A broad range of methods is available for H2 generation which can be categorized into two primary groups: renewable technologies and non-renewable technologies (Nikolaidis and Poullikkas 2017). The latter category includes hydrocarbon pyrolysis and hydrocarbon reforming, which encompasses the three fossil-based methods mentioned above. On the other hand, hydrogen production via renewable energy has two main branches, namely biomass-based and water-splitting technologies. Processes that use biomass as the raw material fall into two further sub-categories: thermochemical technologies such as gasification, pyrolysis, combustion, and liquefaction; and biological processes comprising fermentation and bio-photolysis stages (Nikolaidis and Poullikkas 2017). Water-splitting processes instead include electrolysis, photo-electrolysis, and thermolysis where water is the feedstock. A technical overview of those technologies is provided in the next paragraphs, mainly building on Ahmed et al. (2022).

Since hydrogen is not widely accessible in nature, the energy conversion routes highly influence the overall cost of hydrogen production (Ahmed et al. 2022). An analysis of the main cost components involved in the upstream stage of the H2 value chain is therefore important in order to have a sharper picture of the hydrogen economy. Firstly, cost parameters for H2 production can be divided into two major categories, which will be also mentioned in the subsequent sections, namely operational (OPEX) and capital (CAPEX) costs. The latter have been sub-divided, by Kannah et al. (2021), into two groups: the direct capital costs, that include instrumentation, control system and site-specific costs, and indirect capital costs, that include engineering and supervision, construction costs, legal and contractor expenses and contingency. Instead, operating costs are represented by the raw material (the feedstock), by labour and maintenance costs. In the next paragraphs, first a definition of «Levelised Cost of Hydrogen» is provided, secondly, the costs of the main hydrogen production methods will be outlined and compared to one another, drawing from the existing techno-economic literature. Thirdly, some important cost parameters of the hydrogen upstream component – such as the Net Present Value (NPV), the Return on Investment (ROI) and the Pay-Back Period (PBP) – will be discussed.

The methodology used to establish the capital and operating costs of hydrogen production is indeed defined as «Levelised Cost of Hydrogen» (LCOH), which enables different production routes to be compared on a similar basis. The LCOH indicates how much it costs to produce 1kg of hydrogen, taking into account all the relevant variables that affect production, namely CAPEX, OPEX and – if renewable electricity is used – the annual hourly production curve of the renewable resource (Vector Renewables 2022). For the purpose of this chapter, it is therefore essential to briefly examine how the LCOH is calculated. Since it is used for evaluating the economic performance of hydrogen production, the LCOH is defined as discounted cash flows divided by the discount hydrogen output, according to the following formula (Tang et al. 2022):

(1)

where Ii is the investment in year i, Mi the maintenance and service cost in year i, Oi the operational cost in year i, Ei the energy (hydrogen) output in year i, [kg], Ri the revenue income in year i, and finally r is the cost of capital, [%]. If the investment, the other costs and the revenue are taken in euros [€], the LCOH is thus expressed in € per kg of hydrogen [€/kgH2]. As defined in economic and financial theory, the discounted cash flows are used to find the present value of the expected future cash flows using a given discount rate, so that investors can determine whether future cash flows of a project (in this case related to hydrogen production) are larger than the value of the initial investment. This is the concept of the net present value (NPV). Drawing from the formula described above, since the aim is to investigate the cost components, the cash flows and the hydrogen output are simplified as constants along with the years, thus resulting in the following equation (Tang et al. 2022):c

(2)

To have a first practical outlook of the evolution of the LCOH on a global level, the IEA has provided a chart (Figure 2) that reports the actual LCOH in 2021 and 2022, versus the expected LCOH for 2030, based on the path to climate neutrality by 2050, for different production sources.

Figure 2 – Levelised cost of hydrogen production by technology in 2021, 2022 and the Net Zero Emissions by 2050 Scenario [$/kgH2]. Source: IEA (2023c). Notes: CCUS = carbon capture, utilisation and storage; PV = photovoltaic; NZE= Net Zero Emissions by 2050 Scenario in 2030. Solar PV, wind and nuclear refer to the electricity supply to power the electrolysis process. NZE values refer to 2030. The dashed area represents the CO2 price impact.

The LCOH shows a high variability depending on the hydrogen production source. When using natural gas, it can be seen that costs are comparatively lower than when using renewable technologies. The spikes in the 2022 LCOH for natural gas (both with and without CCUS) are mainly due to the gas price crisis sparked by Russia’s war against Ukraine in early 2022 and the already present tightness in gas markets from late 2021. All costs are projected to be declining by 2030 compared to 2022, but wind- and solar PV-based H2 production will remain costlier than the fossil-based one also in the medium term, even though prices will be lower overall compared to today.

Since in the following we will review the literature assessing H2 generation costs according to each technology, one last element should be mentioned in this first part, because it will also be useful to better understand the next chapters, which will be dealing with the integration of electricity and hydrogen molecules. The LCOH’s calculation methodology can indeed be compared to the technique used to compute the so-called «Levelised Cost of Electricity» (LCOE), which – being always linked to the concept of the present value of the investment – is calculated by the net present value (NPV) of the total cost of building and operating a power generating asset, and dividing this number by the total electricity generation over the lifetime of the plant (US Department of Energy 2013). The LCOE is therefore the measure of lifetime costs of the power plant divided by its energy production, thus allowing for comparisons of different technologies (solar, wind, natural gas…) with unequal life spans, different CAPEX, different risks and returns. As will be mentioned later in this chapter, one of the current most significant challenges in increasing the size of the hydrogen economy and scaling-up green hydrogen production lies in reducing the cost of the electrolyser, since the H2 production cost is greatly influenced by the electrolyser capital cost, and the maximum electrolyser utilisation (load hours) results in lower H2 production costs, which accounts about 3000-6000 operating hours (Kannah et al. 2021).

The latter element is one of the main reasons why steam-methane reforming (SMR) is still the most widely used technology for H2 production, since its high efficiency leads to larger hydrogen yield per unit of feedstock, resulting in a production cost that lies between $1.25 and $3.50 (or €, given today’s quasi-parity of the two currencies) per kg of H2. As SMR leads to significant CO2 emissions, carbon capture and storage (CCS) technologies are used and therefore the cost of H2 production can increase, being no less than 2.27 $/kgH2 (Nikolaidis and Poullikkas 2017). Coal gasification lies between 1.30 and 1.60 $/kgH2 (Ahmed et al. 2022). Such methods of thermo-chemical conversion are thus extensively exploited due to the energy density and huge availability of carbon-based fuels. Indeed, on a global level, approximately 48% of H2 is produced from natural gas, 30% using oil and 18% using coal.

Renewable hydrogen produced through water electrolysis shows, instead, higher costs per kg. For instance, Kuckshinrichs et al. (2017) documented the economic analysis of mature H2 production technology (Alkaline water electrolysis, AWE) at three different site locations in Europe – Germany, Austria, and Spain. They reported that the LCOH was around 3.64 €/kgH2 at the German site, whereas in Austria and Spain sites, the levelised cost of H2 was slightly higher (15 to 18%), mainly owing to the higher electricity cost. Matute et al. (2019) have estimated the cost of H2 production for AWE around 6 €/kgH2 and Proton-exchange membrane (PEM) based water electrolyser as 7 €/kgH2. According to Ahmed et al., (2022), photo-electrolysis with a solar energy source can have a production cost as high as 10.36 $/kgH2, and a similar pattern is also followed by the H2 production technologies using biomass (lignocellulose in this case), whose cost lies around 12 €/kgH2. Table 1 gives a schematic overview of the above-mentioned data.

Table 1 – Costs of hydrogen production using available technologies. Source: own elaboration based on selected studies.

Because green hydrogen is mostly produced via electrolysis, it is interesting to briefly focus on the way in which production (fixed and operating) costs for water electrolysis are formed, so as to have the necessary theoretical instruments to analyse the next section covering renewable hydrogen in particular. The factors that determine the CAPEX, the OPEX and the mass of hydrogen produced (MH2) can be specified as follows (Kannah et al. 2021):

CAPEX=CCA+(OMC +IC).CCA.A(3)

(4)

MH2=rH2.LT.CF(5)

where CCA = capital cost of electrolyser, A = net area of the electrode (used to split water), COE = cost of electricity, rH2 = rate of H2 production, HHV = higher heating value of hydrogen3, η = efficiency of the electrolyser system, LT = lifetime of the electrolyser, CF = capacity factor4, OMC = operation and maintenance costs, IC = installation costs, and CCA times A = total capital cost. The cost of electricity is one of the most critical elements for establishing the convenience of the whole electrolysis system, and also the water supply must be considered. Electricity cost is strictly connected to the concept of power purchase agreements (PPAs). These are increasingly used contracts signed between a producer and a consumer of electricity that fix a certain price, thus insulating the counterparts from market price volatility. For instance, Fragiacomo and Genovese (2020) include PPAs to calculate the electricity cost in their economic analysis of renewable hydrogen production in southern Italy5.

Before moving to the analysis of renewable hydrogen replacing fossil-based H2, one last point should be made with regard to the methods used to establish the cost-effectiveness of a hydrogen production technology. Return on investment (ROI) and the pay-back period (PBP) will be briefly addressed. While the latter can be defined as the time, in years, that the expected benefits of the investment equal the fixed assets, namely when the NPV is equal to zero, the ROI index represents the potential economic returns compared to the initial investment (Fragiacomo and Genovese, 2020). Therefore, ROI can allow to identify the total growth of the production plant from the start to the end of its life. Kannah et al. (2021) present the following formula to calculate ROI: ROI = (AF/FCI)*100%, where AF is the annual profit (difference between annual revenue and annual production cost) and FCI is fixed capital investment (cost required for purchase of land, equipment and installation). Typically, a value of ROI above 20% is considered as profitable for the scaling up process.

Renewable hydrogen, as outlined by the EU Hydrogen Strategy (2020) is defined as «hydrogen produced through the electrolysis of water (in an electrolyser, powered by electricity), and with the electricity stemming from renewable sources», adding that «the full life-cycle greenhouse gas emissions of the production of renewable hydrogen are close to zero» (European Commission 2020)6. The newly adopted EU Delegated Acts on Renewable Hydrogen further specify that unless the electricity system is already largely decarbonised, it is crucial to match the electricity demand for hydrogen production with additional renewable electricity generation, otherwise electrolysers’ additional electricity demand could risk leading to increased fossil-based power generation (European Commission 2023).

Therefore, using «clean hydrogen» as a synonym for renewable H2, it is important to introduce the concept of «well-to-gate» when accounting for emissions in hydrogen production. This is an assessment methodology that calculates the lifecycle emissions associated with upstream feedstock production, upstream transportation, and onsite hydrogen production, thus excluding downstream storage and transport emissions, service and end-of-life emissions, and it can be measured in grams or kilos of CO2 equivalent per kg of produced hydrogen (Connell 2022). For instance, the well-to-gate GHG emissions of steam reforming of natural gas are about 9 kg of CO2eq/kgH2, while those of SMR with carbon capture and storage (CCS) with 90% capture are equal to 1 kg of CO2eq/kgH2, and 4 kgCO2eq/kgH2 with a capture rate of 56% (IEA 2019).

Several obstacles must be considered when assessing the increasingly wider employment of renewable hydrogen and the flexibility that the latter can provide to decarbonise polluting sectors of the economy. The first key component is renewable electricity, which when produced through solar PV or wind can also be referred to as variable renewable energy (VRE). Hydrogen produced from renewable electricity (through an electrolyser) could indeed facilitate the integration of high levels of VRE into the energy system, because the electricity consumption of electrolysers can be adjusted to follow wind and solar power generation, where hydrogen becomes a source of (long-term) storage for renewable electricity (IRENA 2018). Moreover, hydrogen from renewable electricity could create a new downstream market for renewable power, because it has the potential to reduce renewable electricity generators’ exposure to power price volatility risk, in instances where part or all generation is sold to electrolyser operators through long-term contracts (e.g. PPAs). The second key element is thus the electrolyser, analysed hereafter.

As regards the issue of transportation, five forms of H2 are considered: compressed hydrogen (CGH2), liquefied hydrogen (LH2), ammonia (NH3), methanol (MeOH), and Liquid Organic Hydrogen Carriers (LOHC). While the first two forms involve only the presence of hydrogen, the last three can be defined as «chemical carriers», since H2 is mixed with other elements, making it suitable for being transported. Given that these technologies not only allow for the transport of hydrogen, but also for its storage (ENTSO-G et al. 2021), the same classification is used for discussing H2 storage.

The economic analysis of hydrogen transportation via new or refurbished pipelines needs to take the levelised cost of transmission (LCOT) into account. The latter – which is reported for the European scenario – can be defined as the discounted cost per MWh of hydrogen transported by the pipeline (European Commission 2021). As summarised in Table 3, while the investment cost for completely new hydrogen pipelines – based on estimations for the German network – would amount to no less than €2.48 million (in 2019 prices) per km of pipeline length and those for a repurposed gas pipeline would be around €0.37 million/km (in 2019 prices), the LCOT for refurbished and newly built pipelines is estimated at around 3.7€/MWh per 600 km and 4.6-45€/MWh/600 km respectively (European Commission 2021). Thus, it can be said that the investment cost of repurposing the existing lines is around 15% of the cost of building new hydrogen pipes, even though there are other studies that report a CAPEX per km of refurbished hydrogen pipelines equal to around 33% of the cost of newly built lines (ACER 2021). These figures suggest that converting the gas network to carry pure hydrogen can be cheaper that building new infrastructures. However, as mentioned in the previous sub-section, the process of conversion can involve issues with gas supply and should therefore be done gradually, and it should especially consider the developments in hydrogen demand across long distances.

Table 3 – Investment costs [M€2019/km] and Levelised Cost of Transmission (LCOT) [€2019/MWh/600 km] for new and refurbished hydrogen pipelines. Source: own elaboration from European Commission (2021).

The identification of the different «tipping points» – here understood as the points where one particular method of hydrogen transportation becomes more cost-effective than the one previously used – is useful to put the technologies into perspective and contextualise them in the next chapters. If trucks are seen as the most cost-effective option for H2 transport in small volumes (less than 10 tonnes per day) over short distances (up to 200 km) (ACER 2021), the cost of MEGC systems is around 790-1100$/kgH2 using compressed hydrogen, while beyond a distance of 300/400 km it is more cost-effective to transport liquid H214. In terms of shipping routes, while transporting ammonia appears much cheaper than pure hydrogen transport, for distances below 1500 km, transporting hydrogen gas by pipeline is likely to be the cheapest delivery option, and above 1500 km ammonia or LOHC become more cost-effective (IEA 2019). Conversion costs can significantly impact business cases since as much 28% (11kWh/kg) of the transported energy can be consumed during LOHC dehydration and hydrogen separation (ENTSO-G et al. 2021).

Before analysing the current technologies for storing hydrogen, it is interesting to combine the different H2 transportation methods and assess their cost-efficiency, drawing from Cebolla et al. (2022), who also provide some of the most updated figures in terms of costs. Hydrogen delivery costs (in €/kgH2) are plotted against distance for 1 Mt of H2 per year in a two-fold scenario: 1) high electricity prices (Figure 4), with a production site electricity price of 50 €/MWh and a consumption site price of 130 €/MWh, and 2) low electricity prices (Figure 5), with a production site electricity price of 10 €/MWh and a consumption site electricity price of 50 €/MWh. While the first price scenario is based on current and 2022-23 electricity prices, the low-price scenario includes future (2030+) estimated renewable electricity price trends. It is important to note that the colour of the background (blue and red for Figure 4, blue, red and green in Figure 5) reflects the cheapest hydrogen transport method for each distance.

Figure 4 – Hydrogen delivery cost vs. distance (High electricity price)15. Source: Cebolla et al. (2022).

Figure 5 – Hydrogen delivery cost vs. distance (Low electricity price)16. Source: Cebolla et al. (2022).

For high electricity prices (Figure 4), compressed hydrogen transported in pipelines is the cheapest option up to around 7500 km, whereas for distance beyond 7500 km liquefied hydrogen remains the most cost-effective method, due to the additional costs involved in combining H2 with the other chemical carriers. In the low electricity price scenario (Figure 5), hydrogen pipelines are the cheapest option up to around 6500 km, after which LH2 becomes the more economic option. From around 10000 km, LOHC becomes the most cost-effective option, while for very long distances (above 15000 km), ammonia and LOHC (brown and green lines) perform better than LH2 (red line), mainly due to the issue of boil-off (which imply hydrogen losses during transportation when H2 is liquefied).

Storage has been insufficiently explored up to this point, and no viable business model for hydrogen – as an internationally or even locally traded commodity – could possibly omit the fact that this substance in most cases will have to be stored at least right after its production and before its delivery to the end user (Patonia and Poudineh 2023). This is especially true with renewable (solar and wind-generated) H2, since its generation is intermittent, but its current and projected demand (mainly from industrial customers) is stable. Therefore, while the availability of renewable energy for hydrogen production is subject to strong fluctuations, the operation of pure H2 networks serving significant hydrogen demand would require the services of highly flexible hydrogen storage (ACER 2021). According to Usman (2022), the practical hydrogen storage is perhaps the biggest hurdle in the success of the hydrogen economy on a large scale.

Given the need to decarbonise the economy, hydrogen storage not only serves final H2 demand, which will gradually increase in the next decades, but it has become increasingly important to provide for long-term electricity storage when non-dispatchable power sources (such as solar and wind) are used to produce renewable electricity. While batteries, for instance, can absorb short-term renewable electricity fluctuations, hydrogen can allow for larger-scale and longer-term storage mainly through Power-to-Gas (P2G) technologies. Hydrogen contribution will be critical to manage seasonal peaks in the RES electricity demand and supply, due to the projected increase in electrification and overall use of renewables. It will also optimise investments in energy systems by reducing over-investments in electricity grids.

There is however an issue related to the actual efficiency of using electricity to produce hydrogen (by electrolysis), storing the hydrogen, and then converting it back to electricity by using a gas turbine and a power generator, or a fuel cell. Hydrogen re-electrification with these two methods can have efficiencies as high as 50%17, which means that at least 50% of the energy is lost. Nonetheless, it should not be neglected that the alternative to hydrogen production, storage and re-electrification could be that renewable electricity must be curtailed because of the lack of electrolyser capacity to transform the surplus renewable electricity into renewable hydrogen. The efficiency of such a situation would be equal to zero.

It is essential to analyse hydrogen storage technologies along two dimensions: 1) the physical forms or chemical compounds in which hydrogen can be stored, and 2) the sites where H2 can be placed when needed. The five forms of hydrogen previously addressed will be analysed here to account for their use as storage options. Large- (country-) scale storage of hydrogen is still technologically limited to H2 compression and injection underground (Patonia and Poudineh 2023). The second form of pure hydrogen (liquefied H2) presents significant challenges when it is stored, owing to the evaporation of part of this hydrogen – known as «boil-off» – which is a consequence of the heat transfer from the (warmer) storage tank surroundings, to the stored hydrogen (Cebolla et al. 2022). This in turn will imply a pressure increase inside the tank, but not necessarily a loss of hydrogen, since the evaporated H2 may be redirected back to the liquefaction plant, or to an intermediate gas storage buffer, or directly to a final user (Cebolla et al. 2022). According to the same JRC report, however, these measures require additional equipment and integrated refrigeration and storage (IRAS), thus implying higher costs. The last three options are hydrogen compounds: ammonia (NH3), which can be stored at cryogenic temperatures at atmospheric pressure; methanol (MeOH), whose storage is usually performed in stainless steel tanks; and LOHC, which can be stored in large quantities at ambient conditions in double-walled containers, as used for crude oil or diesel (Cebolla et al. 2022).

The second dimension of the present analysis concerns hydrogen storage sites, about which there is currently substantial debate in Europe. All the available options can be divided into above ground and underground storage. The former is almost exclusively represented by superficial tanks, containing either compressed or liquefied hydrogen. Compressed hydrogen, however, even at very high pressure (700 bars or 70 Mpa), has only 15% of the energy density of gasoline, so storing the equivalent amount of energy as hydrogen at a vehicle refuelling station, for instance, would require nearly seven times the space (IEA 2019). On the other hand, ammonia has a greater energy density, but it will also lead to greater energy losses due to the required conversion process (IEA 2019). Finally, the costs for large tanks (200-300 tonnes) of liquefied H2 can range between 150-300 €/kgH2 (Derking et al. 2019).

Underground hydrogen storage (UHS) can be subdivided into three main types of formations, that provide large-scale seasonal storage: salt caverns, aquifers and depleted fields (ENTSO-G et al. 2021). Other types of underground storage include conventionally mined rock caverns, abandoned mines and also pipe storage, which is located a few meters below ground level and it is not classifiable as geological storage (Kruck et al. 2013)18. Geological and reservoir constraints, technical and safety limitations, legal barriers, conflicts of interest, and social acceptance are amongst the most significant barriers to the implementation of UHS (Tarkowski and Uliasz-Misiak 2022).

These sites are suitable for storing pure hydrogen due to their low cushion gas requirement19, the large sealing capacity of rock salt and the inert nature of salt structures, limiting the contamination of the hydrogen stored (ENTSO-G et al. 2021). Besides, salt caverns offer very flexible H2 storage (injection) and retrieval but, as can be seen in Figure 6, opportunities for storing hydrogen in salt caverns are geographically limited to a few areas in several EU Member States (ACER 2021). The largest potential is indeed located in the southern part of the North Sea and in its bordering countries. The potential for hydrogen storage in European salt caverns (onshore and offshore) has been estimated at 2.5 billion tonnes of hydrogen, with the largest potential in Germany (42%) (Caglayan et al. 2020)20.

Figure 6 – Salt deposits in Europe. Source: Kruck et al. (2013).

Hydrogen will compete with bioenergy and fossils with carbon capture and storage (CCS) in decarbonising hard-to-abate industrial sectors (Tarvydas 2022). One key application where green hydrogen can be introduced is steelmaking. The latter industry accounts for 4% of all the CO2 emissions in Europe and 22% of industrial carbon emissions (Bellona Europa 2021), since the primary steelmaking method involves two fundamentally high-emission steps: first, the iron ore is melted in a blast furnace (at about 2000ºC) usually using natural gas or coke (made from coal), thus obtaining so called «pig iron» in a process known as «direct reduction of iron» (DRI); second, the pig iron is made into steel, via a process that can generate up to 1.85 tonnes of CO2 for every tonne of steel produced (Alverà 2021). When green hydrogen – instead of fossil fuels – is used to reduce the iron ore, the latter is heated between 800-1200ºC, obtaining pig iron, which can be then fed into an Electric Arc Furnace (EAF), where electrodes generate a current to melt the pig iron to produce steel (Bellona Europa 2021) with no emissions26. Such a technique has been around at a commercial scale since the late 1960s, but not with pure (or green) hydrogen, thus generating emissions.

Although hydrogen (and especially green H2) costs more than fossil fuels, the existence of a carbon price, such as the EU ETS, can make cleaner alternatives more competitive, not to mention the spike in fossil gas prices, that started in late 2021 and worsened after the beginning of Russia’s large-scale invasion of Ukraine in early 2022. According to the European Commission (2021), the investment cost of new hydrogen DRI-EAF based manufacturing capacity is between 400-752 €/tonne of annual steel production capacity, while the steel production costs using the same technology are between 386-685 €/tonne of crude steel.

Besides steelmaking, which is projected to cover most H2 demand amongst the hard-to-abate sectors by 2050, there are other industries which can potentially scale up their use of this clean molecule. One example is provided by the cement sector, that can use hydrogen either as a fuel in the cement production process (replacing coal and natural gas), or as a means to capture CO2 and use it as feedstock (carbon capture and utilisation) for the production of other products such as building materials and fuels (Commodity Inside 2023). The same can be done in the ceramics industry, as demonstrated by the agreement between the Italian company Iris Ceramica and the national gas TSO SNAM in late 2021, that aims to fully decarbonise the company’s production process through a 100% hydrogen-fuelled plant (Iris Ceramica 2021)27.

According to Tarvydas (2022), 4% of fuel demand in transport will be met by hydrogen by 2030, rising to 17% and around 27% in 2040 and 2050 respectively. It is however important to distinguish between the different categories of transport, since some of them will see a quicker scale-up of hydrogen-fuelled vehicles while in other types of transport the molecule will remain rather cost-inefficient compared to electricity-powered or alternatively fuelled vehicles. Hydrogen can become the key to decarbonising heavy-duty and long-haul transport, as there are hardly any other zero-emission alternatives available (Ruf 2018). Those categories include maritime and aviation applications, which however remain at a prototyping stage. In the shipping sector, hydrogen fuel cells are used, but only in a few cases are they employed as propulsion. Fuel cells can be used as auxiliary power units for on-board energy needs, while for airplanes, fuel cell-powered flights are not regarded as feasible (Ruf 2018). Hydrogen can rather play a more significant role in the production of e-kerosene (used as a fuel in aviation), which is generated by combining H2 and CO2, and is included in the category of the so called «e-fuels» or «power-to-liquid». Two conditions are essential for e-kerosene to have zero greenhouse gas emissions. First, hydrogen needs to be produced using renewable electricity, and second, carbon dioxide needs to be captured from the atmosphere (Transport & Environment 2021).

Light and medium-duty transport deserves a separate discussion, as there is currently much debate on the actual cost-effectiveness and maturity levels of fuel-cell cars and hydrogen buses. The former have been introduced in the market but their commercial availability is still limited, and their original equipment manufacturers (OEMs) are almost exclusively located in East Asia (Ruf 2018). Fuel-cell buses are instead a more mature application, mainly for urban areas, even though their technology readiness level (TRL) must take into account the relevant infrastructure needs, such as hydrogen filling stations. These can create bottlenecks and obstacles towards scaling-up hydrogen-powered vehicles28. Hydrogen-fuelled trains also present some criticalities, even though they have been gathering pace to replace conventional diesel trains, as happened in Germany at the Elbe-Weser Railroad Company, which has become the first in the world to operate a fleet of hydrogen trains in regular operation (Weyerer 2022).

One of the sectors where the introduction of hydrogen is more discussed – and perhaps most controversial – is the residential sector. The latter is the second largest consumer (behind the transport sector) of final energy in the EU (around 33%) (European Environment Agency 2025) and it is responsible for around 6% of GHG emissions from energy, emitting more than the power sector (Hydrogen Europe 2022). It is important to point out that households use energy for various purposes: mainly space and water heating (around 79% combined), space cooling, cooking, lighting and electrical appliances and other end-uses also outside the dwelling themselves (European Environment Agency 2025). Given that studies investigating the residential applications of hydrogen are still scarce, the use of hydrogen in buildings should be assessed as part of a complete energy system (Rongé and François 2021), not only on the level of a single house, taking into account also the efficiency improvements and renovation of buildings.

Focusing on the main uses of energy in households (heat and power), hydrogen can be used via three main technologies: hydrogen gas boilers, combined heat and power (CHP) units and hybrid heat pumps. The first appliance functions in the same way as a natural gas boiler, even though hydrogen burns with a much higher flame speed, which can generate nitrogen oxides (NOx, with high global warming potential) during combustion, thus needing a burner re-design (Rongé and François 2021). Controlling these factors while excluding hydrogen for open-flame cooking for which it is not an option, may come at a higher cost and lower fuel efficiency (Korberg et al. 2022). The second technology, CHP, can be based on either combustion of hydrogen or on fuel cells. The latter system is currently offered by several suppliers in form of «micro-CHP» (in the order of 10s of kW) and they are mostly connected to the natural gas grid and extract the hydrogen from the natural gas (cracking) before feeding it into the fuel cell (Rongé and François 2021). This is only possible where hydrogen-ready infrastructure is already in place, thus recalling the potential issues in repurposing the distribution grid mentioned in the previous section. Finally, hybrid heat pumps are a combination of an air-source heat pump (absorbing heat from outside and releasing it inside) and a gas boiler, with a single control operating the whole system. Hydrogen can be used in the boiler instead of natural gas. Such a technology can help to decarbonise only if hydrogen comes from renewables, which is where most of the sceptical views are concentrated29. In the short term, hydrogen in buildings will remain expensive, mainly due to the lack of infrastructure for distribution and the high investment costs, but after 2030, upscaling of hydrogen supply for the industry will lead to the availability of low cost H2 for other applications (Rongé and François 2021).

As reported by the JRC paper on the role of hydrogen in decarbonisation scenarios (Tarvydas, 2022), different studies claim that power generation from hydrogen increases tenfold (compared to 2030), reaching 162 TWh, while the same analyses see around 4-5% of the electricity demand met by hydrogen by 2050. The main issue concerns the RES installed capacity needed to produce the (green) hydrogen that can be reconverted into electricity (a process that currently involves substantial energy losses). For a sustainable power plant, the access to the fuel will be crucial, while the mode of fuel (H2) transport and distance have a strong impact on costs and distribution emissions. Likewise, the storage volumes and capabilities need viable solutions30. Finally, besides the role hydrogen can play in mitigating seasonal variations in RES production through long-term storage of electricity, fuel cells and hydrogen can also provide for a low-emission alternative as back-up power for critical infrastructures (e.g. data centres, hospitals…) and can provide off-grid power supply for remote areas (Ruf et al. 2018).

Finally, we briefly discuss the competition clean hydrogen will have to face to win its way into the economy, as in almost all use cases there can be cheaper, simpler, and safer solutions towards full decarbonisation. The following concepts will take into account the techno-economic aspects of hydrogen use cases, without considering the push-factor represented by policy support schemes and incentives, that will instead be discussed – at an EU level – in the next chapter. Figure 9 shows the so called «clean hydrogen ladder», which summaries in a simple graphic – based on peer-reviewed research – where clean hydrogen is sure to be part of a net-zero future («unavoidable») and where there are other solutions available («uncompetitive»), along a series of steps on the ladder (red to green). The combination of thermodynamics, micro-, macro-economic, and geopolitical factors within a simple figure can be a double-edged weapon, but it is useful to put all the pieces together. Indeed, the H2 uses mentioned above, such as steelmaking, long-term electricity storage, long-haul aviation, and shipping, are also in the upper part (future scale-up) of the ladder. Some other uses, such as domestic heating, urban and short-range transport are in the bottom part of the ladder mainly because of the current lack of proper infrastructure (like distribution lines or hydrogen refuelling stations) and thus higher overall costs.

Figure 9 – Clean hydrogen ladder 5.0. Source: Liebreich, M. (2023).

The Clean Energy Package (CEP) still represents one of the main legal frameworks on which the existing energy and climate legislation at the EU level is based, while it has been revised through the Fit-for-55 and REPowerEU initiatives. The CEP is only the fourth of the so-called «packages» that have shaped and steadily updated the European energy (mainly electricity and gas) markets. After the «First Energy Package», which consisted of an Electricity Directive (1996/92) and a Gas Directive (1998/30), the energy market liberalisation efforts were coupled with further market integration steps. The «Second Energy Package», adopted in 2003, contained two Directives (for gas and electricity) and one Regulation (on access to the network for cross-border exchanges in electricity), while mandating the creation of independent national regulatory authorities (NRAs). Thanks to this package, households and industrial consumers were free to choose their gas and electricity suppliers, thus fostering competition in the market. Finally, two Directives and three Regulations constituted the «Third Energy Package», adopted in 2009. The updated gas and electricity Directives were accompanied by the Regulation (713/2009) establishing the Agency for the Cooperation of Energy Regulators (ACER), the Regulation (714/2009) on conditions for access to the network for cross-border exchanges, and the Regulation (715/2009) on conditions for access to the natural gas transmission networks (Florence School of Regulation 2020a). An example of the increasing importance accorded to market integration and cross-border cooperation was the creation of the European Networks for Transmission System Operators for electricity and gas (ENTSO-E and ENTSO-G). The CEP contains four Directives and four Regulations, mostly concerning electricity and energy efficiency. Table 5 summarises the eight pieces of legislation contained in the CEP.

The objective of the CEP was thus to make the EU energy market suitable for the low-carbon transition, even though - unlike the previous packages - it did not include specific legislation for the gas sector, focusing instead on electricity. A separate new gas package was indeed foreseen to be put forward by the Commission in 2020, but also due to the emergency spurred by the COVID-19 pandemic and the subsequent policy initiatives (e.g., Next Generation EU), the new gas framework was proposed in conjunction with the Fit-for-55 package, in late 2021, and has been referred to as the «Hydrogen and Decarbonised Gas Market Package». The latter piece of legislation thus provides a sort of complement to the CEP, since it is crucial to create a consolidated framework and provide regulatory certainty to facilitate the integration of low-carbon and renewable gases into the market.

Table 5 – Acts adopted under the Clean Energy Package. Source: own elaboration based on European Commission (2019) and Florence School of Regulation (2020a and 2020b).

The Communication3 presented in July 2020 to the European Parliament and Council by the European Commission referred to as the «EU Hydrogen Strategy» has got at its core the goal of the Commission to significantly reduce the production costs of «green» hydrogen, so as to make it competitive with fossil-based H2. The strategy includes however also a long-term geopolitical and industrial ambition: Europe is a highly competitive player in clean H2 production technologies, and it could reap significant benefits from the development of a global hydrogen market (Grossi 2020)4. The difference between the past peaks of interest in hydrogen and today’s situation is mainly due to the rapid developments in renewable energy technologies and the subsequent cost decline of renewables, which open new possibilities for hydrogen. The 2020 EU Hydrogen Strategy estimated that cumulative investments in renewable hydrogen in Europe could be up to €180-470 billion by 2050, and in the range of €3-18 billion for low-carbon and fossil-based H2, while employing more than 1 million people in the hydrogen value chain (European Commission 2020a). Table 6 summarises the stages into which the Commission decided to divide the H2 strategy5. While the H2 market is likely to develop through a gradual trajectory and at different speeds across sectors, the policy focus must be initially on laying down the regulatory framework for a liquid and well-functioning market and on incentivising both supply and demand in lead markets (mainly industrial applications and mobility), including through bridging the cost gap between conventional solutions and renewable and low-carbon hydrogen and through appropriate State aid rules (European Commission 2020a).

Table 6 – Phases of the EU Hydrogen Strategy. Source: own elaboration based on European Commission (2020a) and Tarvydas (2022).

The rules designed and proposed so far by the EU institutions are targeted at an emerging market that should first establish itself. In 2025, market growth has remained insufficient to meet EU and national targets, as electrolyser capacity only reached 308 MW in 2024, hence way behind the 6 GW target for 2024 and 40 GW for 2030 (European Union Agency for the Cooperation of Energy Regulators 2025).

It is interesting to address the progresses made by the EU from the publication of the H2 strategy in 2020 up to the time of writing. This can be done by assessing the 20 «key actions» outlined in the document of the EU Hydrogen Strategy, and reported in Table 7, together with the follow-up information about their implementation. These actions are sub-divided into five dimensions: 1) an EU investment agenda, 2) actions to boost hydrogen demand and production, 3) a supportive framework for infrastructure and market rules, 4) promotion of research and innovation in H2 technologies, and 5) the international dimension.

Table 7 – Key Actions of the EU Hydrogen Strategy. Source: own elaboration based on European Commission (2020a) and European Commission: https://energy.ec.europa.eu/topics/energy-systems-integration/hydrogen/key-actions-eu-hydrogen-strategy_en.

The EU strategy on hydrogen is complemented by the Strategy for Energy System Integration (ESI), which was released at the same time, in July 2020. Without adopting a systemic perspective, it is indeed more difficult - if not impossible - to exploit the transformations occurring in one sector to foster advancements in other sectors of the energy system. The latter today is still built on several parallel, vertical energy value chains, which rigidly link specific energy resources with specific end-use sectors (European Commission 2020b). For instance, petroleum products are predominant in the transport sector and as feedstock for industry. Coal and natural gas are mainly used to produce electricity and heating. Electricity and gas networks are planned and managed independently from each other. Market rules are also largely specific to different sectors. According to the ESI strategy, such a model of separate silos is technically and economically inefficient and leads to substantial losses in the form of waste heat and low energy efficiency. This is why emerging technologies, such as renewable hydrogen, can not only contribute to decarbonisation, but can transform the same structure of the energy system, by integrating different energy carriers flexibly and fostering decentralisation.

Energy system integration can be defined as «the coordinated planning and operation of the energy system as a whole, across multiple energy carriers, infrastructures, and consumption sectors» (European Commission 2020b). The main idea behind integrated energy systems, which are also known as «multi-energy systems» or «hybrid energy systems», is to move from a single energy carrier to multiple energy carriers to exploit the synergies from their interplay, thereby increasing the efficiency in the energy resources used (Graditi and Di Somma 2022). In their book Technologies for Integrated Energy Systems and Networks, Graditi and Di Somma (2022) define this concept as an integrated infrastructure for all energy carriers with the electrical system as a backbone, characterised by a high level of integration between all networks of energy carriers, coupling of electrical and gas networks, heating and cooling, supported by energy storage and conversion processes. Figure 10 shows such a concept, which links the various energy carriers with each other and with the end-use sectors (households, tertiary sectors, industry and transport).

Figure 10 – Scheme of an integrated energy system. Source: Graditi and Di Somma (2022).

Therefore, energy system integration relies on «sector coupling» to achieve full integration. Sector coupling can be defined as «the process of progressively interlinking the electricity and gas sectors - by optimising the existing synergies in the generation, transport, and distribution of electricity and gas - with the ultimate scope to build a decarbonised and hybrid EU energy system» (Florence School of Regulation 2020c). Therefore, despite being limited to electricity and gas, sector coupling is the key to integrate more sectors in the future, given the projected increase in electrification of end-uses, and the enhanced role of clean molecules (mainly biomethane and hydrogen). Power-to-Gas (P2G) technologies, already mentioned in this work, are a typical - and rather new - instrument to foster sector coupling, because they can serve the double purpose of converting curtailed electricity into renewable (or low-carbon) hydrogen (depending on the type of electricity used) for storage or direct use, and even into natural gas (after methanisation) (Florence School of Regulation 2020c). As reported in Van Nuffel (2018), sector coupling leads to a lower overall cost, mainly because of reduced investment costs, since the lower peaks in electricity demand and supply allow for less reinforcement investments in the electricity transmission and distribution grids and require less gas-based power generation capacity. Hence, also efficiency can be higher in a system with sector coupling, which uses assets in a more economical way. This is why the EU ESI Strategy aims at gradually shaping a new integrated energy system, by putting forward concrete policy measures that have been divided into six main pillars: 1) a circular energy system based on efficiency, 2) increased electrification based on renewable energy sources, 3) renewable and low-carbon fuels in hard-to-abate sectors, 4) empowering consumers’ choice, 5) infrastructure integration, and 6) digitalisation for a smarter interconnection.

The pillars of the ESI Strategy have been confronted with numerous challenges. Firstly, the application of the «energy efficiency first» principle must materialise, while the Primary Energy Factor (PEF) 12 can be used as a tool to facilitate comparisons of savings across energy carriers. Secondly, electrification has shown a slower pace, increasing only by 5% in the last thirty years (European Commission 2020b). For this reason, and according to the provisions of the new RED III (see section 2.1.4.2. below), it is crucial to accelerate permitting for installing renewable power capacity and further electrify the energy mix. Part of such newly installed renewable capacity must be used to ramp-up clean hydrogen production, as this molecule is a critical enabler of system integration, and methane-based H2 with CCS has been facing a too slow growth. This is also because a proper CCS system needs an integrated infrastructure to manage and transport CO2. It is important to keep in mind that infrastructure investments typically have an economic life of 20 to 60 years, so there can also be a serious risk of lock-in effects and stranded assets.

Among the other aspects included in the REPowerEU Plan the European Commission launched the so-called «Hydrogen Accelerator», aimed at complementing the EU Hydrogen Strategy, and increasing the EU’s ambitions on renewable hydrogen, envisaging a total investment range of €335-471 billion only by 2030. A new target of 10 million tonnes (Mt) of renewable hydrogen imports into the EU by 2030 has been established, together with the target of 10 Mt of domestic renewable H2 production (European Commission 2022b). Of this domestically generated hydrogen, about 6.6 Mt was already considered in the Fit-for-55 scenario, therefore REPowerEU has increased the internal production by 3.4 Mt. At the external level, the 10 Mt of H2 import are subdivided into 6 Mt of renewable hydrogen and 4 Mt of ammonia.

Since 1 Mt of hydrogen has an energy value of around 33 TWh, this means that at least 350 TWh of additional renewable electricity generation will be required to produce 10 Mt of H2 per year by 2030. To have an estimate, this compares to 541 TWh of solar and wind generation in the EU27 in 2020, while the total EU27 gross electricity generation (including hydro, fossil fuels, and nuclear) was of 2781 TWh (Barnes 2023). On the demand side, the REPowerEU Plan rests on some critical assumptions regarding hydrogen usage within the EU. Figure 13 compares the projected hydrogen use by sector in 2030, as estimated by the Fit-for-55 Package first, and then by REPowerEU.

The Commission assumes a reduction in natural gas demand by industry of 35 bcm between 2021 and 2030, based on increased energy efficiency and a switch to alternatives such as electrification and hydrogen. Out of the 35 bcm reduction in natural gas demand, 27 bcm is expected to be replaced by 8 Mt/y of hydrogen, with 2 Mt/y replacing oil and coal use (Barnes 2023). The use of hydrogen in industrial heat, for example, is planned to increase 4.5-fold compared to the Fit-for-55 targets. A more than 2.5-fold increase is envisaged in the transport sector.

Figure 13 – Hydrogen use by sector in 2030 [Mt of H2]. Source: European Commission (2022b).

The expected drop in natural gas use can raise the potential for repurposing existing gas pipelines for hydrogen transportation. Although cross-border hydrogen infrastructure is still in its infancy, the basis for planning and development has already been set by the inclusion of hydrogen infrastructure in the revised Trans-European Networks for Energy (TEN-E) (European Commission 2022c). Given the 10 Mt import target, several «hydrogen corridors» have been identified and partnerships with third countries have been established. Studies indicate that until 2030 the imports of hydrogen into the EU are most cost-efficient via pipelines from the neighbourhood and in the form of ammonia through ships over long distances (European Commission 2022b)45.

The REPowerEU Hydrogen Accelerator also includes several policy initiatives and legislative proposals that have been integrated into the current revision process of key energy legislation (e.g. the Hydrogen and Decarbonised Gas Markets Package and the Renewable Energy Directive). Besides the already mentioned sub-targets for RFNBOs under the RED for industry and transport, and the adoption of the two hydrogen Delegated Acts, the REPowerEU Action Plan also includes the regular reporting on the uptake of renewable hydrogen in key sectors (starting in 2025), the proposal to double the number of the so-called Hydrogen Valleys46, the scale-up of electrolyser manufacturing, whose details are outlined in the «Electrolyser Declaration», and the mapping of the hydrogen infrastructure needs47 (Conti and Kneebone 2022). In addition, as was reported in the section covering the progresses of the EU Hydrogen Strategy, the 840 investment projects collected under the European Clean Hydrogen Alliance, include the production of H2 (the installation of over 50 GW of electrolysers), transportation and usage of hydrogen by industry, mobility applications, energy systems and buildings (European Commission 2022b). The discussion on the Important Projects of Common European Interest (IPCEI) on hydrogen, and the need to fast-track them, will be addressed in the section 2.5 on H2 funding flows.

After the announcement made by Commission’s President Ursula Von der Leyen in her State of the Union speech in September 2022, the European Commission presented the European Hydrogen Bank (EHB) through a Communication in March 202348. The EHB is an instrument, implemented by the European Commission, consisting of two financing mechanisms to support renewable hydrogen production within the EU and internationally, while providing data on hydrogen demand, supply, flows and prices and playing a coordination role to facilitate the blending with the existing financing instruments (such as the EU funds) to support hydrogen projects (European Commission 2023b). This initiative has been spurred mainly by the need to close the current investment gap - estimated at around €90-115 billion - and connect future renewable hydrogen supply with the EU’s demand objective, including imports of H2 from international producers.

Today, Europe hosts over 30% of proposed hydrogen investments globally, but while the first final investment decisions (FIDs)49 took place in 2022, a vast majority of hydrogen investments in Europe are still at the planning stage (European Commission 2023b). This can be traced back to two main reasons: on the one hand, investors need regulatory certainty and therefore the regulatory framework mentioned in the previous sections should be quickly finalised, and on the other hand, more demand visibility is needed. This is part of the so-called chicken-or-egg dilemma, whereby the demand from customers will not materialise until there are no appropriate infrastructures that supply hydrogen, but without that demand, investors will not finance hydrogen infrastructures, which in turn means zero demand. Table 14 reports the European Commission’s estimated investments needed to achieve the target of 10 Mt of domestic (EU) hydrogen production and to enable the imports of an additional 10 Mt from third countries.

Table 14 – Estimated investments needed to achieve the target of 20 Mt/y of green hydrogen and derivatives (billion €). Source: European Commission (2023b).

Given the H2 investment challenges mentioned so far - electrolyser manufacturing capacity, hydrogen production capabilities, expansion of H2 demand in new sectors, and development of dedicated infrastructure - there currently remains a «green premium» in terms of higher costs for those choosing hydrogen over fossil fuels. The green premium is the additional cost of choosing a clean technology over one that emits more GHG (i.e. the difference between the costs of the two technologies), and therefore it helps to see which barriers still need to be overcome (Breakthrough Energy 2022). According to the European Commission, the targeted use of public resources to finance the green premium can leverage private sector investments and reduce the risk of investing in renewable hydrogen production. Around €1 billion is estimated to be required to enable 0.04-0.06 million tonnes of renewable hydrogen production capacity per year, and after 2025, the market premium is expected to decline due to decreasing production costs and increased demand for green products produced with renewable hydrogen (European Commission 2023b).

The last part of this section dedicated to hydrogen-specific policy initiatives looks at the spectrum of the funding sources that support the scale-up of clean hydrogen in the EU. The adoption of the two Delegated Acts on RFNBOs has contributed to better channelling EU funds towards renewable hydrogen and to guiding the approval of national state aid schemes for hydrogen projects. Significant investments for the production of renewable hydrogen are also being channelled through the National Recovery and Resilience Plans, as more than €10 billion have been assigned so far under the Recovery and Resilience Facility, and several Member States have been able to provide public funding to hydrogen projects via the Important Projects of Common European Interest (IPCEI). The EU Innovation Fund has been providing resources both for renewable H2 (through fixed-premium auctions) and electrification in industry. The Commission has also allocated an additional €200 million for Hydrogen Valleys, as part of REPowerEU, and has been supporting the work of the Clean Hydrogen Partnership54 to which it provided €1 billion under Horizon Europe (European Commission 2023a).

The funding sources for clean hydrogen also come from the European Investment Bank (EIB) and the InvestEU fund, which aims at mobilising private investment. The latter fund as well as Cohesion Policy funding (mainly through the European Regional Development Fund) and the Just Transition Fund (JTF), mentioned in the European Hydrogen Bank Communication, will provide support to Member States and regions for investments in the whole hydrogen value chain. In addition, the EIB has committed to exceed 50% of its overall lending, by 2025, for climate action and environmental sustainability, and it is also one of the «implementing partners» of the InvestEU fund, together with the European Bank for Reconstruction and Development and the Nordic Investment Bank. In the past decade, the EIB provided over €1 billion in financing directly linked to hydrogen projects, and this was recently complemented by the EIB’s REPowerEU €30 billion package which aims to mobilise up to €115 billion by 2027 of investments leading to decarbonisation of the EU industry (European Commission 2023b).

The Ten-Year Network Development Plan (TYNDP) provides an overview of the European gas infrastructure and its future development, by mapping the integrated gas network according to a range of development scenarios (ENTSOG 2023a)60. For the first time, in the TYNDP 2022, ENTSOG developed a dual gas system modelling approach considering both methane and hydrogen networks simultaneously, thus adjusting the TYNDP to include REPowerEU ambitions with respect to hydrogen infrastructure development. The parallel policy-based infrastructure assessment was developed by ENTSOG together with the TSOs to incorporate additional infrastructure needs required to comply with the relevant policy objectives, such as the 2030 hydrogen imports targets defined by the REPowerEU Plan (ENTSOG 2023a). The approach developed by ENTSOG in the TYNDP 2022 refers to both the existing natural gas infrastructure and the planned natural gas and hydrogen infrastructure. Both types are interconnected, allowing to capture interactions between the two gases and assess the role of the transmission system of both fuels in satisfying demand under different conditions.

For the purpose of this work, it is essential to outline the planned and ongoing hydrogen projects, also considering the potential repurposing of gas transmission lines. Today in the EU and the UK around 205 000 km of gas pipelines exist (ENTSOG 2023b), as shown in Figure 15. Given that, unlike methane, hydrogen infrastructure levels can only be defined with the consideration of planned projects, the TYNDP 2022 defines two contrasted hydrogen infrastructure levels (ENTSOG 2023c):

– Level 1 is a project-based infrastructure level, composed of all hydrogen projects submitted by project promoters to the TYNDP 2022 (including infrastructure submitted as «hydrogen-ready») as well as H2 projects submitted to the first Projects of Common Interest (PCI) selection process under the revised TEN-E Regulation61;

– Level 2 is defined as a policy-based infrastructure, composed of hydrogen infrastructure level 1 and additional infrastructure assumptions needed to enable the EU policy objectives for hydrogen.

Figure 15 – Transmission length in the EU and UK in 2022 [km]. Source: ENTSOG (2023b).

With the current 33 member companies participating63, the European Hydrogen Backbone Initiative (from now on «the Initiative») aims at defining the critical role of hydrogen infrastructure in the EU’s decarbonisation effort and in the creation of a liquid and competitive renewable and low-carbon hydrogen market. The Initiative was conceived in 2020 and it has been developing transmission scenarios, connecting hydrogen supply and demand in Europe, towards 2030 and 2040. By examining its regular reports, it is possible to understand the importance of having a new regulatory framework able to ensure hydrogen integration, and to connect the dots with the previously outlined elements, such as the emergence of two parallel gas transport networks, one dedicated to hydrogen, and the other to (bio)methane. The Initiative estimates that around 30 000 km of hydrogen pipelines will be commissioned by 2030, and around 57 600 km by 2040 (European Hydrogen Backbone 2023). Table 17 summarises the envisioned length of the future hydrogen network, as projected by the Initiative.

Table 17 – Envisioned length of the EHB network [km]. Source: own elaboration based on European Hydrogen Backbone (2023).

While ongoing multiple studies are investigating to which extent it is technically feasible and economically efficient to use the existing natural gas infrastructure for the transport of hydrogen, according to Grote et al. (2022), about 70% of the total onshore pipeline length in Europe could possibly be reused or repurposed for the transport of hydrogen. Although repurposed pipelines will represent a clear majority of the overall network, the increase in total pipeline length for the 2040 network is mainly due to the newly built pipelines (European Hydrogen Backbone 2023).

Previous analyses of the Initiative have shown that a hydrogen pipeline can transport some 65 TWh of hydrogen per year (Van Rossum et al. 2022). This result is based on two assumptions: 1) a pipeline can transport around 13 GW of hydrogen (capacity), and 2) a load factor of 5000 hours in a year is considered. By multiplying the capacity (13 GW) by the time (5000 hours), we obtain 65000 GWh, that correspond to 65 TWh. This means that transporting 10 Mt (or 330 TWh) of hydrogen, as set by the REPowerEU import target, would require approximately five (65 TWh multiplied by 5) large-scale pipeline corridors towards Europe.

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).