The Italian gas TSO Snam adopted a medium-term plan covering the years 2022-2031 which envisages investments both in the development and maintenance of pipelines and storage facilities and in the realisation of the «Italian Hydrogen Backbone» to support the creation of a national H2 market and to export the additional volumes available from domestic production and import. Within such plan, according to which there could be over €20 billion of investment opportunities in 2022-2031, in late January 2024 Snam released the «2023-2027 Strategic plan», that provides for €11.5 billion in total investments of which €10.3 billion are directly related to infrastructure development (Snam 2024). €7.4 billion are earmarked for the gas transport component, that includes the construction of the «Adriatic pipeline» to increase the south-north gas and, in the future, hydrogen transport capacity; €1.4 billion will be used for expanding and upgrading storage sites; €1.5 billion dedicated to the purchasing and installation of two LNG regasification plants4 and the related infrastructure. However, by considering the whole 2022-2031 plan, we can see that maintenance interventions (around 30) far outnumber the construction of new pipelines (6), thus confirming that grid expansion investments are likely to become less relevant compared to replacement investments by gas TSOs.

It is important to emphasise that investments for the development and modernisation of Snam’s transportation and storage infrastructure are being made with a view to H2 asset readiness, while Snam is carrying out H2 certification activities on the existing network and checks on storage, compressor stations and the metering system. To this effect, the Italian H2 backbone (Figure 27) has been developed with a view to reusing the pipelines of the methane transportation network «as far as possible through repurposing activities» (Snam 2023), which firstly involve verifying the suitability of existing pipelines to carry H2. The pipelines’ adaptation process needs to consider that the existing natural gas consumption will gradually diminish but it will still be present for several years, and therefore the transport of methane must be ensured. This is why Snam is also conducting transport and demand coverage checks on the downstream transport network, to ensure that natural gas transport continues to be reliable and secure, taking into account the expected medium-to-long term demand (Snam 2023). According to Snam’s strategic planning document, initial assessments on the repurposing activities suggest that the capacities of the resulting natural gas network will in any case be sufficient to meet the system’s demand for natural gas.

Figure 27 – The planned Italian Hydrogen Backbone. Source: Snam (2023).

The Italian Hydrogen Backbone project, with a total CAPEX of about €3.2 billion (Snam 2023)5, is currently in its pre-feasibility stage, and it envisages the preparation of the H2 network to cover the needs of the hydrogen market until 2040, developing sufficient import capacity from Africa to guarantee coverage of the expected demand. The project is also set up to allow export to and import from Austria and Switzerland, ensuring flexibility and security of supply to the Italian and European hydrogen transport system as soon as these interconnections are developed.

The future domestic hydrogen network will mainly consist of grid sections converted for H2 transport, with small exceptions. We can see that in northern Italy the H2 backbone essentially splits into two sections, each of which will serve an interconnection with Austria and Switzerland respectively. In addition to the main backbone, six branches have been defined that will constitute the first connection between the hydrogen backbone and the main consumption and/or production centres. In particular, the areas planned to be reached are those where a significant switch from the consumption of natural gas or other fossil fuels to hydrogen is envisaged, namely the hard-to-abate sectors (in particular petrochemicals and steelworks) (Snam 2023).

It is interesting to notice that Snam’s gas grid development plan includes a section dedicated to the Poseidon pipeline (Figure 28), which is the final stretch of a Greece-Italy interconnection system that would connect the Italian grid to the gas volumes available in the Eastern Mediterranean (the Levantine Basin), thanks to the «EastMed» pipeline project6 and to the gas volumes available at the Turkish/Greek border through an overland extension in Greece. With a total length of around 2000 km, the project (expected to become operational in 2026) would serve Europe’s gas supply diversification strategy in the short term, while in the longer term it could also be used as a hydrogen supply route (Snam 2023). However, despite having been kept in the list of Projects of Common Interest (PCI) published in November 2023 by the European Commission, the EastMed-Poseidon pipeline project, has been subject to both economic and geopolitical difficulties. On the one hand, the commercial viability of a new natural gas pipeline to Europe has been questioned due to the Green Deal objectives for the next decades which would see a lower demand for natural gas. On the other hand, Turkey, whose territory is bypassed by the current project, has raised doubts about the pipeline’s feasibility.

Figure 28 – The EastMed-Poseidon pipeline complex. Source: Agenzia Nova (2022).

The evolution of the electricity transport network is increasingly dependent on the shift of power installed capacity from demand centres, thus being critical for deciding where to establish renewable hydrogen production plants. In order to achieve the Fit-for-55, REPowerEU and national RES targets, Italy’s electricity TSO Terna has been investing around €11 billion in new gird development interventions, under the umbrella of the so-called «Hypergrid» project (Terna 2023)7. The latter will exploit high-voltage direct current (HVDC) transmission technologies which will imply a massive modernisation of existing power lines on the country’s east and west ridges, including the southern regions and islands, accompanied by new submarine connections. According to Terna’s 2023 grid development plan, «Hypergrid» will increase the performance of power lines, minimising their environmental impact and transferring more and more power generated by renewables in southern Italy to the load areas in the north, where the bulk of demand is concentrated. The «Hypergrid» project consists of five main cable backbones (Terna 2023): «HVDC Montalto di Castro-Milan» (to transfer electrons from central to northern Italy), «Central link» (to move electricity from central Italy to the main consumption areas in Tuscany), «Sardinian backbone» (to enable better RES integration on the island, including electricity produced by future off-shore power plants), «Ionian-Tyrrhenian backbone» (to transport renewable energy produced in Sicily and other southern areas towards northern Italy), «Adriatic backbone» (connecting Apulia with Emilia-Romagna and allowing to reduce grid congestion in areas with high renewable generation like Apulia).

The planned and ongoing interventions on the electricity network also arise from an increasing number of requests for connection to the national transmission grid from new renewable power plants. At the end of 2022, Terna had received approximately 311 GW of active requests for connection to the national transmission grid (high and extra-high voltage) for RES electricity, of which 302 GW for photovoltaic and wind power plants (on-shore and off-shore) (Terna 2023). Although the forwarding of the connection request does not guarantee the actual construction of the plant8, such numbers signal a clear tendency towards exploiting Italy’s renewable potential. Around 80% of connection requests are indeed located in southern Italy and on the islands (Figure 29), which are characterised by greater windiness and irradiation (Terna 2023).

Figure 29 – Localisation of connection requests for photovoltaic and wind power plants in Italy. Source: Terna (2023).

With a view to a coordinated planning of the various resources to 2030, the high increase in RES and thus in intermittent electricity generation implies an increase in periods of overgeneration and, consequently, curtailment of renewable electricity. Here is where hydrogen comes into play, as electrolysers represent an opportunity to exploit system overgeneration to produce and store green H2, and use it in turn in other sectors. Given that, according to Terna and Snam’s DDS (Terna 2022), around 3.5 out of 5 GW of the planned electrolysis capacity will be installed in southern (including islands) and central Italy, the potential matching of overgeneration from renewables in the South with hydrogen production could give a decisive breakthrough to the creation of a national hydrogen market. However, the «additionality» rule imposed by the RFNBO Delegated Acts (DA) at the EU level means that electrolyser operation should coincide with hours when the RES production can neither be utilised nor exported. In its energy scenarios, Terna expects a renewable hydrogen production from electrolysis in Italy of around 10 TWh and 20 TWh for 2030 and 2040 respectively (Terna, 2024). Such numbers, especially the projection for 2030, are close to the amount of renewable H2 consumption that we estimated in Chapter 3 when we considered the 2023 version of NECP, which expects around 9 TWh of green hydrogen to be used at a national level in 2030.

Further elements suggest the potential creation of renewable hydrogen production hubs in southern Italy in particular. Snam’s ten-year plan 2022-2031 includes the construction of electrolysers in Apulia and Sicily collecting (renewable) electricity otherwise subject to curtailment (due to overgeneration) and transforming it into an energy vector that can be transported and stored (Snam 2023). A first phase of the project will involve the installation of a 90 MW electrolyser by 2026 near the pipeline dedicated to natural gas import from Azerbaijan (the Trans Adriatic Pipeline) so that the hydrogen produced can be blended into the natural gas network up to a maximum percentage of 2% (Snam 2023). The second phase of the initiative will instead facilitate the recovery of the increasing volumes of overgeneration envisaged by the above-mentioned scenarios, and it will require the installation of a further 800 MW of electrolyser capacity near the most congested grid nodes. According to Snam (2023) the electrolyser’s commissioning date is scheduled for 2031 following the development of the Italian hydrogen backbone, so that the H2 produced can then be injected into a dedicated grid and destined for hard-to-abate consumer sectors first.

It is important to emphasise that green hydrogen production will mostly be based on off-grid renewable electricity at least in the short term, as grid electricity feeding electrolysers would not be decarbonised enough to allow for the resulting hydrogen to be considered renewable under the EU rules. If we consider the carbon intensity (measured in gCO2eq/MJ) of the electricity system in the different EU Member States (Figure 30), we can see that Italy is currently far from the carbon intensity targets for the power grid set at the EU level by the RFNBO DA. The first DA, in particular, outlines the main alternative options under which it can be demonstrated that grid electricity used in the electrolyser is renewable: either in a bidding zone with 90%+ renewables in the electricity mix, or in a «low-carbon» bidding zone with a carbon intensity lower than 18 gCO2eq/MJ, or any other grid solution where however the additionality, spatial and temporal correlation criteria must be met.

Figure 30 – hydrogen GHG emission intensity and renewable energy share from grid electricity in 2020 [gCO2eq/MJ]. Source: Hydrogen Europe (2023).

Although the emission intensity of Italy’s electricity grid is likely to remain above the RFNBO threshold also by 2030 (Hydrogen Europe 2023), this situation could change if we consider the regional development of renewable energy installed capacity. Given that Italy’s electricity market is split into different bidding zones9 - contrary to most EU countries whose entire national territory corresponds to one large bidding zone - the requirements for producing renewable hydrogen could materialise in the bidding zones (mainly in the South of the country) where large new renewable power plants will be built. This means that in those southern bidding zones - especially «Sud», «Calabria», «Sicilia» and «Sardegna» - we could see over 90% of the electricity mix covered by renewables, and prior to this, such bidding zones could become «low-carbon», thus needing to meet the spatial and temporal correlation criteria. This means that the electrolysers should be in the same bidding zones as the renewable power plants, thereby creating the need for hydrogen transport towards the North.

Hydrogen used in hard-to-abate (HTA) sectors is currently almost entirely represented by grey H2, produced mainly through the steam-methane reformation (SMR) process (using natural gas), that results in high levels of CO2 emissions into the atmosphere. Enabling the penetration of renewable hydrogen in HTA sectors is thus extremely important to achieve the decarbonisation targets and meet the specific objectives for RFNBOs enshrined in the Renewable Energy Directive. As we saw in Chapter 2 regarding industry, the RED III sets both minimum thresholds for green hydrogen usage by 2030 (42% of all H2 used in industry must be renewable) and upper limits for fossil-based unabated hydrogen (up to 23% of all H2 used in industry can be produced using fossil fuels). The bulk of the grey hydrogen used in HTA industries is directly produced by the same companies that use it for their production process, as a feedstock (e.g. in the chemical sector) or as a fuel for industrial heat (e.g. in the paper, steel or ceramics sectors). Such configuration is known as “captive production”, taking place within the limits of the industrial plant’s H2 generation capacity. To have a specific order of magnitude, Table 37 reports the amounts of unabated hydrogen produced and used in the main energy-intensive industries in Italy.

Refineries are by far the largest hydrogen consumer, and they also use the SMR process for producing most of their H2. According to Confindustria (2024), between 40 and 50% of that hydrogen is produced through SMR in plants located within refineries, while between 30 and 35% comes from the catalytic reforming of gasoline, and the remainder is purchased from specialised operators, who produce hydrogen by SMR and transport it to the refinery. In the chemical sector, around two thirds of the hydrogen used is produced through SMR and it is destined to produce ammonia and derivatives (Confindustria 2024).

Table 37 – Grey hydrogen used in the hard to abate sectors [Mt/year]. Source: own elaboration based on Confindustria (2024).

If we compare the numbers of the above-mentioned sectors with the targets for renewable hydrogen included in the Italian NECP, discussed in Chapter 3, we can clearly conclude that those targets are not ambitious enough to achieve the 42% renewable hydrogen (RFNBO) target in industry by 2030 foreseen by the RED III. Indeed, Italy’s NECP provides for 0,115 Mt of renewable H2 to be used in industry (see section 3.2.4.), which however correspond to just around 22.4% of the total amount used in refining and chemicals today (0.514 Mt). A 42% renewable hydrogen target would instead require an almost double quantity (0.215 Mt) compared to what is currently indicated in the NECP for industry (0.115 Mt).

As we saw in Chapter 1, however, today’s green hydrogen production cost is still not competitive with grey H2 generation methods. Therefore, besides setting more ambitious quantitative targets, the levelized cost of hydrogen (LCOH), i.e. the price at which the hydrogen produced would have to be sold to offset the total production costs over the lifetime of the project, should be supported through incentive mechanisms. The structure and the amount of support should be determined taking into account two factors in particular: the electricity costs faced by national producers and the equivalent hours of operation of electrolysers, which are conditioned by the type of renewable electricity sources that can be used (e.g. Italy cannot currently count on the high load factors that are accessible to northern European countries that have a high generation from offshore wind) (Confindustria 2024). It could be thus interesting to assess whether such gap in the quantity of decarbonised hydrogen could be compensated, at least in the medium term, by blue hydrogen.

The transition from production modes with a high environmental impact to sustainable ones in the hard-to-abate industrial sectors could see blue hydrogen as a bridging opportunity in the short to medium term. Nevertheless, investment in research and development is needed to build industrial-scale plants that will demonstrate its viability for widespread applications, as the production of blue hydrogen requires efficient carbon capture and storage (CCS) to drastically reduce emissions from the steam methane reforming process. CO2 can be captured through three main types of processes: post-combustion, pre-combustion or combustion in oxygen. All methodologies have either an intermediate or high technology readiness level, and the average demonstrated carbon capture efficiency of the capture methodologies is about 90% (The European House - Ambrosetti 2022).

As we saw in Chapter 1, blue hydrogen can serve as a complementary technology to green hydrogen for various reasons. First, blue H2 can facilitate the uptake of hydrogen in marginal demand sectors thus lowering the overall cost of hydrogen in the longer term and putting significant pressure on the CO2 price, as demand for CO2 would increase when a market is created. Second, using blue hydrogen to meet the short-to-medium term H2 demand significantly reduces the necessary investments into renewable power generation capacity, leading to savings in the energy system (Durakovic et al. 2023). Third, low-carbon hydrogen can be exploited especially in areas not particularly favourable to the development of renewable sources - both because of geographic characteristics, as well as for scarce land availability (The European House - Ambrosetti 2023).

The new CCS project off the coast of Ravenna in the Adriatic Sea could become a potential enabler of blue hydrogen supply to the HTA sectors soon. This new CCS facility can prove critical to the decarbonisation of the unabated hydrogen that is currently used in energy-intensive industries in northern Italy that use it either as a feedstock (chemicals, refineries) or as a fuel for combustion. By removing the CO2 produced when grey hydrogen is generated, H2 could thus become «low-carbon». The project, implemented jointly by the Italian TSO Snam and by Eni and officially named «Callisto» (CArbon LIquefaction transportation and STOrage) is one of the few CCS projects in southern Europe compared to the North Sea area (IOGP 2023), and it will be one of the largest CO2 storage sites in the world and the largest in the Mediterranean10. The project envisages an initial phase, which started in 2024, aimed at capturing 25,000 tonnes of CO2 from Eni’s natural gas processing plant in Casalborsetti (Eni 2023). Once captured, the CO2 will be piped to the «Porto Corsini Mare Ovest» platform and injected into the depleted gas field of the same name in the Ravenna offshore area. In the second phase, from 2026, 4 million tonnes of CO2 are expected to be stored to contribute to the decarbonisation of the hard-to-abate industries in the Ravenna area and Northern Italy (Eni 2023). From 2030 onwards, the large capacity of the reservoirs would make it possible to increase the project’s capacity to 16 or more million tonnes per year, depending on market demand.

While at the infrastructural level projects are being developed, we should assess the actual possibility to introduce low-carbon hydrogen in the H2 mix in accordance with EU and therefore national legislation. The European Commission’s Delegated Act on low-carbon hydrogen (see Chapter 2) defines the concept of low-carbon hydrogen and sets out the methodology for calculating the required 70% greenhouse gas emission savings compared to unabated fossil fuels, in line with the methodology established in the RFNBO Delegated Act of 2023. The 70% threshold applies to blue hydrogen produced from natural gas using CCS technology, low-carbon electrolytic hydrogen produced by electrolysis using electricity from the grid, and hydrogen produced from methane pyrolysis (European Parliament 2025). The delegated act aims to standardise the calculation of emissions savings by accounting for the full life-cycle emissions from producing low-carbon fuels, including indirect emissions, as well as upstream methane emissions and actual carbon capture rates (European Parliament 2025). Nonetheless, there exists a loophole in the Renewable Energy Directive III that allows to reduce the share of RFNBO (green hydrogen) foreseen by the industry-specific target, thus potentially enabling Member States to increase the share of other types of hydrogen in their total H2 amount. Whereas the green H2 target for the industry sector is set at 42%, Article 22b of the RED III states that «A Member State may reduce the contribution of renewable fuels of non-biological origin […] by 20% in 2030», meaning that green hydrogen can be 22% instead of 42% in industry. Such possibility would perfectly fit the NECP’s projections, that foresee a 22% share of green hydrogen in industry by 2030 (see previous section). This scenario can however be employed only under two conditions: first, the country has to be on track to meet its national contribution to the EU’s overall target of 42.5% renewables in final energy consumption by 2030; second, the share of hydrogen made using fossil fuels has to be 23% or below in 2030 (Official Journal of the European Union 2023). Italy is not close to either objective, as its renewable share in final energy consumption was just around 19% in 2022 (Ministero dell’Ambiente e della Sicurezza Energetica 2023a) and it has currently no nuclear plants that can power electrolysers to produce hydrogen, which would not be renewable but neither would it be fossil. Despite being largely decarbonised thanks to CCS, blue hydrogen instead remains a fossil-based H2 type, thus not being able to fulfil the requirements of the more flexible scenario foreseen by the RED III.

A case in point is provided by Iris Ceramica Group, one of Italy’s top-three ceramics manufacturers with an annual revenue of over €500 million. This company, whose main production facilities are distributed between the Provinces of Modena and Reggio Emilia14, has become the first ceramics manufacturer in the world to develop hydrogen-based ceramic production. Iris Ceramica Group signed two different agreements in 2021 and in 2023 with the Italian gas TSO Snam and with Edison Next15, respectively, in order to implement the use of green hydrogen - initially in a blend with natural gas - in the firing stage of the ceramics production process.

In September 2021, Snam and Iris signed a memorandum of understanding aimed at developing a project for producing ceramics surfaces using a blend of green hydrogen and natural gas. The H2 is produced from solar energy, via a dedicated 2.5 MW photovoltaic plant, installed on the rooftop of one of Iris Ceramica’s factories located in Castellarano, in the Province of Reggio Emilia (Snam 2021). The PV plant is coupled with an electrolyser and a storage system for on-site H2 generation, while the company’s long-term aim is to switch to a fully decarbonised production.

For this very reason, in July 2023, Iris Ceramica Group signed an agreement with Edison Next to develop what has been named the «H2 Factory™», a new project always located in the Castellarano production facility, that will develop green hydrogen generated thanks to a custom-made system installed on site (Edison Next 2023). The partnership between Iris Ceramica Group and Edison Next has marked the beginning of the second phase of the project that was launched through the 2021 agreement with Snam. The first step towards decarbonisation, which saw Iris Ceramica Group engaged over the last two years in the feasibility study and construction of the H2 Factory™ site, suitable for hosting the green hydrogen production plant, has been successfully completed (Edison Next 2023).

In order to enable the hydrogen blend, and even more for a 100% hydrogen system, several arrangements are required. Technical modifications do not only concern the plant engineering, such as the furnace engineered to be fuelled with a blend of hydrogen and natural gas, but involve also strategic site works, including the construction of rainwater collection tanks, the installation of the PV panel system on the roof of the ceramics facility, and ad hoc hydrogen production and storage areas. Iris Ceramica Group has set up the entire infrastructure for the distribution of hydrogen within the plant.

Edison Next will provide an electrolyser with a capacity of 1 MW, fuelled by renewable energy, as part of a €50 million investment by Iris Ceramica Group (Edison Next 2023). The renewable hydrogen production plant (splitting water into H2 and oxygen) will use rainwater from the collection tanks, thus also promoting virtuous water management, and it will take the electricity from a new PV plant of around 1.2 MW in addition to the existing plant of 2.5 MW mentioned above. Hydrogen will be used in particular to fuel the furnace, which will be mixed with natural gas up to a percentage of about 50%, while a furnace that will run on 100% hydrogen is being studied (Edison Next 2023). The expected production of about 132 tonnes of green hydrogen per year will replace about 500,000 cubic metres of natural gas per year, starting from 2025 (Edison Next 2023).