Hydrogen as an Energy Carrier—An Overview over Technology, Status, and Challenges in Germany ^†

Abstract

Hydrogen is set to become an important energy carrier in Germany in the next decades in the country’s quest to reach the target of climate neutrality by 2045. To meet Germany’s potential green hydrogen demand of up to 587 to 1143 TWh by 2045, electrolyser capacities between 7 and 71 GW by 2030 and between 137 to 275 GW by 2050 are required. Presently, the capacities for electrolysis are small (around 153 MW), and even with an increase in electrolysis capacity of >1 GW per year, Germany will still need to import large quantities of hydrogen to meet its future demand. This work examines the expected green hydrogen demand in different sectors, describes the available technologies, and highlights the current situation and challenges that need to be addressed in the next years to reach Germany’s climate goals, with regard to scaling up production, infrastructure development, and transport as well as developing the demand for green hydrogen.

1. Introduction

Although the influence of the combustion of fossil fuels on climate has long been known [1,2], it is only fairly recently that various countries across the world have taken action to replace fossil fuels with less destructive technologies. Two of the United Nations’ Sustainable Development Goals relate to a sustainable energy supply and the limiting of global warming [3]. In 2021, the EU defined targets within the “Fit for 55 package” for the use of renewable hydrogen in industry and transport by 2030. These targets entered into force in 2023 as part of the Renewable Energy Directive [4]. In 2023, two acts on renewable hydrogen set the criteria for the definition of renewable hydrogen of non-biological origin and a scheme to calculate life-cycle emissions of renewable hydrogen and recycled carbon fuels [4]. The hydrogen and gas decarbonisation package [5], adopted in 2024, introduces a new regulatory framework for a hydrogen infrastructure and hydrogen market. The European directives are to be put into national law by the member states.

The European Union (EU) has set itself the target to achieve net-zero emissions by 2050 [6]. Germany has imposed itself even stricter targets and plans to reach climate neutrality already by 2045 [7], and for example, the federal state of Baden-Württemberg [8] in Germany even has outdone these targets by aiming to reach net zero by 2040. These targets require fast and comprehensive measures to convert the entire energy supply structure.

Germany’s national hydrogen strategy, which was first published in 2020, was updated in July 2023 [9] and states in detail how the ambitious targets are to be reached. The strategy includes four main fields of action:

The first is to ensure a sufficient supply of green hydrogen. To meet the expected demand, 10 GW of electrolysis capacity is to be built in Germany until 2030. Projects within the H₂Giga framework support the development of technologies for large-scale series production of electrolysers [10], and H₂Mare [11] supports the development of offshore hydrogen and hydrogen derivatives production. An import strategy is offering a framework for the import of green hydrogen in the future. Hydrogen partnerships are already being built, and projects are assessing the potential for green hydrogen import from various countries, for example, Australia [12], several African countries [13], Canada, USA, and New Zealand [14]. The import strategy aims at ensuring a sustainable, stable, safe, and diversified supply of green hydrogen and its derivatives and includes the construction of infrastructure for the import via pipeline as well as via ships [15,16].

The second pillar of the national hydrogen strategy is the building of a hydrogen infrastructure. An 11,000 km hydrogen core network will connect hydrogen producers with consumers by 2032, and the number of hydrogen refuelling stations is to be increased. Projects within the TransHyDE framework aim at developing and upscaling all necessary technologies and components for the transport and storage of hydrogen in gaseous or liquid form, as well as chemically bound hydrogen [17].

The third pillar aims at developing hydrogen demand and supporting the use of green hydrogen in the industrial and transport sectors. The German government funds projects for hydrogen use in the steel and chemical industry, for example, within the project Carbon2Chem [18], as well as power to X projects for the production of e-fuels and the improvement of fuel cell technologies [14].

Last but not least, the national hydrogen strategy addresses the issue of a suitable legal framework. This should enable speeding up planning and approval procedures [14]. Legislative options and their likely consequences are being analysed within the Ariadne project [19] to enable the legislative to suitably support the development of the hydrogen economy.

In 2023, more than half of Germany’s electricity came from renewable energies. However, looking at the overall primary energy consumption, less than 20% of Germany’s total energy supply came from sustainable sources [20]. When the primary energy consumption is considered, oil and natural gas are still the most important energy carriers in Germany. The increase in renewables in the electricity sector is a development that essentially occurred in a comparatively short time frame between 2000, when renewables contributed 6.3%, and 2023, when 52% renewable electricity was achieved [21]. The development over the last two decades shows that in the electricity sector, Germany is on the right track, but in other sectors, like transport, industry, and the heating sector, Germany is facing great challenges to decarbonise those sectors in the next decades.

Hydrogen as an energy carrier is set to play a vital role in those sectors that are otherwise hard to decarbonise. It has the potential to replace fossil fuels in those sectors, and it can also be a link between the electricity sector and other energy sectors, if hydrogen is produced from renewable electricity by means of electrolysis. Using renewable electricity for the production of hydrogen also enables hydrogen to serve as large-scale and long-term energy storage. The produced hydrogen can be used in different applications at a later point in time. It can be reconverted into electricity, used directly as a fuel or used in industrial processes as a base chemical.

To meet the ambition targets of climate neutrality, hydrogen technologies, as well as the installed hydrogen production capacity, have to be expanded dramatically in the next decades. This is, of course, in addition to other efforts, like reducing energy consumption, increasing energy efficiency, and developing the use of renewable energy sources and carriers wherever possible.

This work aims at summarising information from various sources and thereby giving a comprehensive overview of the potential hydrogen demand in different sectors, the existing technologies for the production, storage, transportation, and use of hydrogen, as well as existing practical applications and the status and challenges related to the introduction of a hydrogen-based energy supply in Germany.

2. Properties of Hydrogen

The most common hydrogen isotope (protium) consists of one proton and one electron, and under standard conditions, it forms the diatomic molecule H₂ with a covalent bond. Hydrogen is a very common molecule in the universe, as Cecilia Payne discovered in 1925 [22]. More than 90% of all atoms in the universe are hydrogen atoms [23], and approximately 75% of the total mass is hydrogen [24]. On earth, it is less common: only about 0.7 wt% [24] in mass of the Earth’s crust is hydrogen. On the Earth’s surface, it is more common [24] and usually occurs as a chemical compound. It is, for example, found in water or hydrocarbons. When hydrogen and oxygen combine to form water, energy is released, as shown in Equation (1). It can, therefore, be used as a fuel.

H₂(g) + ½ O₂ (g) → H₂O (l)   ΔH = −286 kJ/mol

(1)

An advantage of hydrogen compared to other conventional or renewable fuels is its high specific energy, as shown in Table 1. In comparison to other fuels, the specific energy of approximately 33 kWh/kg [25] of hydrogen is much higher than that of any other fuel. The energy per kg stored in hydrogen is approximately three times the energy stored in petrol or diesel (approximately 12 kWh/kg [25]), while lithium-ion batteries only reach specific energies of around 0.3 kWh/kg [26], a tiny value in comparison. The gravimetric energy density of hydrogen is also higher than that of methane of methanol, which can also be produced from renewable sources. This makes hydrogen a very interesting fuel for mobile applications.

However, if volumetric energy density (amount of energy stored per volume) is considered, hydrogen does not do as well in comparison. At normal ambient conditions, hydrogen just has a volumetric energy density of 3 Wh/L [27], which is far below that of liquid fuels like diesel (approx. 10 kWh/L), petrol (approx. 11 kWh/L) [28], or methanol (approx. 5.53 kWh/L). It, therefore, needs to be pressurized or stored at a low temperature in liquid form to increase the volumetric energy density. At 350 bar, it reaches an energy density of 0.7 kWh/L, at 700 bar, it reaches 1.3 kWh/L, and in liquid form, at 1 bar and 20 K, its energy density is 2.3 kWh/L [29]. If the pressure tank is included in the calculation, the volumetric energy density of pressurised hydrogen at 350 bar is comparable to that of lithium-ion batteries [27]. The gravimetric and volumetric energy densities of different energy carriers are summarised in Table 1.

Table 1. Gravimetric and volumetric energy density for different fuels.

	kWh/kg	kWh//L
H2 at normal conditions	33 [25]	0.003 [27]
H2 at 700 bar	33 [25]	1.3
H2 liquid at 20 K	33 [25]	2.3 [29]
Petrol	~12 [25]	11 [28]
Diesel	~12 [25]	10 [28]
CH4 at normal conditions	13.9 [30]	0.01 [30]
Methanol	7.02 [31]	5.53 [31]
Li-Ion batteries	~0.3 [26]	~0.4 [32]

Table 1. Gravimetric and volumetric energy density for different fuels.

	kWh/kg	kWh//L
H2 at normal conditions	33 [25]	0.003 [27]
H2 at 700 bar	33 [25]	1.3
H2 liquid at 20 K	33 [25]	2.3 [29]
Petrol	~12 [25]	11 [28]
Diesel	~12 [25]	10 [28]
CH4 at normal conditions	13.9 [30]	0.01 [30]
Methanol	7.02 [31]	5.53 [31]
Li-Ion batteries	~0.3 [26]	~0.4 [32]

Hydrogen safety is one aspect that is sometimes used as an argument against the use of hydrogen. However, since hydrogen has been used in specific applications for a long time, the safety-related properties, as well as the necessary measures, are well known.

Table 2. Properties of hydrogen and petrol and their relevance for safety. Based on [33].

	Petrol	Hydrogen	Conclusion
Density ratio to air	3.2–4	0.09	H2 diffuses quickly; petrol stays on the ground
Ignition limit	0.6–8%	4–75%	H2 burns in a wide range
Detonation limit	1.1%	18%	H2 burns before it explodes
Ignition energy	0.24 mJ	0.02 mJ	H2 and petrol can be ignited by a spark
Ignition temperature	220–280 °C	585 °C	Petrol can be ignited by a hot surface
Flame	Wide; hot radiation	Narrow; less heat radiation; almost invisible	Risk for burns next to flame lower for H2; H2 flame might not be noticed
Toxicity	toxic	Not toxic	H2 no risk for ground, water, or wildlife

compares some properties of hydrogen and petrol and states the relevance as to safety.

In comparison to petrol, the density ratio of hydrogen to air is very low, and hydrogen defuses quickly in the surrounding air. It rises upwards from a leak, while petrol stays on the ground. The ignition limits of petrol and hydrogen in Table 2 show that hydrogen burns in a wider range than petrol. The detonation limit of hydrogen, however, is at 18%, which means that hydrogen will burn before it explodes, and it is possible to use a controlled combustion to avoid a potential explosion. Hydrogen has a lower ignition energy than petrol; however, a spark is enough for the ignition of both fuels. Hydrogen is less likely to be ignited by a hot surface than petrol. A potential danger arises from the fact that the hydrogen flame can be almost invisible in some light conditions, but heat radiation is lower. Lastly, petrol is toxic, cancerogenous, and damaging to water and wildlife, while hydrogen is none of those. The comparison shows that the dangers related to the use of hydrogen are different from those related to the use of petrol, but not necessarily more dangerous, if adequate safety measures are followed.

Due to the different properties, technologies, as well as safety measures, have to be adapted for the use of hydrogen and, especially for international use and trade, a framework for safety regulations across borders is required. The European Hydrogen Safety Panel [34], for instance, promotes safety in the production, storage, distribution, and use of hydrogen.

3. Current Uses of Hydrogen, Targets, and Potential Future Demand

Hydrogen has long been used in industry. Between 2021 and 2022, hydrogen consumption worldwide only grew by about 3%, and in that time frame, this hydrogen was almost exclusively used in industrial applications and refining processes. New applications in transport, energy, or heating made up less than 0.1% of the applications [35]. This hydrogen was almost exclusively produced from fossil fuels [35]. However, both the demand as well as the production method will change in the next decades.

The EU has set targets for reaching net zero by 2050. In 2023, the EU issued the renewable energy directive three (RED III) [36], where the intermediate target for 2030 to increase the use of renewable energies was raised from 32% to 42%. Specific targets for different sectors are defined as well in the directive: By 2030, the transport sector is supposed to use at least 29% of renewable energies or reduce their mission of climate active gases by at least 14%. The industrial sector has to increase its use of renewable energy by at least 1.6 percentage points on an annual average over two periods from 21 to 25 and 26 to 2030. The directive also states that at least 42% of the hydrogen used in the industrial sector has to come from renewable fuels of nonbiological origin by 2030. This value is increased to 60% by 2035. The target defined for the building sector is also ambitious: By 2030, at least 49% of the energy used in buildings has to come from renewable sources. In all those three sectors, the use of hydrogen can play an important role in achieving those targets.

3.1. Uses in Industry

Hydrogen is already used in industry as a base product, for example, for the ammonia synthesis process, which is a preliminary step in the production of fertilisers and polyamides. It is also a base product for methanol synthesis, which is used as a base chemical in the chemical industry, and hydrogen also finds a use in refineries for the desulphurisation of diesel. The current hydrogen demand in Germany is presumed to be around 55 TWh per year [37]. Almost all of this already existing demand is currently met by hydrogen produced from fossil fuels and ought to be speedily replaced by renewable hydrogen, wherever possible.

In German refineries, approximately 17.7 TWh/a of hydrogen is currently produced internally, and another 5 TWh/a is required for desulphurisation in refineries in Germany [38]. The internally produced hydrogen cannot be replaced, but the additional 5 TWh can. Once the use of fossil fuels starts to decline, the demand from desulphurisation processes will decline as well.

Ammonia production in Germany has decreased by about 40% in the last decade to about 1.72 Mio tonnes per year [39]. This amount contains approximately 13 TWh of hydrogen. About 1.1 Mt of methanol were used in Germany in 2022, which were produced from fossil sources [40]. Theoretically, the production of 1 t of methanol requires 0.1875 t of hydrogen. This results in an approximate demand of 0.2 Mt or 8 TWh of hydrogen. These already existing uses of hydrogen result in a demand of approximately 26 TWh, which can easily be replaced by green hydrogen, if available. The hydrogen demand for ammonia and methanol production can also be expected to increase in the future as they themselves can be used directly as an energy carrier and as a basis for e-fuel production. However, it is uncertain whether this will lead to increased production within Germany or rather production abroad and transport of the hydrogen derivatives to Germany. The energy utility company EnBW, for instance, is planning the import of 100,000 t of green ammonia, produced from renewable sources, from Norway by 2027 [41].

In addition to the existing hydrogen demand, which can be replaced by green hydrogen as shown in

Table 3. Existing hydrogen demand in Germany, which can be replaced by green hydrogen.

Ammonia production	13 TWh calculated based on [39]
Methanol production	8 TWh calculated based on [40]
Desulphurisation in refineries	5 TWh [38]

, there are new possible uses in industry. For example, hydrogen can be used in the steel industry and cement industry to reduce their climate impact. Steel production and cement production are two of the largest sources of CO₂ in the industry sector in the EU; both contribute above 20% to the industrial emissions in the EU each [42].

Hydrogen can be used as a reducing agent in primary steel production by using pure hydrogen for a direct reduction (DRI) process of iron ore. The DRI process using natural gas is already an established technology, although pure hydrogen is not yet used [43]. By using hydrogen instead and replacing Equation (2) with Equation (3) [44], the process is decarbonised [43]. If the process heat required for the reduction of iron ore is supplied electrically from renewable sources or through green hydrogen, almost all CO₂ emissions can be avoided.

Fe₂O₃ + 3CO → 2Fe + 3CO₂   ∆H = −18.4 kJ/mol

(2)

Fe₂O₃ + 3H₂ → 2Fe + 3H₂O   ∆H = 104.9 kJ/mol

(3)

A blending of hydrogen into natural gas is also a possibility as a transition technology to reduce the climate impact. The technological challenges that arise here are to develop the technology to enable an operation with varying hydrogen content. The potential demand in steel energy could increase over the next decades, up to 67 TWh [45] in Germany or 187 TWh in the EU in 2050 [46]. Several demonstration and pilot plants using the DRI process already exist in Germany. In 2021, for example, Salzgitter AG started the construction of a DRI demonstration plant and has recently launched a tender for 100,000 tonnes of green hydrogen [47] for use in the steel production process. Other demonstration plants are planned, for instance, by ArcelorMittal in Hamburg [48].

Another new use of hydrogen in an industry is the cement industry. Cement production currently emits about 7% of global CO₂ [42] and is responsible for about 20% of industrial emissions in the EU [42]. The CO₂ during cement production is released by the calcination process, where calcium carbonate is turned to calcium oxide and CO₂, as shown in Equation (4). This CO₂ cannot be avoided and is in addition to emissions from fuel combustion for the required heat.

CaCO₃ →CaO + CO₂   ∆H = 178.0 kJ

(4)

To decrease the climate impact, the CO₂ released in the calcination process can be captured and used as a basis for the production of synthetic fuels in combination with green hydrogen, while hydrogen or electricity can also be used to replace fossil fuels for heating. As an example, there are projects already underway that are examining and planning the transition of the cement producing facility in Lägerdorf. The technical and economic feasibility is assessed with plans to implement a net-zero cement production plant by 2029 [49], and at the site of the cement producer Schwenk, a pilot plant for the separation of CO₂ is being built [50].

Summing up, the emissions from the industry sector can be reduced by substituting grey hydrogen in existing applications with green hydrogen. This has the advantage that existing industrial processes can be used without modification. The challenge mainly lies in providing sufficient green hydrogen at a sufficiently low cost and ensuring transport and large-scale storage. On top of that, new industrial uses, like steel or cement production, of hydrogen will arise, and hydrogen can be used as an energy carrier for providing energy to the industry sector. Here, the challenges lie also in the provision of large amounts of green hydrogen, ensuring its safe transport and storage, but also in the development of technologies, reactors, and infrastructure that can operate with pure hydrogen or varying hydrogen content in a transition phase. It is estimated that a completely CO₂-neutral industry could create a hydrogen demand of approximately 372 TWh in Germany [51] and 165–1584 TWh in Europe [52] by 2050.

3.2. Use in Transport

Another sector where hydrogen has a high potential for decarbonising is the transport sector. In 2022, transport made up slightly less than one-third of Germany’s energy consumption [20]. Within the transport sector, cars and vans make up the largest part of the CO₂ emissions worldwide, followed by heavy freight vehicles [53]. There is, therefore, great potential for reducing climate impact if this sector can be decarbonised. Fossil fuel-based vehicles can be replaced by battery electric vehicles (BEVs). However, BEVs have several disadvantages. They are better suited for short distances due to the heavy weight of batteries, and they have long charging times. The main advantage is that the well-to-wheel efficiency is close to 80% [54]. For long-distance transport not only in cars, but also in vans and especially heavy trucks, batteries are not the best option. Here, hydrogen or synthetic fuels offer much larger distances as well as faster refuelling, but the well-to-wheel efficiency of fuel cell vehicles is around 32% [13], much lower than for batteries. However, this hydrogen fuel cell well-to-wheel efficiency is still much higher than for synthetic fuels. For the production of synthetic fuels, hydrogen has to undergo several more conversion steps, which reduces the well-to-wheel efficiency to around 12% [54]. The largest potential for hydrogen application in the transport sector, therefore, lies in long-distance transport, like heavy-duty trucks and applications where vehicles drive long distances with few longer stops for recharging, for example, buses. Hydrogen also has potential for application in other modes of transport, like trains [55], ships [56], or even in aviation [57].

The increased use of hydrogen in transport is supported by targets and directives issued by the EU. Currently, 10% of all new trucks and 45% of all new buses have to be emissionless. These target values will rise in the next years, and by 2030, 90% and, in 2035, 100% of all new buses will have to emissionless. At the same time, the directive states that by 2040, a reduction of CO₂ emissions of heavy trucks by 90% has to be achieved [58,59]. These directives mean that within the next decade, the demand for emissionless trucks and buses will increase. This demand might be covered by battery electric, hydrogen, or biofuel/synthetic fuel-based technologies. Currently, a few hydrogen-based vehicles are commercially available. There are hydrogen trucks already on the market, and more are expected in the coming years [59]. The same applies to buses with several hydrogen buses already commercially available [60].

Whether battery or hydrogen vehicles will be more successful in the future depends very much on the cost development of the vehicles, as well as the cost development and availability of green hydrogen. To lower the cost of fuel cell-based vehicles, the cost of fuel cells needs to be reduced. Cost reductions can be achieved by R&D to increase the lifetime of cells and stacks by reducing material costs and implementing recycling technologies. Most importantly, the manufacturing process of fuel cells must be scaled up and industrialised. This applies to the fuel cells and the systems themselves as well as to any system components. It is, therefore, important to build up the fuel cell-producing industry. In 2022, approximately 50 companies in Germany were involved in the manufacturing of fuel cells or system components [61], and the industry is predicted to grow between 10% [62] and 40% per year in the near future [63].

There are estimations that the total cost of ownership (TCO) of hydrogen-powered vehicles will, by 2030, be similar to or even below that of conventional internal combustion engine vehicles and BEVs [18]. This is especially the case for vehicles that drive long distances. The higher the required range in the tank, the more likely it is that hydrogen-powered vehicles will be cheaper (based on TCO) than battery-powered ones, possibly even before the year 2030 [64]. Currently, the purchasing costs for fuel cell- and battery-driven buses are not too different. A reasonable estimated price is around 590,000 euros for a fuel cell bus and 570,000 euros for a battery bus [65]. The possible range for the fuel cell bus is approximately 400 km higher than that of a battery electric bus, which has a range of approximately 230 km [59]. Due to the long recharging times, switching to battery electric buses often requires a larger fleet than with conventional technologies, which increases the overall cost. This is not the case for fuel cell buses, where the required fleet is the same as for fossil fuel-based technology. Considering the refuelling infrastructure, the building up is initially easier for a BEV. However, once a hydrogen infrastructure exists, refuelling of a fuel cell bus becomes the easier solution and requires less space and time than for a fleet of battery electric buses. Therefore, another aspect of introducing hydrogen vehicles into the market is the availability of sufficient refuelling stations that are suitable for different types of H₂ cars and trucks. Currently, different vehicles require different refuelling systems (700 bar or 350 bar), and not all refuelling stations are suited for busses and trucks. From this arises the challenge to build up an infrastructure of fuelling stations. How important the availability of refuelling stations is for increasing the number of hydrogen-powered vehicles in an area can be seen from the H₂pure project [60], in which 28 companies in Ulm, a town in southern Germany, participated in a survey with regard to their willingness to use hydrogen vehicles and possible introduction time frames of the technology. The study predicted a strongly increasing demand for hydrogen within a short time frame. However, more than 50% of the participating companies stated that two refuelling stations within the city were required for redundancy reasons before they would start using H₂ technology. More than 50% also stated that two refuelling stations within reach would be sufficient for the introduction of the technology [66]. Hydrogen refuelling stations will also have to be supplied with hydrogen, which necessitates not only a sufficient hydrogen supply, but also a distribution infrastructure, for instance, via pipelines.

When considering the development of the number of hydrogen refuelling stations worldwide, a considerable increase from 434 in 2019 to 921 in 2023 can be seen [67]. The increase is strongest in China. The number of hydrogen refuelling stations in Germany in the same time frame has increased from 79 in 2019 to 91 in 2023 [68]. Since vehicles will also travel beyond borders, the availability of refuelling stations in neighbouring countries is also important, and international standards are required. The European Hydrogen Observatory [69] reported 86 operational and publicly accessible refuelling stations in Germany, while the total number in all of Europe is 187. Germany is, therefore, leading, followed by France with 27 H₂ refuelling stations and the Netherlands with 24 stations [69]. This lower number of refuelling stations in other European countries limits inter-European transport with H₂ vehicles.

So far, cars make up the biggest part of hydrogen fuel cell vehicles already on the road worldwide [35]. The number has increased from around 19,000 to 63,000 between 2019 and June 2023 [35]. The number of H₂ buses and commercial vehicles worldwide is small in comparison. In 2023, there were about 7000 H₂ buses and 8000 H₂ trucks worldwide [35]. The greatest number of H₂ vehicles exist in Korea, followed by China and the United States [35]. However, when looking at the hydrogen consumption in road transport, buses are leading with approximately 14 kt of hydrogen in 2022, while cars only consumed around 11 kt and other commercial vehicles only around 7 kt [35]. Most of this consumption happens in China, where the segment of H₂ heavy-duty trucks is very strong, while in Europe, only around 3 kt of hydrogen was used for road transport in 2022 [35].

The registration of battery electric cars has increased in Germany (more than 1.5 million in 2024) [70]; however, the number of H₂ vehicles remains small, with only 208 fuel cell buses, 109 light commercial H₂ vehicles, 81 heavy commercial vehicles, and 2236 fuel cell cars registered in 2024. The biggest growth is seen in the bus sector, where H₂ buses make up about 1.3% of newly registered buses [71].

Other means of transport can use hydrogen as well. Hydrogen-powered trains can be used on non-electrified tracks. A total of 61% of the German train network is electrified [72]; however, there are some tracks that are still being covered by diesel trains. In all of Europe, the percentage of electrified tracks is slightly lower at around 58% [73]. The trains operating on unelectrified tracks could be replaced with hydrogen trains. Several trials have already been done. In 2024, a trial of a hydrogen train between Tübingen, Horb, and Pforzheim is underway [55]. In countries with less electrification of the train network, hydrogen trains can have an even greater potential. Other applications use the fuel for boats and ferries, like the MF Hydro [56], although hydrogen as fuel for ships is still in the development stage [74]. Hydrogen even offers potential in aviation, with experimental aircraft, like the Hy4 having already flown [75]. Commercialisation aims for hydrogen-powered aircraft are named between the years of 2028 [76] and 2035 [77].

In total, a hydrogen demand from transport in Europe of up to 1782 TWh is predicted [52] for the year 2050. For Germany, a demand of between 128 TWh [51] and 186 TWh [45] in the transport sector is expected in 2045.

Liquid fuels derived from renewable hydrogen (e-fuels) can also aid in decarbonising the transport sector. E-fuels can be used with minor modifications on existing combustion engine technologies and might gain importance should the price of battery electric and hydrogen technologies in transport not fall as expected. The well-to-wheel efficiency of liquid e-fuels, however, is considerably lower (around 12% [54]) than the direct use of electricity (around 80% [54]) or hydrogen (around 32% [54]). More renewable electricity or hydrogen is required for the same distance travelled, and since hydrogen is the base for the production of e-fuels, the increased use of e-fuels will increase the hydrogen demand even more.

3.3. Use in Electricity

More uses for hydrogen can be found in stationary applications. Hydrogen can be stored in large quantities and then reconverted into electricity, providing a flexible energy supply for peak load. The reconversion into electricity can happen via hydrogen gas turbines or fuel cells and can either use pure hydrogen or hydrogen blended with natural gas. Currently, this application has no relevance in the global electricity supply, with less than 0.2% of global electricity being generated from hydrogen [35]. The predictions for hydrogen demand in the electricity sector vary between 43 and 792 TWh in Europe [52], while the expected hydrogen demand in the energy sector for 2045 in Germany is around 85 TWh [51].

3.4. Use in the Heating Sector

Hydrogen can also find an application in the heating sector. For space heating, hydrogen can be burned in gas heaters, either as pure hydrogen or blended into natural gas. Especially for the transition phase, fuel-flexible burners are required. State-of-the-art burners support at least 23% of hydrogen [78]. For higher H₂ contents, the technology needs to be adapted since flashbacks can occur [79]. The conversion into heat can also happen in fuel cell-combined heat and power systems. In such a combined heat and power system, the fuel cell produces electricity, while the waste heat produced by the system is used for space heating. The technology is already available and currently usually used with natural gas [80].

The use of hydrogen for space heating can be imagined for situations where no other heat sources are available and for decentralised standalone systems where renewable electricity is coupled with an electrolyser and hydrogen storage. For a large-scale application in the heating sector, a suitable gas infrastructure is required, either with a separate hydrogen network or by blending hydrogen into the natural gas grid.

Demonstrations and trials of blending hydrogen into the natural gas grid already exist. For example, from August 2021 until June 2022, the entire village of Winlaton in northeast England was provided with natural gas with 20 vol% of hydrogen blended into it. The village has a closed public gas network and is a typical example of a UK gas network. It was found that no changes to the customer’s gas supply or appliances were necessary since current gas appliances are designed to operate with a blend of up to 23% of hydrogen. The demonstration showed that a percentage of 20% hydrogen can be safely blended into a public gas network without changes to the existing applications. By blending 20% of green hydrogen into the natural gas network in the entire UK, approximately 6 million tonnes of CO₂ emissions would be avoided every year [81].

The predictions of the hydrogen demand for space heating in Germany vary greatly. The demand expected in 2050 varies between 10 and 1221 TWh in Europe [52]. Some sources expect the demand in the building sector for Germany to remain comparatively low at around 12 TWh [51] as other technologies like geothermal, heat pumps, solar thermal, and biomass can supply most of the heating demand more efficiently. The national hydrogen council, however, estimates a H₂ demand in the heating sector of 5 to 10 TWh in 2030 and a growing demand in the order of 125–500 TWh in 2045 [45].

The potential hydrogen demands in the year 2045 in Germany, which are predicted in different studies for the different sectors, are summed up in

Table 4. Potential hydrogen demand from the sectors industry, transport, electricity, and heating in Germany in the year 2045, as estimated in different predictions.

Sector	Potential H2 Demand in TWh
CO2 neutral industry	372 [51]
Transport	128 [51] to 186 [45]
Electricity	85 TWh [51]
Heating sector	12 TWh [51] to 125–500 [45]

.

4. Production Technologies of Hydrogen

In 2022, about 95 megatons of hydrogen were produced worldwide, which is an increase of up to around 3% compared to 2021 [35]. Since 2000, the demand has grown by approximately 50% [82]. This amount corresponds to approximately 3740 TWh (considering higher calorific value). Almost all of this hydrogen was produced from fossil fuels. About 62% were produced from natural gas, 21% from coal, and 16% as a byproduct from refineries and the petrochemical industry. Less than 0.7% were produced from low-emission sources [35]. In Germany, approximately 0.16 TWh of hydrogen was produced from electrolysis in 2023, with a total hydrogen production of about 42 TWh [83]. It can, therefore, be concluded that the current hydrogen production has little benefit for the climate.

Hydrogen is classified according to its source or production method and represented by the colour scheme of hydrogen, as shown in Figure 1.

4.1. Steam Reforming

The most common way of producing hydrogen is via steam reforming of natural gas. The process of producing grey hydrogen happens at a temperature between 800 and 900° at a pressure of about 20 bar. The main reaction is given in Equation (5), with the water gas shift reaction (Equation (6)) also releasing hydrogen.

CH₄ + H₂O →CO + 3 H₂   ∆H = 206 kJ/mol

(5)

CO + H₂O →CO₂ + H₂   ∆H = −41 kJ/mol

(6)

If the resulting CO₂ is released into the atmosphere, this process releases between 9.5 and 13.5 kg CO₂ equivalent per kilogram of hydrogen [84]. The climate impact can be lessened by capturing the CO₂ and using or storing it (blue hydrogen). In the case of blue hydrogen, only between 1.5 and 6.3 kg of CO₂ equivalent per kilogram of hydrogen is produced [84]. The steam reforming process can also use biomass as a feedstock, in which case orange hydrogen is produced.

4.2. Gasification of Coal

Another common process for the production of hydrogen gasification of coal, producing either black (from hard coal) or brown (from lignite) hydrogen, coal is converted into a synthesis gas (a mixture of hydrogen, CO, methane, and other trace gases), and water, air, or oxygen can be used as gasifying agents. The process takes place at a temperature of around 1800°, and the shift reaction (Equation (6)) helps to increase hydrogen content. The gasification of coal produces between 22 and 26 kg of CO₂ equivalent per kilogram of hydrogen [84]. With carbon capture and storage, the climate impact can be reduced to about 2.6 to 6.3 kg of CO₂ per kilogram of hydrogen [84]. Syngas can also be obtained from biomass, in which case sustainable hydrogen can be produced through the same process.

4.3. Low-CO₂ Technologies

Technologies with reduced CO₂ emissions are the production of hydrogen via pyrolysis of methane (turquoise hydrogen), steam reforming with carbon capture use, and storage (blue hydrogen) or pink hydrogen, which is produced through electrolysis using electricity from nuclear power.

Pyrolysis was previously used for the production of carbon black [85] but can also be used for the production of hydrogen. In this process, the methane is split into hydrogen and solid carbon at temperatures between 600° and 1700°, as shown in Equation (7).

$$\mathrm{C}\mathrm{H}4\to 2\mathrm{H}2+\mathrm{C}\hspace{1em}\hspace{1em}\hspace{1em}∆\mathrm{H}=74.91 \mathrm{k}\mathrm{J}/\mathrm{k}\mathrm{g}$$

(7)

Different kind of processes for methane pyrolysis have been developed, including plasma pyrolysis, fluidised beds, moving carbon beds, molten metal, or molten salt [86,87]. The solid carbon can then be used in other processes. Between 2 and 16 kg of CO₂ equivalent per kilogram of hydrogen are released [84] in this process. This technology is not yet used for large-scale production; only laboratory and pilot plants exist with technology readiness levels varying between 3 and 9 [85]. A test site for methane pyrolysis is for example located at BASF in Ludwigshafen, and the company Monolith Inc. has been operating a demonstration plant commercially since 2020 [88].

4.4. Electrolysis

The most important technology for producing renewable hydrogen is electrolysis, with electricity being provided from renewable sources (green hydrogen). This technology represents the connection between electrical energy and material-bound energy. Industrial synthesis of hydrogen using alkaline electrolysis has been possible since 1888 [89], and alkaline electrolysis is still the most mature electrolysis technology [85], which dominates the electrolysis market at present [90].

In an alkaline water electrolyser, two metallic electrodes are immersed in an aqueous solution of potassium hydroxide (KOH) or NaOH [91]. The electrodes are usually steel grids with highly porous Raney nickel as a catalyst. The electrodes are separated by a separator to avoid the recommendation of hydrogen and oxygen. Formally, asbestos was used for separators; nowadays, the separator usually consists of polymer-based composites. The operating temperature is around 60 °C to 80 °C, and the system efficiency is around 61% [92]. The half-cell reactions at the anode and cathode can be seen in Equations (8) and (9) [91].

Anode: 2OH⁻ → H₂O + ½ O₂ + 2e⁻ E⁰ = +0.401 V

(8)

Cathode: 2H₂O + 2e⁻ → H₂ + 2OH⁻ E⁰ = −0.828 V

(9)

Electrolysis based on proton exchange membrane (PEM) electrolyser cells offers advantages with respect to dynamic operation [85]. In PEM electrolysers, the electrolyte is a solid proton-conducting polymer membrane (usually Nafion), which needs to be kept moist to conduct irons. PEM electrolysers usually use noble metals, such as platinum, as a catalyst in the cathode, and the technology is still more expensive than alkaline electrolysers [93]. The half-cell reactions at the anode and cathode are shown in Equations (10) and (11), and the operating temperatures of a PEM electrolyser are below 100 °C. The efficiency of PEM electrolyser systems is around 61% [94].

Anode: 2H₂O(l)→O₂(g) + 4H⁺ + 4e⁻  E⁰ = 1.229 V

(10)

Cathode: 4H⁺ + 4e⁻→2H₂(g)    E⁰ = 0 V

(11)

High-temperature electrolysis based on solid oxide electrolyser cells (SOEC) is also interesting but not yet state-of-the-art. The technology readiness level is between 6 and 7 [85]. High-temperature electrolysis offers very high efficiencies of over 80% [85], as part of the energy required for the splitting of water can be supplied in the form of heat, and charge transfer losses decrease with higher temperatures [95]. The high operating temperatures enable synergies with high-temperature industrial processes.

Electrolysis can also be done at high pressures, which offers advantages, especially if hydrogen is stored at high pressures. Increasing pressure decreases the polarisation resistances [95], and liquid water can be compressed more easily than gaseous hydrogen. Using water pumps instead of hydrogen compressors is cheaper and approximately 5% more efficient [96].

An electrolyser not only consists of the electrolyser cell itself, but requires a balance of plant and surrounding infrastructure for operation. Apart from a sufficient electricity supply, approximately 10 L [97] of water is needed to produce 1 kg of hydrogen. Depending on the quality of the water source, between 9 and 22 L are required [97,98], which can be taken from groundwater, surface water, or even waste or seawater [97,99]. A location for a large electrolyser, therefore, requires a suitable water source, and the electrolyser must not compromise water supply for the area, not even in extreme situations. Local conditions need to be considered, but overall, the water demand for electrolysis can be met in Germany, as the quantities required, even for large-scale electrolysis, will be small in comparison to current water consumption [97].

Figure 2 shows a schematic of a PEM electrolyser system. Before water enters the electrolyser, it is cleaned, and a deioniser prevents the accumulation of ions in the recirculating anode water circuit. Water separators remove humidity from the hydrogen, and oxygen is produced before the hydrogen is cleaned, compressed, and stored. The produced oxygen can be used in further processes, for example, medical applications [100], the chemical and steel industry, or wastewater treatment [101], but most often, it is released into the atmosphere [102]. In the latter case, care must be taken to ensure sufficient mixing with the ambient air since oxygen is toxic in high concentrations [103]. The electrolyser also requires a cooling system to keep the electrolyser cells at optimal temperatures and to condense water at several points in the system. The heat needs to be dissipated to the exterior or can be used in another process, for instance, for district heating, if available.

To avoid bottlenecks in electricity transmission lines, large-scale electrolysers should ideally be located in areas with high-renewable production capacities, like photovoltaic, or wind farms with low-electricity production costs and high load output.

4.5. White Hydrogen

White hydrogen is occurring naturally due to continuous geochemical reactions in rocks. Due to hydrogen’s high diffusivity, it escapes easily from the ground, but under favourable conditions, it can accumulate in hydrogen-rich reservoirs [104]. It is estimated that several billion cubic meters are generated yearly and could potentially be harvested [104]. Efforts to extract white hydrogen are currently underway in Australia, USA, Spain, France, Albania, Colombia, South Korea, and Canada [105], but it is currently assumed to play a minor role in Germany’s future hydrogen supply [106].

Other environmentally friendly production mechanisms are also being researched, for instance, hydrogen produced directly from solar energy [107,108] or the recycling of waste [109,110,111].

5. Green Hydrogen Production in Germany

The percentage of renewable electricity in Germany has increased to more than 50% in 2023 and continues to grow. Large wind farms in the north and reasonably good conditions for solar energy, as well as some wind in the south, offer cheap electricity for the production of hydrogen during times with a large surplus of renewable energies. The total geo-technical potential for renewable electricity in Germany is estimated to be up to 1800 TWh per year [112,113]. Water supply in Germany is also abundant. A future electrolysis capacity of 40,000 MW would only increase Germany’s total water demand by less than 1% [114]. Still, local conditions have to be considered, especially in regions that experienced droughts in the past, for example, Brandenburg, Saxony-Anhalt, or Lower Saxony [97]. Close to the coast, desalinated seawater may be used, reducing the demand for fresh water.

Potential consumers of approximately 90% of the expected hydrogen demand for 2030 can be organised into seven regional clusters [115]. Establishing electrolysers in those areas will facilitate the distribution of the produced hydrogen to the consumers, and the national hydrogen strategy supports the development, construction, and scale-up of electrolysers.

The potential demand for green hydrogen in Germany requires an electrolyser capacity of between 7 and 71 GW by 2030 and between 137 and 275 GW by 2050 [116]. The installed electrolyser capacity in Germany in 2024 is approximately 153 MW, mostly in small-scale installations [117]. To meet the intermediate target of 10 GW by 2030 [9], an increase in electrolyser capacity of more than 1 GW per year will be necessary, as well as an increase in plant size to multi-MW installations. This will require increased efforts since current investment decisions for projects of only about 0.3 GW have been made [118], despite the fact that plans for about 13.4 GW have been announced [117]. To make this immense scale-up, which is required in the next decades, possibly a competitive and cost-effective electrolyse industry, as well as a diverse supply chain, has to be built in the next few years.

The investment costs of electrolysers vary greatly, depending on technology, size, and origin. If an average price of 1300 Euro/kW [119] is considered, an investment of up to 13 billion euros is required to reach the goal of building 10 GW of electrolyser capacity in Germany. The investment cost for electrolysers is, however, expected to fall significantly until 2030 [120].

6. Green Hydrogen Cost

Green hydrogen is currently almost two to three times more expensive than grey hydrogen [121], with electrolyser cost contributing most to the total cost [120], followed by electricity price. A considerable decrease in green hydrogen cost can be achieved if capital costs for electrolysers decrease. Electrolyser costs have already fallen by over 60% since 2010 [122] due to technological advancements for electrolyser stacks [123], and it is predicted that they could drop by another 80% in the long term [120]. By increasing the plant size of electrolysers from 1 MB to around 20 MW alone, a cost reduction of over one-third [120] could be achieved. Besides improvements in the technology with respect to electrolyser cells and their materials to increase efficiency and lifetime for dynamic operation, the automatization of the electrolyser production process and the development of a diverse supply chain are needed to reduce both costs and delivery times.

Green hydrogen production costs are also influenced very much by electricity price and the number of operating hours of the electrolyser [120]. For a fixed electricity price, an electrolyser should operate as many hours as possible to reduce the hydrogen production cost. However, green electricity is intermittent, and a surplus of energy is not always available. Due to the integration of more renewable energies in the electricity sector, electricity prices vary with time, and times with negative electricity prices have become more frequent [124]. This makes it possible to operate an electrolyser as a dispatchable load and during times with low or negative electricity prices. This leads to a new, lower optimal number of operating hours per year for minimum hydrogen production costs [125]. Reducing the capital costs, however, is still important to reduce the hydrogen cost and the optimal capacity factor of an electrolyser.

A worldwide trade in hydrogen can also help to reduce green hydrogen costs, as the production costs for green hydrogen in other parts of the world can be much lower than hydrogen produced locally in Germany or Europe despite the additional transport costs. Countries with a high availability of renewable energy, for instance, from solar, as in Chile or Saudi Arabia, will be able to produce cheaper green hydrogen. The IEA predicts hydrogen costs below US$1.6 per kilogram for some parts of the world, while hydrogen costs in Germany and Europe are not expected to fall below US$2.2 per kilogram [126].

7. H₂ Availability Limitations and Trade

A potential demand of hydrogen and its derivatives of 620 to 1288 TWh is expected in Germany in the year 2045 [118]. To produce 1288 TWh of hydrogen, a renewable electricity production of approximately 1840 TWh (assuming an electrolyser efficiency of 70%) is required. In 2023, approximately 272 TW hours of renewable electricity were produced in Germany [20], and the total geo-technical potential for renewable electricity in Germany is estimated to be up to 1800 TWh [113]. It follows that Germany will not be able to cover its own hydrogen demand and will rely on hydrogen imports in the future. To some extent, it will be possible to import H₂ from other European countries, especially in the near future [127]. However, there are estimations that by 2050, the hydrogen demand within Europe will exceed the production capabilities [127], which makes worldwide hydrogen trade indispensable for Europe’s and Germany’s energy supply.

Germany is, therefore, aiming to form energy partnerships with countries that have a high potential for hydrogen production in the form of international research corporations with the aim to create long-term trade partnerships and investment opportunities. Germany has already entered into dialogues or cooperation agreements for the development of green energy technologies and trade with countries like Algeria, Argentina, Brazil, Canada, Chile, China, Egypt, Ethiopia, India, Israel, Japan, Jordan, Mexico, Morocco, Namibia, Saudi Arabia, South Africa, South Korea, Tunisia, Türkiye, Ukraine, USA, United Arab Emirates, Uruguay, Qatar, and Vietnam [128].

An international trading system not only requires the technical infrastructure but also international standards and guarantees of origin as well as quality control of the traded hydrogen. A labelling system for carbon emissions over the whole hydrogen cycle, including transport, should ensure the contribution of emission reduction goals as well as the adherence to social and environmental standards [129].

8. Storage and Transport

Hydrogen can be stored in small amounts in pressure tanks. Steel tanks enable a storage pressure of 200 to 300 bar, while composite materials allow up to 700 to 800 bar. The compression of hydrogen requires energy, and approximately 5% to 20% [130,131] of the energy content of the storage tank is required for compression. Additionally, 700 bar hydrogen has a density of around 40 kg/m³ [132], which means approximately 5 kg of hydrogen can be stored in a 125 L tank.

Storing hydrogen in liquid form at temperatures below −252 °C and 1.013 bar make it possible to store the same amount of hydrogen in a much smaller vessel. For 5 kg of liquid hydrogen, only around 75 L are required. However, the energy required for liquefying hydrogen can make up between 35% and 45% of the energy content [133]. Liquid hydrogen storage tanks require insulation, and it is required to continuously take out hydrogen since a boil of around 0.5% [134] per day cannot be avoided.

Cryo-compressed storage combines low temperatures and high pressures. Hydrogen is stored at a pressure of 250–350 bar and −253 °C. The density of cryo-compressed hydrogen is approximately 80 g/L [135]. Boil-off losses are reduced, and dormancy periods of up to 7 days are possible [136].

Other possible hydrogen storage technologies, for example, metal hydrides, where hydrogen is absorbed in a metal or alloy and forms stable hydrides, or liquid organic hydrogen carriers [135] exist but are so far only mainly limited to niche applications.

Hydrogen can also be stored on a large scale in underground caverns in salt domes or porous structures of depleted oil or natural gas reservoirs. Caverns are already in use for the storage of natural gas. A cavern with a diameter of 60 m and a height of 300 m and a filling pressure of 175 bar can store hydrogen with an energy quantity of 300 GWh [137]. Salt caverns have already been used for the storage of hydrogen in the USA and UK and for the storage of hydrogen-rich town gas also in Germany in the 1970s [138].

Storage and Transport Using the Natural Gas Grid

Large amounts of hydrogen can be stored and transported using pipelines and the existing gas network. Germany already has an extensive natural gas network that reaches approximately 50% of all households [139] and many industrial consumers.

When changing the composition of the gas supplied through the grid, the combustion properties of the gas change as well. Increasing H₂ content affects the heating value, Wobbe index, flame velocity, adiabatic flame temperature, and ignition limit. Above a certain H₂ content, this requires technological adaptations to combustions appliances and consumers [30]. To achieve the same power, a higher volumetric flow is required for high H₂ content, requiring larger pipes and valves, and seals must be hydrogen-tight [82]. Safety measures, like gas detection and ventilation, must be adapted for the changed properties as well. Higher flame temperatures increase the production of NOx, which needs to be addressed in burners for high H₂ content [82]. State-of-the-art heaters already support a hydrogen content of 20% [81,140], and many turbine producers are working on, or already offering, hydrogen-tolerant turbines [141,142,143].

Hydrogen was already a major component in Germany’s gas network when town gas was used, which contained up to 50 vol% of hydrogen [144], until it was phased out during the 1960s and 1970s, when it was replaced with natural gas. By adding locally produced hydrogen or biomethane into the existing gas network, large CO₂ reductions can be achieved within a very short time frame [139]. Adapting existing gas pipelines is cheaper and faster than building new networks. To adapt the existing gas network for 100% hydrogen over a time frame of 30 years, additional costs of around 45 billion euros are expected, approximately a quarter of necessary replacement investments, that are required anyway during that time frame [139]. With the help of membranes or methanation technologies, it is also possible to provide pure hydrogen, pure methane, or a blend to consumers [139].

The current regulation in Germany states that for the existing network, a blend of up to 10% of hydrogen is allowed. This is to be increased to 20% in the short term [145]. A vivid example of the feasibility of 20% hydrogen blended into the natural gas grid was the trial at the village of Winlaton in northeast England [81]. Projects are currently underway to demonstrate and analyse the feasibility of a 20% blend in the region of Fläming in Saxony-Anhalt, Germany, and research into the compatibility of the gas infrastructure and gas appliances for higher contents is ongoing [145]. To increase the hydrogen content of Germany’s natural gas supply, not only adaptation in the gas infrastructure itself is necessary, but the regulations for technical standards and safety have to be adapted as well. These regulations are to be ready for large amounts of hydrogen by 2026 [139].

9. H₂ Infrastructure and Import of Hydrogen to Germany

As stated above, Germany will rely on hydrogen imports in the future. Even within Europe, different regions have different hydrogen production potentials, and the balance between expected demand and supply differs [146]. Hydrogen pipelines through Europe can distribute hydrogen between regions with high potential supply and high demand. The European hydrogen backbone envisions five large-scale pipelines to enable the transport of hydrogen from areas with a high production potential to areas with high demand. These pipelines will connect Southern Europe and North Africa as well as the North Sea region, the Nordic and Baltic regions, and Eastern and Southeast Europe to Central Europe. A total of 33 energy infrastructure operators are involved in the planning and future realisation of this vision [147]. The building up of such a hydrogen infrastructure is supported by the European commission through its repower EU plan, which states a target of 10 million tonnes of domestic renewable hydrogen production as well as another 10 million tonnes of imported renewable hydrogen by the year 2030 [148]. In September 2022, the commission approved 5.2 billion euros in EU public funding for hydrogen projects through the IPC EI Hy2Use initiative [149]. Projects funded through the initiative include hydrogen production, storage, transport, and consumption projects in Europe [150].

These European endeavours are complemented by national programmes. In June 2024, the European commission approved, under EU state aid rules, a German scheme of approximately 3 billion euros to support the construction of a national hydrogen core network for Germany [151]. The hydrogen core network will create an approximately 10,000 km-long hydrogen transport network between 2025 and 2032; 60% of this network will consist of existing natural gas pipelines that will be converted to hydrogen operation. In 2032, this network will have a takeoff capacity of around 280 TWh and 87 GW [152].

Besides creating international and national networks, the introduction of hydrogen technologies can be supported through local hydrogen hubs or islands, which can create decentralised hydrogen centres of hydrogen production and use at an early point in time [153]. Hydrogen hubs bring together local electrolysers and consumers via a local infrastructure. For a location to be suitable for the formation of a hydrogen hub, several conditions need to be met. An electrolyser requires a sufficient renewable electricity supply. This can either be a direct supply from a photovoltaic (PV) or wind farm or can be achieved through a power purchase agreement according to the energy directive two (RED II) [36]. Nevertheless, to keep the load on the electrical network low, it is best not to locate electrolysers in regions with high electric loads but rather in regions with high renewable electricity production. An electrolyser also requires a sufficient water supply from groundwater, surface water, or wastewater, and the local water supply must not be compromised. The provision of water for electrolysis is not a challenge in Germany in general [97], but local conditions have to be considered. The wastewater from the electrolyser also needs to be removed, and a treatment facility needs to be accessible. A hydrogen hub also requires local hydrogen consumers that are supplied either through a local pipeline or via hydrogen trailers with the locally produced H₂. The use of waste heat from the electrolyser, for example, for district heating, is optional, as is the use of the produced oxygen.

Local hydrogen hubs make it possible to switch gas network sections to a hydrogen-based supply, either with pure hydrogen or hydrogen blended into the natural gas, while other sections are still being prepared for hydrogen readiness or are provided with conventional natural gas [153]. Over time, more and more network sections can be converted to hydrogen and can be connected to the hydrogen backbone or core network at a later time, until climate neutrality is achieved for the entire gas network.

An example for a hydrogen hub is the harbour in Stuttgart [154] or the GET H₂ Nukleus project in Lower Saxony [155], where green hydrogen production facilities are being planned. The hydrogen will reach consumers in transport, industry, and heating via a local pipeline, and at a later point in time, this local pipeline can be connected to a larger network.

10. Green Hydrogen Derivatives for Worldwide Transport and Trade

Green hydrogen production facilities are being developed worldwide, and pipelines are a convenient means of transport for hydrogen, as long as the transport distance is not too far. For transporting large amounts of hydrogen from other parts of Europe, for example, from Spain to Germany, pipelines are the cheapest option. However, when importing hydrogen from other continents, transport via ship becomes the more viable option [84]. Hydrogen can easily be transported on ships in gaseous form in smaller quantities using conventional pressure tanks [74]. Larger quantities of hydrogen can be transported via ships in liquid form at −253 °C. There is currently one ship that can carry large amounts of liquid hydrogen. The Suiso Frontier is the world’s first liquefied hydrogen carrier [156]. It was built in 2020 as a prototype ship to assess the technical aspects of transporting liquefied hydrogen by sea. It currently transports hydrogen from Australia to Japan on a regular basis, and the commercialisation of the technology is planned for 2030 [157].

From an economic point of view, it might be cheaper to not transport hydrogen in its pure form, but to convert it before transport [158]. Transport in the form of ammonia or hydrocarbons is possible and cheaper above distances of between 2000 and 4000 km [84].

Ammonia synthesis through the Haber–Bosch process is a well-known technology where nitrogen reacts with hydrogen to form ammonia according to Equation (12) [159]. Under normal conditions, ammonia is a gas, which turns into liquid at −34 °C. If pressurized to 10 bar, it turns liquid at 25 °C [160]. Ships for the transport of ammonia are already available [74].

N₂ + 3H₂ ↔ 2NH₃       ∆H = −92kJ/kmol

(12)

Hydrogen can also be used to produce methane with CO₂ from carbon capture. The most common process is a heterogeneous catalytic conversion, although biological methanation is a promising approach [161]. The overall reaction of the methanation process is shown in Equation (13) [162]. Converting hydrogen to methane for transport has the advantage that methane can be transported in liquid form at −162 °C, and the existing LNG infrastructure can be used since CH₄ is the main component of natural gas.

4H₂ + CO₂ ↔ CH₄ + 2H₂O       ∆H = −165 kJ/mol

(13)

Hydrogen and CO₂ from carbon capture can also be used for methanol synthesis (Equation (16)) via the reverse water gas shift reaction (Equation (14)) and a hydrogenation step (Equation (15)) [163,164]. Methanol is liquid at normal conditions and, therefore, easy to transport. It is, however, toxic.

CO₂ + H₂ → CO + H₂O      ΔH = 41 kJ/mol

(14)

CO + 2 H₂ → CH₃OH      ΔH = −90.5 kJ/mol

(15)

Total reaction: CO₂ + 3 H₂ → CH₃OH + H₂O      ΔH = −49.5 kJ/mol

(16)

Of course, the conversion of hydrogen into another compound is an additional conversion step with associated losses, reducing the overall efficiency. However, the advantages of transportability can make it worthwhile from an economic as well as energetic point of view. The green hydrogen derivatives can either be used directly or reconverted into H₂ before use.

For the large-scale import of green hydrogen or hydrogen derivatives, the harbour infrastructure has to be adapted. For example, transfer points for inserting hydrogen into the natural gas network are needed [74], and installations for the reconversion into H₂ are required, if H₂ derivatives are not used directly.

Several harbours in Germany have announced their intention to prepare for hydrogen in the coming years, and feasibility studies are underway; however, very few operational projects exist yet. In 2022, for example, the harbour in Hamburg announced their intention to build Germany’s first import terminal for green ammonia by 2026, including facilities for the cracking of ammonia to reconvert it into hydrogen [165]. Cooperations with Chile, Uruguay, Argentina, Scotland, and Canada exist to build up the infrastructure and logistics for a future hydrogen import structure [165]. Other smaller harbours (maritime and inland) are also considering or planning electrolysers for the production of green hydrogen to supply the industry, which is often located near harbours. For example, Rostock [166], Stuttgart [167], and Bremerhaven [168] are planning for hydrogen production facilities.

11. Summary

Hydrogen can decarbonise sectors that are less easy to decarbonise than the electricity sector, as it can be a link between the electricity sector and other sectors through the technology of electrolysis.

Almost all of the currently used hydrogen is used in traditional applications, like industry and refining, and almost all hydrogen is currently produced from fossil fuels (grey, black, or brown hydrogen).

The EU has formulated targets, and Germany has set an energy strategy with even stricter goals that include hydrogen as an energy carrier for industry, transport, heating, and power. The ambitious targets formulated will lead to an increase in demand for green hydrogen, and new uses of green hydrogen will appear across all sectors.

The grey hydrogen currently used for ammonia and methanol production can be replaced by green hydrogen as soon as it is available. The demand for both is also expected to increase, as they can also be used directly as a fuel. Hydrogen also has a high potential for use in the steel and cement industry. In the transport sector, hydrogen is mainly suited for vehicles that drive long distances, like buses, heavy trucks, and vans. In order for hydrogen vehicles to penetrate the market, the total cost of ownership has to be reduced, and the availability of vehicles as well as the number of green hydrogen fueling stations has to be increased. Hydrogen can also be used in the heating sector, and trials have already demonstrated that no changes are required for state-of-the-art burners for operating with a hydrogen content of 20% blended with natural gas. Predictions of the future hydrogen demand in the heating sector in Germany vary greatly, as other heat sources may be available locally. Hydrogen can also be reconverted into electricity, thereby providing flexibility for peak demand. In total, a hydrogen demand of around 587 to 1143 TWh of hydrogen will have to be met in Germany by 2045.

For the use of hydrogen having a beneficial impact on climate, the hydrogen demand has to be met through climate-neutral production technologies, using electrolysis and electricity from renewable sources. The dominant electrolyser technologies currently are alkaline electrolysers and PEM electrolysers. In 2024, Germany had about a 150 MW of electrolyser capacity installed and has formulated the target to increase this capacity to 10 GW in 2030. This means an increase in electrolyser capacity of more than 1 GW per year will be necessary. Currently, investment decisions for projects of only about 0.3 GW have been made [118], despite the fact that plans for about 13.4 GW have been announced [117]. To achieve the target, production of electrolyser cells and production facilities must be scaled up quickly in the coming years. The electrolyser size also has to be increased, and electrolyser costs have to be reduced through R&D of the electrolysers themselves and automatization of the production processes to lower the cost of green hydrogen. The cost of green hydrogen is also strongly influenced by the electricity price, with electrolysers being able to operate as dispatchable loads for use at times of low electricity prices.

Despite the efforts to scale up local production in Germany, Germany will have to import hydrogen in the future and will not be able to cover its own demand. It therefore requires cross-border connections and international cooperation to meet its ambitious targets. Transport of hydrogen can occur in the form of compressed or cryogenic hydrogen. Pipelines and gas networks can be used for transport over short and intermediate distances. Strategies and transition scenarios include the creation of a hydrogen backbone for transport within Europe, a core hydrogen network for transport within Germany, and independent hydrogen hubs that enable local hydrogen islands and grid sections transitioning to hydrogen at an early time. Worldwide long-distance transport can happen via ships. In the future, hydrogen can be transported on ships in liquid form or converted into ammonia or hydrocarbons for transport. For large quantities and long distances, these hydrogen derivatives might be cheaper and also more energetically viable than the transport of hydrogen in its pure form.

To meet the targets of a sustainable hydrogen-based energy supply, the support for the development of hydrogen technologies has to be continued to lower their cost and increase their lifetime, reliability, and safety. In addition, a reliable hydrogen supply and hydrogen infrastructure needs to be developed, not only in Germany but in an international context within Europe as well as worldwide. This requires the industrialisation of the electrolyser industry, the diversification of supply chains, and the construction of hydrogen pipelines, hydrogen terminals in harbours, and refuelling stations for hydrogen use in transport. Without a sufficient supply and distribution infrastructure, transition to a hydrogen-based energy supply is not possible. To facilitate an international adoption of hydrogen as an energy carrier, cross-border cooperation, standards, and regulations need to be harmonised as well.