend -- a very high dividend and dividend growth, and at the same time, bring our payout, as you remember, from our early discussions 4 years ago from a level where we were not so comfortable to a level, I would say, of absolute comfort today. So that 2.5% kind of aligns with our long-term growth outlook, absent any of the upsides that I talked about. So there's no change in philosophy, no change in approach. We have financial flexibility potentially to pay even more, but I think it's right at some point to align the dividend growth to the underlying sustainable long-term net income growth. When it comes to regulation and how the hydrogen market should be organized. I think electrolyzers will need to be incentivized if this is in the form of putting them in the RAB or in the form of electrolyzer-specific incentive or in the form of integrated hydrogen, green hydrogen production incentive, we still don't know. We are active in a number of high-level dialogues with the European Commission, with different member states, with our own institutions and regulators. And I think 2021, as I've indicated earlier, is going to be a year where a lot of collaboration is necessary to determine what is the best way to incentivize this key part of the value chain. What is very clear to us is that we will only invest in this and other opportunities when we see predictable, visible returns that are higher or greater than what we can achieve on our normal regulated activities. I hope I've answered your questions.

The next question is from Meike Becker with Bernstein.

I think I go with 2. The first one is on your Slide 24 and 28. So it's essentially your international footprint and the new businesses. Particularly, I'm wondering about the energy efficiency going into perhaps electricity a little bit and your expanding into China and India. So if you could sort of elaborate what your presence is today in India and China and what plans potentially you see? And relative to what you're doing today, if their appetite to expand your footprint into electricity, and I don't mean the operating network or something. I'm thinking perhaps appetite to accelerate or hedge somehow in the green hydrogen production, for example, in North Africa, which would help your core business? So that's question one. Maybe lots of questions in one there. And the second question is quite simply on your efficiency. If you could sort of, like, elaborate what is happening in terms of efficiencies across the plan or if something that changed materially? Or is that steadily progressing?

Thank you, Meike. I will try to answer your first questions and then ask Ale to step in for the cost production and the efficiency program. So on the new businesses, the -- in India, you may have seen, we've recently signed some MOUs. India is a market that has 2 very important trends. One is a strong desire to move from diesel to gas when it comes to transport. Just to give a number, India has most of its trains running on diesel. India has 80 gigawatts of diesel-fired electricity generation units. So there's a big opportunity to invest in liquefaction, in LNG infrastructure and LNG for transport, in all those areas, in CNG, where we have developed and are developing niche technologies. So we hope to be in that market with Snam Global Solutions and looking at projects to deploy our capabilities. When it comes to electricity, if you take a project like the trains project that I mentioned, the train company simply expects to be delivered green hydrogen when and where and at the volumes that they require. So we need to worry about producing it, transporting it, storing it, modulating it and investing in the infrastructure to deliver that. A big part of a program like this is around renewables to produce that green electricity. If the train company, in this case, wants to say that it's 100% green hydrogen, the only way to physically do that is to have dedicated renewables for this. So we have several options. We can purchase the renewable energy and then dedicate that to the electrolyzers. We can build in case there's new -- probably new energy needed as the volumes scale up, we can partner with people who already have and who are developing renewables. I think the model is going to be a combination of all 3, where we may need to be investors, we may need to partner, we may need to simply buy it from existing sources. So it's early, as I mentioned, to say, which form and which model these partnerships will take. What I can say is that listening to my peers and other executives, I think there's a consensus building that there will need to be a greater degree of collaboration. When it comes to North Africa, I showed the chart from Bloomberg. That is very striking. Their analysis is the same as others. The cost of moving green hydrogen to Central Europe, let's say, because the economics are the same, is a 1/10th via pipeline. So this offers very significant opportunities. I don't think this is imminent, because we don't need those volumes of hydrogen today nor do we need them by 2030. But I think that's a really concrete long-term opportunity that we are beginning to work on and should continue to be developing. Sorry, looking at my notes, Javier, I didn't realize you -- I missed to answer the fully amortized pipeline. So I don't have much to add. We've said in the past that we were in dialogue with the regulator. I must say that since green gases have become the consensus and so our network -- long-term life of the network has become now the consensus in Europe with the Commission putting that in writing with the Italian and other national strategies, putting it in the highlights that gas infrastructure is a core element of decarbonization. That alters a little bit the time horizon with which we look at these substitutions. And the discussion is no longer just about give me an incentive to postpone, but is naturally entering into as the conversation with you as to what is the future going to look like, what do we need to replace by when. And so it's a more complex discussion that we will not close this year and that we expect will continue into 2021. Ale, over to you for the cost efficiency targets.

Thank you. On the efficiencies, we have slightly increased the target vis-à-vis last year plan and anticipate the year by which we intend to achieve such target to 2022 versus 2023. It's kind of the same story, as we said. It's a long list of small initiatives that are instilling into the company a disciplined approach in how we spend money on things that are really necessary and effectively all of this discipline has led to create the room on one side to offset the demerger synergies and one-off costs that we inherited from 2016 Medalia decided to create flexibility to accommodate for the investment of the start-up of our new businesses without penalizing the overall profitability that we have delivered to our shareholders. Given a little bit more detail of this EUR 70 million remains, let's say, 60% to 70% related to corporate cost and the rest to operation. And as an additional element of information, that means that if you look at our core perimeter, these reduction of costs will allow us by the end of the plan to have slightly lower cost in nominal terms, whilst at the same time, as I said, during the presentation, revenues and costs for the new businesses would grow to deliver this EUR 150 million EBITDA that we have indicated by 2024.

The next question is from Harry Wyburd of Bank of America.

So first one, sorry to reprise again this sort of any question on the pipeline replacement. So I just wanted to understand a bit more about how it's decided which pipelines you can -- as you replace. So I guess, in some ways, presumably, you would want to replace as many as possible to see what they got in order to the old pipeline and just getting OpEx allowance on it basically you're not amortizing, if you replace it, you get your CapEx -- you return annual allowance. So I guess when you go into these negotiations, presumably, you're sort of reminded to push for more replacement. So I just wondered what actual criteria is the regulator or maybe the government you decided wanted to make, given that there's so much focus on infrastructure, investment and GDP multiplied in every other code to actually to ask you more pipeline replacement than we're currently seeing, going through the markets and or over two months and then wrap up. And second one is very big picture. Just given you've got your affiliate investments in gas transmission, you've got your sort of new energy technology businesses, you've got your new hydrogen technology businesses. In total, if we just look at things there are lots to do with gas transmission, what percentage of your net income are these investments going to be into 2024 and perhaps, even in terms of [indiscernible] how much of the business over the next few years is going to gravitate towards kind of nongas transmission pipe activity? And then third one, again, very big picture there, looking at things like De Nora, you mentioned high-growth rates. Clearly, it's in an area that's getting a huge amount of investor attention, its huge target, its another great investment, but I guess when you're combining that business with your core gas transmission business, is there a risk that you get and other than conglomerate discount here. These are very, very, different business models and I know you mentioned you're sort of spinning -- in terms of spinning this asset into a separate investment fund. But is there a case where you're going further than that and say, look, we need to have little bit subsidiary perhaps to house all of these technology-type investments handling profile, the transition business sort of they just get more accurately valued by the market because I guess it might be a little risk there but all of these things get lost in some other parts.

Okay. Thank you, Harry, for your questions. So on replacement, there's no specific rule. We are in a very, I would say, comfortable place because we've had a very prudent approach to replacements. We've only replaced what we felt was absolutely necessary. And the regulator really appreciates that. We could have replaced more and we could replace more, and we could be here today with a greater growth plan for replacements in the next 4 years and beyond. So we are believers in doing what's good and right for the system and not look at our short or medium-term interests. As I mentioned, looking at today and looking at even 2040 and beyond, the cost of transporting energy in our system is really, really low in percentage terms today and in percentage in relative terms tomorrow. So we don't have, let's say, pressure from an impact on consumers' point of view. At the same time, we're not using any rhetoric to say that we should boost replacements to boost GDP. We are, however, saying that projects like Sardinia are absolutely necessary to deliver cheaper and more sustainable energy to people in Sardinia, who are now still living off diesel and GPL to heat their homes. So that's really what's governing our discussion is a prudent approach, a systemic approach. And what we have is a 10-year plan that we present on a rolling basis and what we provided until 2040 is a kind of continuation of that trend where we replace what is strictly necessary. Of course, as time goes by, and as Italy has some own geological complexities, some of what is necessary becomes greater as the overall network becomes older. When it comes to affiliates, new energies and conglomerate discount. So for the new businesses, I mentioned a target of EUR 150 million of EBITDA. These are startups that are already breakeven today. If you assume they're breakeven now and get to EUR 150 million, you get a sense of the very steep trajectory thereon. We have invested a lot less in these businesses and what they would be worth today. And that worth -- that value is going to become visible as they get to meaningful numbers towards the end of the plan. We provide aggregate view for our associates that will reach from net income contribution because EBITDA is not relevant there, over EUR 200 million. I think it's around EUR 220 million by the end of the plan. So if you add up EUR 150 million of EBITDA EUR 220 million, I think you get to something which is increasingly meaningful. Then the new businesses also add RAB in a way because every biomethane, every CNG, every LNG connection adds to the RAB. And they also contribute to the green gassing of our network as the new businesses succeed, new gases succeed and our network doesn't become a transition infrastructure, but becomes a forever infrastructure that makes that whole replacement discussion a lot more interesting. So I don't think we're at the point of thinking of conglomerate discount. I think this new energy investment platform that we talked about is already a very disciplined, ring-fenced say, vehicle in which we replace a big parts of De Nora. That is really a very attractive asset in itself and really can help us expand our hydrogen leadership in many respects.

The next question is from Alberto Gandolfi with Goldman Sachs.

The first one is on hydrogen. I was wondering, I mean you've been a key driving force of the butane in the hydrogen in Europe and one of the key founding members, if I can say of the EU backbone project, which is about EUR 40 billion just for the reconfiguration of pipes and compression stations without even calculating storage. So I guess my question is, can you share with us what percentage of this figure could be attributed to your core market in Italy? And should just assume it's about 15% of that, and then we put maybe storage on top. I'm just trying to clarify, when you say 70% of your pipe is hydro generated, I wonder, so what the investment need to do on the compression station, on storage, the different types of pipeline that you need to reconfigure. So maybe combining the two and given in a differential big way. The second question is on the nonregulated businesses of EUR 150 million EBITDA, would it possible maybe to break down just the main big components which is the 2, 3 largest. And then perhaps give us an indication of what margin net income to EBITDA you'd be expecting from those. And last, on RAB growth, 2.5% floor growth per year, very healthy number. Thank you for that. Can I ask you what inflation assumptions have you baked in that type of growth?

Thank you, Alberto. So on this EUR 40 billion, I'd be -- I get this question a lot. I'd be very tempted to just work out a percentage number. That would be an easy solution. But this EUR 40 billion is a kind of a static figure. This assumes we go from where we are today to a fully hydrogen world that says, what do we need to change? What happens in between is incredibly complex, as I was trying to explain. We will have an overlay of biomethane, methane, CCS methane. So kind of blue hydrogen, CO2 that needs to be transported as well as hydrogen. That starts from 0 and will increase gradually first in blending and then on its own. And no doubt, we will see the development of dedicated hydrogen pipes to anticipate the overall market to get perhaps to specific districts. And the big question still to be resolved is what happens in cities, what happens at the distribution level and at what pace? So I'm afraid that we are working very hard. I don't think we will have an answer soon because we need to map all the bits of the puzzle to get there. But if you think that in our guidance that we gave on 2040, we said that with 2.5% growth, we're still left with 11,000 kilometers of pipelines that eventually will need to be replaced in a way sooner or later. If you take the numbers we gave in the past as between 1 and 3, we're now using 2.1 or 2.2 as an average point. You can easily get to a CapEx amount potential for Italy that is not related to that EUR 40 billion, if you see what I'm saying. So there's a lot of moving parts. I think the bottom line is that we see that RAB growth, by the way, has 1% inflation embedded in it at 2.5%, excluding anything to do with hydrogen. And then we see different bits of hydrogen opportunity as we approach new districts as we build, we or other people build electrolyzers that may or may not be connected to our pipe. And so it's a much more complex and dynamic picture. Of course, Snam has a big share in the European market between our Italian and our associate pipelines. So you can easily work the kind of the percentage of that EUR 40 billion, but that won't get you to what you're trying to calculate, which is the real kind of bottom line CapEx. So in terms of the new businesses, the way you can look at it is, I've said hydrogen will reach breakeven. I think that's a heroic effort because in such a new market in such a short period of time. And I think in the breakeven to be fair to the business unit, let's assume it's break even at gross margin level, but that's already quite heroic because it's with no subsidies. Then we have the other businesses whereby methane, we said double digit return, and you have the CapEx amount there. So I think you can easily work out where we are. Energy efficiency and mobility, you can use as a floor or risk-adjusted regulated returns. The margins are good. Of course, they're not as good as the regulated margins at 80%. But Ale, correct me if I'm wrong, I think behind those EBITDA figures, we have north of EUR 600 million of revenues or something like that, maybe between EUR 600 million and EUR 700 million of revenue. So it's good margins, not as rich as the core business.

Marco, forgive me for the follow-up. I was wondering on the new business, if you can help us also. This is very helpful, in a way. What would be net income from businesses. And maybe one comment, if you allow me structure. In a world where lot of companies assume a normalization in the world, I mean, it's interesting to see you're using 1% inflation. Some people might argue, could go back to 1.5% or 1.75%, so essentially long-term at 3% roughly.

Okay. Thanks for the comment. We'd like to stay on the prudent side. Ale, do you have anything to say on the -- I think net income is around EUR 50 million, maybe where you have biomethane with higher D&A and energy efficiency is, again, has some amortization as well. So I think you should think about it as kind of EUR 50 million net income -- a bit south of EUR 50 million.

The next question is from Enrico Bartoli from Stifel.

First of all, I have a general question on hydrogen. There are a lot of discussions within the industry what kinds are the model, the hydrogen industry will take if there will be development of capacity and total capacity spend or the territory or big capacity concentrated and then the production lines is there to be transported to the production site. Also, how much will be produced in Europe and the opportunity to import from, I see from the Slide 15 from the North Africa, but you mentioned also in the past, the potential from the Middle East. So I was wondering what is your view, the possible scenario that which this industry could develop over the next year. And second question is related to Sardinia. I was wondering how much you include in terms of CapEx related to the investment in Sardinia? And recently, there were many discussions about, actually, the backbone is losing or not, see that you include already some CapEx there. If you can update us on the state-of-the-art on this topic. And the third one is on the associates of the guidance that you gave on stable contribution in '19, the contribution was around EUR 200 million. If you can give us a non-precise, hint or what you expect in 2024, if this is the level that we can assume.

Thanks, Enrico. So I will answer the hydrogen model and the backbone, and then I will let Ale deal with the associates and with the breakdown of Sardinia. So I think it's early to tell. I foresee a model where we will both need to import hydrogen from outside of Europe because I expect that nimbyism will continue and the gigawatts of new renewables that are necessary. I just don't see where we will build them. There's a growing opposition to renewables. If I look at Germany, they have to get out of nuclear. They have to get out of coal, and they are not having a lot of growth in their own domestic renewables. So there will be an opportunity and a need to import significant volumes of hydrogen. So when you start thinking of import, you're like where do we import from? Well, like for natural gas, but even more because it's less dense and much more expensive to liquefy. The cost advantage I talked about is 1 to 10. So wherever possible, we will look for places and parts of the world where we can pipe it, whether it's Eastern Europe, whether it's Southeastern Europe, whether it's the Middle East with new projects, whether it's North Africa, and the same will happen for other parts of the world, where there are significant spaces available with renewable potential, whether it's wind or sun. And of course, this is also true for offshore wind. The potential is to create aggregate hydrogen and transport. I also see a model where if someone is building a hydrogen refueling station in a remote area, eventually, over time, if there's space, it will become interesting and cheap to produce dedicated renewables for that petrol station. If there is a significant area, which is neighboring, if there's maybe a wind turbine that's next door. I see residential projects that have hydrogen at the home, manufactured at home with solar in the summer. So I think we will see an emergence of several models, and I think there's space for all these types of models. Of course, what's important is that we don't make any bets too early in the game. And I think Europe is really coordinating the efforts by having a lot of conference calls, a lot of dialogues, a lot of private public partnerships. And I think it's a -- is a great investment mechanism because it forces European countries to collaborate and to share. On the blue versus green, as I mentioned, I think there will be necessary of having blue hydrogen to get the market going. And certainly, Germany and the U.K. have told me that they're looking at having significant amounts of blue hydrogen in the mix for a number of years, which is not a short period of time in their intentions. So I think Europe will need to again move in a coordinated way. When it comes to the backbone, we are bringing gas to Sardinia. That's the good news. It's happening by 2024, the latest. We have the opportunity to have a project now that doesn't have the opposition that you are referring to. We are not talking about an extensive point-to-point backbone. We're rather talking about parts of backbone that are built around the clusters of demand with potential offshoots, whether it's dedicated smaller lines or trucks to deliver gas to areas that maybe have very low demand. And so LNG is a good way to move gas around as well. So we have that opportunity. Ale maybe, if you can give more details on the cost?

I think you rightly referred to approximately EUR 200 million of contribution from associates in 2019. These were also including, as we commented in the past, one-off effect, which we are very significant for DESFA, which accounted for approximately EUR 30 million, which as we said since the very beginning, the normalized contribution for DESFA is something that we've always expected to be in the EUR 10 million to EUR 15 million. So we are benefiting from an incredibly positive scenario, which is accelerating tariff recovery from the past, which will normalize in due course. And 2021 is actually, as I commented before, the first year where this is going to happen. And the same when it comes to Teréga, there were one-off effects, which was normalized, taking other EUR 10 million, EUR 50 million off. So if you take those number, you normalize for what are one-off and then you have the gradual reduction that we have commented on, on the Austrian, then you have, of course, the positive contribution of TAP and of ADNOC. And overall, the contribution of our associates is, as Marco said before, around EUR 220 million, slightly above that number. So it will go up as a portfolio, but with decent contribution in 2024 versus what we had in 2019.

The next question is from José Ruiz from Barclays.

I just have two. First one is you mentioned EUR 500 million in this -- CapEx in the digitalization. I was wondering if these hare RAB related? So I'm guessing, the point I want to get is from your EUR 6.7 billion investment plan, how much is not RAB related? And the second question is a bit a follow-up on something you said before. You were mentioning 2021, a critical year to find -- if I understood correctly, incentives for electrolysis. My question is basically, when is the debate about regulation on infrastructure -- hydrogen infrastructure is going to take a place after that, 2 years later.

Thank you, José Ruiz. So the technology investments of EUR 500 million are in the RAB. And what's outside of the RAB are the EUR 700 million for the new businesses, that's our CapEx breakdown. When it comes to hydrogen regulation, I think in a normal situation it may take 2 to 3 years. I think there's a strong desire from very top policymakers in Europe and in member states and around the world to accelerate this. So I see very rapid pace. I see a lot of efforts to really come to some coordinated views. There was a conference call last week. There's another conference call this week. So hopefully, by the end of 2021, we have already greater visibility on the direction of travel.