The European Commission presented the «Fit-for-55» Package in July 2021 to implement and achieve the aims of the European Climate Law, which took effect on 29th July 2021. The package consisted of thirteen interlinked strategic and legislative proposals to revise existing EU energy and climate laws and six proposals to adopt new legislation. After setting ambitious targets such as climate neutrality by 2050 and a 55% reduction of net GHG emission by 2030, the European Commission also designed an equally ambitious and strict timeline to reach those objectives, which however must consider the possible frictions and obstacles enshrined in the EU ordinary and special legislative procedures. As is being demonstrated at the time of writing, final decisions on some of the proposed legal acts have yet to be made, while other acts have been recently adopted or politically agreed upon13.

Some of the changes proposed through the «Fit-for-55» Package are not limited to one specific sector or sub-sector, but are intended as cross-sectoral regulatory acts, that contribute to integrating the energy system to other sectors. Figure 11 provides an explanatory overview of those linkages between sectors and shows the legislation proposed to realise the objectives of the EU Climate Law. The key areas of action of Fit-for-55 are the energy, buildings, and transport sectors. Some links between the key proposals imply, for instance, that the revised Gas and Hydrogen Regulation and Gas and Hydrogen Directive (both part of the «Hydrogen and Decarbonised Gas Market Package») refer to the revised Renewable Energy Directive (RED) for the definition of renewable gas. In turn, both the RED and the Energy Performance of Buildings Directive (EPBD) refer to definitions included in the revised Energy Efficiency Directive (EED)14. The latter and the proposal for a Social Climate Fund (SCF) refer to each other with respect to the use of the fund15. Finally, the Energy Taxation Directive (ETD)16 refers to the definitions in the revised RED and in the new Alternative Fuels Infrastructure Regulation (Erbach and Jensen 2022).

Figure 11 – The «Fit-for-55» Package. Source: Erbach and Jensen (2022).

While the legislative proposals introduced with the «Fit-for-55» Package were being negotiated by the EU institutions, the European Commission published the REPowerEU Plan on 18th May 2022, to respond to the energy market disruptions sparked by Russia’s war against Ukraine17. This initiative included actions in four key areas, which had been also affected by the tightening of energy supply chains and increased gas prices since late 2021. The plan includes efforts targeted at diversifying and securing the EU’s energy supplies, as well as saving energy and boosting renewables. The updates that REPowerEU has brought to Fit-for-55 are aimed at preserving and strengthening the EU’s climate policy trajectory, including enhanced targets for green and low-carbon gases, such as biomethane and hydrogen. Table 8 gives an overview of the main amendments put forward with REPowerEU concerning the Fit-for-55 legislative proposals. Besides the short-term measures taken to fill gas storages and diversify the energy supply away from Russian fossil fuels, the REPowerEU Plan has focused on a series of targeted amendments to the RED, the EED, and the EPBD. Since all three directives were already in the process of being revised as part of Fit-for-55, the amendments are meant to feed into this ongoing process of legislative revision.

Table 8 – Main legislative updates of REPowerEU. Source: own elaboration based on European Parliament (2023a).

Given the scope of this thesis, the REPowerEU Plan will be mentioned in the light of the initiatives targeted at developing hydrogen, even though some other major changes have been rolled out by the European Commission to strengthen the EU energy system. One critical measure is represented by the mandate to add a «REPowerEU chapter» in the National Recovery and Resilience Plans (NRRPs), thus also increasing the financial resources to bring about decarbonisation20. Furthermore, boosting the industrial low-carbon transition and the use of renewables are two key areas of action, as well as investments in energy infrastructures and interconnections.

2.1.4.1 Hydrogen and Decarbonised Gas Market Package

The revision of the Gas Directive (2009/73/EC) and the Gas Regulation (2009/715/EC) is part of the «Hydrogen and Decarbonised Gas Market Package» (HDGMP), proposed by the European Commission in December 2021. Two years after, in December 2023, the EU’s legislative institutions managed to agree on a final version of both the Directive and Regulation, both of which were formally adopted in early 2024, with the aim to create a favourable regulatory environment for the uptake of the so-called «clean molecules». In 2021, power and heating generation represented the largest share of natural gas use in the EU at roughly 31% of overall consumption, while around 24% of gas was used by households, and a further 23% by the industry sector (European Council 2023). The EU’s total natural gas consumption was around 343 billion cubic metres in 2022 (Statista 2023)21. A significant amount of this demand is likely to be electrified in the future as it is typically more efficient in the context of a renewable-dominated energy mix. Within this context, projections for the gas sector broadly envisage a diminished overall role for molecules (Olczak and Piebalgs 2019). However, there is likely to still be a requirement for significant volumes of molecular energy. This is due in part to the physical properties of energy in such a form. According to the TYNDP 2022 Scenario Report22, current national policies show a large role for methane with very limited evolution of the demand until 2030, when the methane demand will decrease with the implementation of the strategy of some Member States which see the uptake of their hydrogen demand (ENTSO-E and ENTSO-G 2022). Figure 12 clearly shows that the current share of fossil gas consumption will have to be almost completely replaced by clean molecules (biogas, hydrogen, and e-gases) by 2050.

Figure 12 – Total consumption of gaseous fuels in 2050 [Mtoe]23. Source: European Commission (2021a).

The Commission’s initial proposal set two main goals. On the one hand, the package had to establish the legislative base for the decarbonisation of gas markets, and on the other hand, it was aimed at creating a hydrogen market (Tanase and Anchustegui 2022). These objectives will contribute to putting Europe at the forefront in terms of regulatory innovation in an area that is expected to be a vital component of the energy transition. The latter goal includes the creation of regulatory incentives towards a fit-for-purpose infrastructure where hydrogen can be cost-effectively transported from production to consumption (Tanase and Anchustegui 2022). Table 9 summarises the key areas of revision of the rules within the HDGMP, as proposed by the European Commission at the end of 2021.

Table 9 – Key areas of revision in the European Commission’s HDGMP proposal. Source: own elaboration based on Tanase and Anchustegui (2022).

One critical aim of the HDGMP is to ensure a more integrated network planning between electricity, gas and hydrogen networks, as emphasised in the EU Strategy for Energy System Integration. According to the Commission, at the national level, there may continue to be two separate network plans for gas and electricity, but both will need to be developed on the basis of a joint scenario covering electricity, gas and hydrogen, as this helps to ensure that there is a common vision between different energy vectors in the future (European Commission, 2021a)24. The initial HDGMP proposal introduced an additional national network planning for hydrogen and an EU-wide ten-year network development plan, which would include the modelling of an integrated network, build on national hydrogen network plans, national investment plans, cross-border interconnectors, and identify gaps in investments. The revised Gas Directive, as agreed by the EU legislators, requires gas TSOs and hydrogen network operators to prepare every two years a ten-year network development plan for methane and H2, while hydrogen distribution network operators must cooperate with electricity and natural gas distributors to develop a network plan every four years (Council of the European Union 2023c).

Infrastructure is thus the keystone of the future development of an integrated hydrogen market. The European Commission assumes that there will be two gaseous networks: a methane-based infrastructure, which will evolve from the current natural gas-based system to one which uses more biomethane and synthetic methane; and a hydrogen-based infrastructure, which will complement and partly replace the current natural gas one (Barnes 2023). This is why also a separate organisation for hydrogen operators (ENNOH) was included in the initial proposal, and it has been kept in the final agreement between the Council and Parliament (Council of the European Union 2023d), even though the latter institution had insisted on expanding the role of the already existing ENTSO-G to also cover hydrogen network operators, thus becoming an “ENTSO-G&H” and avoiding the creation of the ENNOH (European Parliament 2023b). Although we could claim that integrating those operators into the already existing ENTSO-G would have been faster and could have provided benefits from common expertise, the revised legislation requires ENTSO-G to also prepare the hydrogen network plans for a transition period (until 2027) until the ENNOH is established (Council of the European Union 2023d). The creation of a new separate entity to coordinate future hydrogen operators could be also justified by the fear (mostly felt by the Council) that having one single ENTSO-G&H might give an incentive to incumbent (natural gas) operators to exclude potential new entrants, thus distorting the market to their advantage.

Regarding hydrogen networks, the Commission initially proposed to abolish tariffs at interconnection points between different Member States from 2031 (Barnes 2023). Given that tariffs would have been equal to zero, the national regulatory authorities (NRAs) should have agreed a system of financial compensation for cross-border H2 infrastructure, because tariffs are usually the essential means through which network operators recover their revenue and thus enable the physical flow of gas in the system. Cross-border tariffs reflect the cost of moving gas from one network in one country to another. The proposal to remove such tariffs on hydrogen networks was based on the Commission’s idea that cross-border transport tariffs hinder trade25. However, as we pointed out, removing those tariffs will require several network operators to agree revenue-sharing mechanisms which would be complex.

As a result, the EU’s co-legislators agreed that for the hydrogen market every national regulatory authority must consult the neighbouring NRAs on the draft tariff methodology and submit it to the Agency for the Cooperation of Energy Regulators (ACER), while each Member State, and thus every NRA, will maintain the right to set its own tariff (Council of the European Union 2023d). The revised Gas Regulation adds the possibility for EU countries to merge adjacent entry-exit systems - i.e. the different zones of the gas network - to achieve regional integration where tariffs can (but do not have to) be abolished at the interconnection points. When choosing such option, the regulatory authorities may approve a common tariff and an effective compensation mechanism between TSOs for the redistribution of costs on account of the abolished interconnection points (Council of the European Union 2023d). The legislators also agreed on a series of discounts on tariffs for renewable and low-carbon gases accessing the natural gas system, concerning:

1. the injection from production facilities, with a discount of 100% for renewable and 75% for low-carbon gas;

2. the injection to and withdrawal from storage facilities, with a 100% discount in the Member State where the renewable and low-carbon gases were first injected into the system;

3. the interconnection points between Member States, with a discount of 100% on the capacity-based tariffs26 for all network users, after one year from the entry into force of the revised Gas Regulation, and only after providing the respective TSO with a proof of sustainability, based on a valid sustainability certificate in accordance with the Renewable Energy Directive II.

Regarding hydrogen blending at interconnection points in the gas grid, the Parliament and Council agreed on a 2% instead of a 5% H2 share, as had been initially proposed by the Commission. Some experts have argued that the supply of renewable hydrogen will be so limited in the early years that it is better to focus its use on hard-to-electrify sectors such as heavy industry, rather than «waste» it by blending it into natural gas flows (Barnes 2023). Moreover, at present, the permitted proportion of hydrogen in gas transmission networks varies significantly from one EU Member State to another. For instance, only 0.5% is allowed in Sweden, 4% in Austria, 5% to 10% in Germany and up to 12% in the Dutch gas grid (Zemite et al. 2023).

The revised Gas Directive includes a reference to «low-carbon hydrogen», thus potentially opening the way to the so-called blue H2. The 9th recital states that «In line with the EU Hydrogen Strategy, the priority for the Union is to develop renewable hydrogen produced using mainly wind and solar energy». It nonetheless continues stating that «Low- carbon fuels (LCFs) such as low-carbon hydrogen (LCH) may play a role in the energy transition, […] particularly in the short and medium term to rapidly reduce emissions of existing fuels, and support transition of the Union’s customers in hard-to-decarbonise sectors in which more energy or cost-efficient options are not available». A more precise - even though incomplete - definition of «low-carbon hydrogen» is provided by Article 2 of the revised Gas Directive, where such type of H2 is included in the concept of «low-carbon gas» which meets a «greenhouse gas emission reduction threshold of 70%» (Council of the European Union 2023c)27.

As a final item in the revision of the gas package, the issue of unbundling - the separation of energy supply generation from the operation of the transmission network - should be mentioned. In its initial proposal, the Commission suggested a horizontal unbundling model, i.e. when a hydrogen network operator is part of a company active in transmission or distribution of natural gas (or electricity), it must be independent at least in terms of its legal form and must ensure that accounts are kept separate between the two activities (Tanase and Anchustegui 2022). After 2030, however, the Commission proposed the Ownership Unbundling (OU) model, i.e. the highest degree of unbundling, which prevents a company that owns and operates a network from being active in the other (competitive) segments of the hydrogen or gas supply chain. Such a proposal would nonetheless prevent transmission system operators (TSOs) in several Member States from owning and operating a hydrogen network after 2030, with the effect of disincentivising investments into hydrogen and its supporting infrastructure. This is also why the Council of the EU and the European Parliament decided to allow other, less restrictive, unbundling models to apply to hydrogen networks, and they agreed to allow Member States not to apply the OU model under certain conditions (Council of the European Union 2023c)28.

The integration of clean molecules in the EU’s energy mix still faces limitations and bottlenecks. First, replacing fossil gas with biomethane or hydrogen does not completely solve the issue of lifecycle GHG emissions. Clean molecules can also be climate forcers, characterised, for instance, by fugitive emissions. Secondly, the aspect of lifecycle emissions involves an opportunity cost, concerning the allocation of scarce resources (e.g. renewable electricity) to different uses, such as electrolysis to produce green hydrogen, or the electrification of transport applications. That is why different EU initiatives aimed at decarbonisation may end up competing for the same renewable electricity. Thirdly, the cost-effectiveness of clean molecules and the speed at which they can be scaled largely depend on the cost and availability of renewable electricity, as well as the support schemes introduced by governments. Unsubsidised, renewable hydrogen typically remains uncompetitive with fossil H2 in most of the circumstances.

The Hydrogen and Decarbonised Gas Markets Package is strongly linked with the proposals set out in the revised Renewable Energy Directive (RED). After the adoption of RED II (Directive 2018/2001), the European Commission expanded its scope with the proposals included first in Fit-for-55, and then in REPowerEU. The latter plan indeed raised the required share of renewable energy sources (RES) in the EU’s final energy consumption to 45% by 2030, and the Commission included measures to accelerate permitting procedures for new RES power plants, whereas Member States would be required to designate «renewables go-to areas» suitable for RES installations (European Parliament 2023a). The proposal also included a series of higher EU and national targets for different sectors (transport, industry and buildings) and the promotion of (renewable) hydrogen consumption in transport and industry (European Parliament 2023d). The European Parliament adopted the more ambitious RES targets (including sector-specific targets) proposed by the Commission, reaching a provisional agreement with the Council on 30th March 2023. The two co-legislators formally adopted the RED III (Directive 2023/2413) in September (Parliament) and October 2023 (Council)29. Table 10 outlines the content of the main items agreed upon by the co-legislators regarding the RED.

Table 10 – Key elements of the Renewable Energy Directive III. Source: own elaboration based on Council of the European Union (2023b).

Most importantly, for the purpose of our discussion, the revised Renewable Energy Directive contains the definition of renewable gas, including renewable fuels of non-biological origin (RFNBOs). The rules to comply with in order for an RFNBO to count towards the EU’s policy targets have been defined in two critical Delegated Acts to the Renewable Energy Directive, published by the European Commission in February 2023, and formally adopted in June 202330. As the number of implemented production projects increased and improvements were made in the generation of RFNBOs, an issue emerged on the end-uses of those fuels and energy carriers, concerning the availability of sufficient renewable electricity to produce them.

RFNBOs are the subject of the first Delegated Act (DA), which defines when hydrogen, hydrogen-based fuels and other energy carriers can be considered RFNBOs. These were first defined in the 2018 Renewable Energy Directive (RED II) as «liquid or gaseous fuels which are used in the transport sector other than biofuels or biogas, the content of which is derived from renewable sources other than biomass»32. However, the Commission proposed to count RFNBOs towards the EU’s renewable energy targets regardless of the end-use sector in which they are used, thus expanding the scope for hydrogen development. Article 1 of the new RED III amends the previous definition, describing RFNBOs as «liquid and gaseous fuels the energy content of which is derived from renewable sources other than biomass». Gaseous renewable H2 produced by feeding renewables-based electricity into an electrolyser is therefore considered an RFNBO, whereas liquid fuels, such as ammonia (NH3), methanol, or e-fuels, are considered RFNBOs when produced from renewable hydrogen (European Commission 2023a).

The first DA is also known as «Additionality Delegated Act» because the rules that it sets out aim to ensure that RFNBOs are only produced from «additional» renewable electricity, which is generated at the same time and in the same area as the production of RFNBOs33. Unless the electricity system is already largely decarbonised, it is indeed crucial to match the electricity demand for hydrogen production with additional renewable electricity generation (European Commission 2023a). If H2 production were not matched by additional RES electricity, the additional electricity demand of electrolysers (used to produce H2) could lead to increased fossil-based power generation, thereby increasing - rather than decreasing - emissions. According to the RED II, as of 1st January 2021, RFNBOs are indeed counted towards the EU’s renewable energy targets if they deliver GHG emissions savings of at least 70% compared to fossil fuels (Erbach and Svensson 2023)34.

Because the Renewable Energy Directive provides for a default rule on grid electricity used to produce RFNBOs, the «Additionality DA» acts as a sort of «derogation», providing two scenarios in which the RFNBOs can be considered fully renewable (i.e., produced with renewable electricity). These two scenarios have been introduced by the Commission mainly because currently (and in the near future), given the 70% GHG emissions reduction requirement, the GHG intensity of the electricity grids in most EU Member States is too high, i.e. not fulfilling the emissions saving requirement of the RED35. The default rule included in the RED states that the share of RFNBOs corresponds to the average share of renewable electricity on the electricity network of the country in which the RFNBO production is located. Table 11 outlines the two scenarios under which the first DA allows the hydrogen (RFNBO) produced to be counted as fully renewable.

Table 11 – Scenarios under the Additionality Delegated Act to count hydrogen produced as fully renewable. Source: own elaboration based on Directive 2018/2001 (RED II) and Baker McKenzie (2023).

While the off-grid option is the simplest approach to ensuring that the electricity used to produce hydrogen is 100% renewable36, it becomes more difficult to ensure that the electricity taken from the grid comes from renewable sources, because it is usually generated by a mix of renewable, nuclear and fossil sources (Erbach and Svensson 2023). Therefore, the first DA outlines four alternative options under which it can be demonstrated that grid electricity used in the electrolyser is renewable (Baker McKenzie 2023):

1. Where the electrolyser is located in a bidding zone37 containing a 90%+ level of renewables, and the number of its production hours is capped at the same percentage of the year (the maximum number of operating hours for the electrolyser operation is determined by multiplying the renewable energy share in the electricity mix by the number of hours in a year);

2. Where the RFNBO production plant is located in a bidding zone in which the emission intensity of electricity generation is lower than 18 gCO2eq/MJ (i.e., a low-carbon bidding zone), it relies on electricity produced under a renewable power purchase agreement (PPA) and it complies with «temporal» and «spatial» correlation requirements set out in the Delegated Act (see below);

3. Where the RFNBO is produced with electricity consumed during an imbalance settlement (i.e., the electricity is consumed during a period of curtailment of RES electricity);

4. All other grid situations (default option) in which the renewable electricity is procured via a renewable PPA, and «additionality», «temporal» and «spatial» correlation requirements are met.

Taking the current European electricity system into account, options 2 and 4 (both involving the conclusion of a PPA with a renewable producer) will be the most common. It is important to explain the three requirements (additionality, temporal and spatial correlation) that are present in those two scenarios, as well as in the off-grid option with the electrolyser directly connected to the renewable power plant. Table 12 reports the three criteria as set out in the first DA, showing for each criterion to which scenario they apply. As a general rule, and to facilitate the early ramp-up of hydrogen infrastructure, the Commission’s DA introduces a transitional phase with relaxed rules, i.e. the rules on additionality will not apply until 1st January 2038 for the renewable power plants that came into operation before 1st January 2028. This is mainly because the planning, permitting processes and installation of new additional renewable power takes time and could result in delays in the deployment of electrolysers, limiting the potential to create economies of scale (European Commission 2023a).

Table 12 – Criteria of additionality, temporal correlation and spatial (geographical) correlation. Source: own elaboration based on Baker McKenzie (2023) and Erbach and Svensson (2023).

This Delegated Regulation (the «Methodology Delegated Act») establishes a methodology for calculating the lifecycle GHG emissions savings achieved from using RFNBOs and recycled carbon fuels (RCFs), given the 70% emission reduction criterion foreseen by the RED II40. For the purpose of our discussion, we will focus the following analysis on RFNBOs only, and hydrogen in particular. The methodology established by the second DA defines the total lifecycle emissions from the use of RFNBOs as the sum of emissions from the supply of inputs (including electricity, processing, transport and distribution, and combustion of the fuel in its end use) minus any emissions savings from carbon capture and storage (Erbach and Svensson 2023). More precisely the formula used to calculate GHG emissions from production and use of RFNBOs is the following41:

E = ei + ep +etd + eu - eCCS(6)

where E are the total emissions from the use of the fuel (gCO2eq/MJ of the fuel)42, ei the emissions from supply of inputs43, ep the emissions from processing, etd the emissions from transport and distribution, eu the emissions from combusting the fuel in its end use, and eCCS the emission savings from carbon capture and storage (CCS). Emissions from the manufacture of machinery and equipment are not considered by the Annex to the Methodology Delegated Act (Official Journal of the European Union 2023). Instead, to calculate emission savings from production and use of RFNBOs, the Annex specifies that they shall be calculated as follows:

Savings = (EF - E)/EF (7)

where E represents the total GHG emissions from the use of RFNBOs, and EF the total emissions from the fossil comparator. The latter has been established by the European Commission at a value of 94 gCO2eq/MJ for RFNBOs. Therefore, the reference point set by the second DA means that the total lifecycle GHG emissions from the production and use of RFNBOs (or RCFs) must not exceed 28.2 gCO2eq/MJ (which is equal to the fossil fuel comparator minus the 70% saving, as established by the RED II).

There are several ways to reduce CO2 emissions in the life cycle of RFNBOs. According to Jones et al. (2023) the two main ways of reducing the lifecycle GHG emissions are (i) to use inputs that are associated with avoided emissions (such as captured CO2) and (ii) use carbon capture and storage during the process for making the fuel. It is important to note however that CCS after the fuel’s combustion is not considered in the methodology. For renewable fuels incorporating carbon (notably e-fuels, sustainable aviation and maritime fuels), ensuring that the source of carbon used as part of the production process is associated with avoided emissions is absolutely critical for them to meet the 70% savings requirement (Jones et al. 2023). This is because, chemically speaking, the combustion of these fuels at the point of use produces the same GHG emissions as if they were derived from fossil fuels (Jones et al. 2023).

Given that RFNBOs are produced both via a direct connection to a renewable power plant and via grid electricity, it is important to analyse the methods to assess the emission intensity of the electricity grid, as provided by the second DA. Recital n. 11 of the act states that if the electricity used to produce RFNBOs is taken from the electricity grid, it is therefore not considered as fully renewable, and the average carbon intensity of the electricity consumed in the Member State where the RFNBO is produced should be applied. The delegated act requires the operators to use one of the three alternative methods - set out by the Regulation and outlined in Table 13 - to calculate the carbon intensity of the electricity grid44.

Table 13 – Methods to attribute greenhouse gas emissions values to the electricity taken from the grid not qualifying as fully renewable. Source: own elaboration based on Annex to the Commission Delegated Regulation (EU) 2023/1185.

The EHB’s structure consists of a «domestic» and an «international» pillar. Regarding the first dimension, the domestic pillar supports the scale-up of hydrogen production within the EU, with supply-side auctions allocating fixed premium payments to hydrogen producers (see in detail below). The goal of the international pillar is instead to secure diversified imports of renewable hydrogen (and derivatives) from outside the EU, both with fixed premium payments to international producers and with other funding options that are currently being explored by the European Commission. Given that several Member States have been developing strategies to support the import of hydrogen from third countries51, the Commission is studying how best to design the international leg of the European Hydrogen Bank, considering that imports of H2 will fall within the scope of the Carbon Border Adjustment Mechanism (CBAM) from 202652.

As regards the proposed activities under the EHB, there are four pillars that can be summarised as follows. First, the creation of a domestic market will be initially supported by the EU Innovation Fund (see next paragraph). Second, H2 imports into the EU will be supported by green premium auctions. Third, transparency and coordination activities will include assessments on demand, H2 flows, infrastructure needs and cost data. The fourth pillar of activities is divided into two subjects: the use of existing EU financing instruments, and the existing international financing instruments (concessional loans, guarantees).

The Innovation Fund allocates funds through a pilot auction directed at the production of renewable hydrogen, as defined in the Commission’s Delegated Acts on RFNBOs. Through such market-based tools, the European Commission transfers the funds after interested projects have submitted a bid, in order to receive support, in form of a fixed premium per kg of hydrogen produced, for up to 10 years of operation. The Commission has indeed decided to allocate funds using auctions for three main reasons: 1) because of the successful use of auctions to support renewable power projects in several EU Member States, which have helped lower the price of renewable energy, 2) the efficient allocation of support, which creates competition between producers and provides payments based only on certified and verified H2 production, and 3) the reduced costs for the public and the lower risks, that can attract more private capital (European Commission 2023c). The auction funded by the Innovation Fund under the umbrella of the EU Hydrogen Bank was launched on 23rd November 2023, awarding up to €800 million to renewable H2 producers in the European Economic Area (European Commission 2023c)53.

One significant novelty of this initiative is the so-called «Auctions-as-a-Service» (AaaS) mechanism, put in place by the Commission to enhance the scope of the support to H2 production. Although the RFNBO Delegated Acts provide a uniform basis for the certification of renewable hydrogen across Europe, support schemes can vary considerably between Member States (European Commission 2023b). That is why the Commission has proposed to extend the Innovation Fund auctions as a platform to Member States, enabling them to use their own resources for projects on their territory, by relying on an EU-wide auction mechanism and select the most competitive projects (European Commission 2023b). Hence, through «Auctions-as-a-Service», the Commission would run a single auction, which would first clear the Innovation Fund budget, and then the remainder of the financial support can be supported by Member States themselves.

The EU also decided to link the EHB with «H2Global», Germany’s support scheme for renewable hydrogen. The latter, which is an auction-based instrument, has been financed by the German Government with €900 million for the first «funding window», and its implementation is managed by the H2Global Foundation (H2Global Stiftung), whose subsidiary, HINT.CO (Hydrogen Intermediary Network Company) uses the funding provided to compensate for the difference between supply and demand prices (European Commission 2023d). European Commissioner for Energy Kadri Simson (2019-2024) and German Federal Minister for Economic Affairs Robert Habeck (2021-2025) agreed to link the EHB with H2Global during a bilateral meeting on 31st May 2023 with the aim to expand this approach to other Member States and to jointly develop a European auction targeting international hydrogen imports (Habibic 2023). Thus, it can be argued that the international pillar of the European Hydrogen Bank has been taking shape. As emphasised by the CEO of Hydrogen Europe (a major EU hydrogen industry association), such a step was needed to remain credible with the implementation of the EU Hydrogen Strategy, since the EU will need more hydrogen than it can domestically produce in the required timeframe (Collins 2023).

For the purpose of this work and given the articulated nature of the different sources of EU funding for hydrogen projects, it is essential to mention the different channels and sources, in order to establish a general framework, without specifying the functioning and implementing stages of each single funding programme. Figure 14 shows the revenue flows from the origin of the funds (at the top) or the revenue-generation mechanisms (e.g. the EU ETS), down towards different major funds and programmes, i.e. massive budgets with significant but cross-sectoral ambitions (e.g. the Cohesion Fund or Next Generation EU), and from there, the financial resources flow down into smaller and more specific «secondary» funds and mechanisms more closely related to energy sector decarbonisation (Kneebone 2023).

Figure 14 – Hydrogen funding instruments and flows in the EU (billion €). Source: Kneebone (2023).

As can be seen in the figure, the main funding sources are represented by the EU long-term budget (the Multi-Annual Financial Framework 2021-2027), the EU ETS revenues, the bonds through which the EU borrows on financial markets, and the resources of single Member States. The latter follow an essentially straight path since the EU countries’ own resources can be directed towards the IPCEI projects in form of state aid (after the approval of the European Commission). It is of course important to consider that a large part of the EU budget is also financed by the Member States. The EU MFF feeds six main programmes (LIFE, InvestEU, Horizon Europe, Next Generation EU, the Cohesion Fund and the Connecting Europe Facility), some of which are directly managed by the European Commission, then providing resources for more targeted funds, such as the Just Transition Fund, REACT EU, the TEN-E and TEN-T, as well as the European Hydrogen Bank and REPowerEU. These last two funding sources are also supported by other mechanisms. Revenues from the ETS then flow partly into REPowerEU, but they also flow into InvestEU and the EU Innovation Fund, which in turn feed the EU Hydrogen Bank, a critical tool to enable better coordination between funding programmes and to provide clarity to potential project developers.

Launched by a declaration signed by 22 EU Member States and Norway in December 2020, IPCEI are State aid schemes for supporting projects in infrastructure or research, development and innovation (R&D&I), which are carried out by the private sector and are supported by the funds of the Member States. According to the European Commission (2021b), IPCEI are meant to make a very important contribution to sustainable economic growth, jobs, competitiveness and resilience, as well as to overcome market or systemic failures or societal challenges that prevent a project from being carried out in the absence of the aid. It is important to consider that IPCEI do not have budgets in of themselves but are rather vehicles for accessing finance (Kneebone 2023). Therefore, the European Commission plays a key role in this regard since it is tasked with approving the State Aid funding for IPCEI.

As of 2024, the IPCEI on hydrogen include two sets of projects approved in 2022 (Hy2Tech and Hy2Use), one adopted in February 2024 (Hy2Infra) and one in May 2024 (Hy2Move)55. Hy2Tech, approved in July 2022, involves 35 companies from fifteen Member States. The latter will provide up to €5.4 billion in public funding, while expecting to unlock an additional €9 billion in private investment and the creation of approximately 20000 direct jobs (European Commission 2022d). Hy2Use, approved by the Commission in September 2022, includes 35 companies from thirteen Member States, which will provide up to €5.2 billion in public funding in the coming years, thus expecting to unlock around €7 billion in private investments (European Commission 2022e). Whereas Hy2Tech covers mainly H2 generation, fuel cells, storage and end-use applications, Hy2Use supports research and innovation and first industrial deployment of hydrogen technologies. The third and IPCEI, Hy2Infra, complements the first two by supporting the gradual emergence of an EU-wide hydrogen transmission infrastructure starting from different regional clusters. While expecting to unlock €5.4 billion in private investments, public funding for this IPCEI totals €6.9 billion, which will be provided by the seven Member States (including France, Italy and Germany) that notified the project to the EU (European Commission 2024). The last IPCEI (Hy2Move) will provide up to €1.4 billion in public funding, unlocking an additional €3.3 billion in private investments, and it will cover mainly hydrogen integration into road, maritime, and air transport, as well as high-performance fuel cells and advanced refuelling stations.

After introducing a new infrastructure project category in the TYNDP 2020 for «Energy Transition Projects», ENTSOG decided to develop this category into four different new single project categories, thus allowing for sector-specific insights and displaying development trends (ENTSOG 2023a). The 2022 TYNDP includes 216 investments (in 26 countries) relevant for these four categories, which are: 1) new or repurposed infrastructure to carry hydrogen (HYD), 2) projects for retrofitting infrastructure to integrate hydrogen (RET), 3) biomethane development projects (BIO), and 4) other infrastructure-related projects (OTH). Hydrogen infrastructure projects can be further sub-divided into three groups, namely on-shore and off-shore H2 transmission pipelines, newly constructed or repurposed liquefied hydrogen terminals (including for hydrogen derivatives, such as ammonia), and hydrogen storages. Overall, 359 investments are covered by the TYNDP 2022 out of which 143 are natural gas projects, 153 are HYD, 13 RET, 11 BIO and 39 OTH (ENTSOG 2023a). Table 16 outlines the 153 HYD investments for each of the three groups (pipelines, liquefied H2 terminals, and storages).

Table 16 – Investments in the HYD (hydrogen) infrastructure category in the TYNDP 2022. Source: own elaboration based on ENTSOG (2023b).

As can be derived from the above table, the highest share of H2 investments falls into the category of construction and conversion of existing infrastructure to transport and store 100% hydrogen. From the TYNDP 2020 to that of 2022, investments in the four energy transition categories (HYD, RET, BIO, OTH) have increased, thus showing the willingness of project promoters to commit to the EU’s decarbonisation targets. According to ENTSOG (2023b), the increase in investments over the last two years stems from the need of industries and societies in the EU to reduce their GHG emission in the near-to mid-term future, and from the provisions set out in the recently adopted acts and initiatives at the EU level, aiming at enhancing the deployment of renewable gases along with renewable electricity. Figure 16 shows the number of investments per country and the type of infrastructure of the four new categories, and Figure 17 illustrates the status of those projects, included in the TYNDP 2022. Such investments are mostly in the «less-advanced» stage, whereas the other two stages are the «advanced» and the «final investment decision» (FID) stage.

Figure 16 – Number of investments per country and type of infrastructure. Source: ENTSOG (2023b).

Figure 17 – HYD, RET, BIO and OTH investments by maturity status62. Source: ENTSOG (2023b).

The latest TYNDP foresees capital investments exceeding €210 billion, approximately 80% of which are dedicated to hydrogen, and the remaining 20% is mainly allocated to natural gas (ENTSOG 2025). Out of the 326 projects included in ENTSOG’s TYNDP 2024, more than 200 focus on hydrogen (in the TYNDP 2022 they were 153). Nearly 80% of the 110 new projects introduced in the 2024 cycle are hydrogen-related, representing a twofold increase compared to TYNDP 2022 (ENTSOG 2025). This development highlights the EU’s strategic commitment to establishing a hydrogen backbone and prioritising regional interconnections and renewable energy integration.

Since the publication of its first infrastructure report, the European Hydrogen Backbone has steadily revised its cost estimations on the development of a dedicated H2 network within the span of 15-20 years up to 2040. The two fundamental cost components are CAPEX and OPEX. Given that here the cost estimations and the economic analysis are limited to the transmission part of the hydrogen market, it is interesting to outline the evolution of both the CAPEX and OPEX values, and the so-called levelized cost of hydrogen transport (LCOT).

While a cubic meter of hydrogen contains only one third of the energy of a cubic meter of methane at the same pressure (lower «energy density» of H2), this does not mean that three times as many pipelines are required to transport the same amount of energy, because the maximum energy capacity of an H2 pipeline can be increased up to 80% of the energy capacity it has when transporting natural gas (Wang et al. 2020). There can be variations across regional gas networks concerning operating pressures, pipeline diameters and compression system designs, which would impact cost estimates. However, the European Hydrogen Backbone has taken an infrastructure-driven view (as opposed to designing parameters for a specific system demand) and has selected a generic network design, thus obtaining cost ranges that are deemed representative of the EU-average (Wang et al. 2020). Table 18 reports the evolution of the CAPEX and OPEX estimations of the Initiative up to 2040. Initially, operational costs were lower than expected, and they remained quite stable in subsequent estimations. Instead, capital expenditure, which is split into the pipeline costs and the compression cost component, progressively increased (also due to the rising inflation and market disruptions).

Table 18 – Evolution of CAPEX and OPEX values according to the network cost estimations by 2040 (in billion €). Source: own elaboration based on Wang et al. (2020), Jens et al. (2021), and Van Rossum et al. (2022).

The investment costs and the levelised cost of transmission (LCOT), as estimated in the EHB reports, largely reflect the cost assessments carried out in the first chapter of this work, concerning both new and repurposed H2 pipelines. If we consider first the unit capital cost figures (in million € per km of pipeline length), we can indeed see that the cost estimations outlined in Table 3 (Chapter 1) correspond to the data reported by the EHB. The EHB estimates a CAPEX of around 2.8 M€/km for new pipelines, and 0.3-0.6 M€/km for repurposed pipes (Van Rossum et al. 2022), while the economic analysis in Chapter 1 included costs of 2.48 M€/km for new pipelines, and around 0.37 M€/km for repurposed lines. This category of costs mostly depends on variables such as the electricity price and the compressor size. The levelised cost of hydrogen transmission is also like that hypothesised in the first chapter, as it is estimated at around 3.3-6.3 €/MWh in the EHB report, and it is around 3.7-4.6 €/MWh in the first chapter of this thesis.